V 

L C ClUb

DEPARTMENT OF THE INTERIOR

FRANKLIN K. LANE, Secretary

UNITED STATES GEOLOGICAL SURVEY

GEORGE OTIS SMITH, Director

Professional Paper 117

THE SUNSET-MIDWAY OIL FIELD

CALIFORNIA

PART II. GEOCHEMICAL RELATIONS OF THE 

OIL, GAS, AND WATER

BY

G. SHERBURNE ROGERS

WASHINGTON

GOVERNMENT FEINTING OFFICE 

1919

DEPARTMENT OF THE INTERIOR

FRANKLIN K. LANE, Secretary

UNITED STATES GEOLOGICAL SURVEY 

GEORGE OTIS SMITH, Director

Professional Paper 117

THE SUNSET-MIDWAY OIL FIELD

CALIFORNIA

PART II. GEOCHEMICAL RELATIONS OF THE 

OIL, GAS, AND WATER

BY

G. SHERBURNE ROGERS

WASHINGTON

GOVERNMENT PRINTING OFFICE 

1919

CONTENTS.

Page.

Prefatory note................................... 1..................................-...I............'..^.. 7

Chemical and physical properties of the oil and gas................................ ^.......... i ............. 9

Introduction- ...................................................................... ^............'.... 9

Chemical and physical properties of the oil,.................-.............-........-..........:...... 9

Methods of analysis. ................................................:........: ..........-....:... 9

Constitution of California petroleum.............................^................................. 10

Commercial analyses.........................................................^..........1........ 15

Methods of testing................................................ ^........ '....:...,'. ..'....... 15

Results of tests............................................................................... 16

Gravity as an index of the properties of oil........................-.v.........;.....:.............. 22

Properties of the oil in relation to its geologic occurrence......... '. ..................... -I............ 23

Factors influencing the properties of oil..................... v.................................. 23

Influence of physical or structural conditions. ..................-......-.-.-..--. ..-:........... 23

Effects of contact with water.................... r ......................:......:.:-'............ 26

General nature of effects................................................i-:..-:-;.-........... 26

Interactions between water and hydrocarbons...................... ^... ^ :i-1-. -............. 26

Chemical action of sulphur and oxygen on petroleum. ....................:..*............... 29

Relation of sulphur content to gravity...................................... i ^............. 31

Change in properties during migration............................... *.............................. 31

Chemical character of the gas..................................................I....................... 32

Composition of natural gas....................................i ...........'...'.:................... 32

Analyses. ...............................................................^.............^.......... 33

Character of the gas in relation to its geologic occurrence. .......................i ...*............... 36

Temperature gradient-....................................................................:.:....1....... 36

General phases.................................................................v.-..-..........:. -. ;... 36

Temperature measurements..................................................................-./.."..'... 37

Factors affecting accuracy of observations .................................-.........'...... .-^......... 42

Chemical reactions affecting the geothermal gradient.............................. I.................... 43

Oil-field waters. ........................................\..............................:..^.-I........... 45

Scope of discussion..................................................................:.....'........... 45

Hydrologic relations of the field. ..........................................................''..'.*....... 45

Occurrence of the oil-field waters.................................................... J .:.............. 46

General distribution............................................................................. 46

Water sands..................................................... ..........:......:............ 46

Dry sands........................................................... .......... .--,. i.............. 47

Head or pressure.................................................... ......:'...-.'.;.:........... 48

Temperature..................................................................i................... 49

Relation to the oil. ................................................;....., - .>--fc..... I.............. 60

Analysis of water and interpretation of results........................................................ 52

Mineral constituents in water..................................................................... 52

Collection of samples. .............................................................................. 52

Chemical analysis............................................................................... 53

Constituents to be determined............................................................... 53

Statement of analysis........................................................................ 53

Reacting values............................................................................. 53

Properties of reaction........................................................................ 54

Source of analyses in this report................................................................... 56

3
4: CONTENTS.

Oil-field waters Continued. Page.

Types of oil-field waters..... ...__......__......___................................,............--..... 56

Criteria for comparison.......................................................................... 56

Distribution and significance of the constituents................................................... 56

Alkalies..................................................................................... 56

Alkaline earths............................................................................. 56

Sulphate.................................................................................... 57

Chloride.................................................................................... 57

Carbonate and bicarbonate. .................................................... .^............. 57

Bromine and iodine.......................................................................... 58

Sulphide................................................................................... ,58

Minor mineral constituents................................................................... 58

Total mineral solids...............:......................................................... 59

Petroleum constituents....................................................................... 59

General classification............................................................................ 60

Waters of the normal type........................................................................ 61

Waters of the modified type....................................................................... 62

Waters of the altered type........................................................................ 62

Origin and relations of the types................................................................. 64

Origin of the altered (sulphate-free) water...................................................... 64

Origin of the brine.......................................................................... 66

Relations of the mixed type.................................................................. 68

Variation in chloride.................................................................... 68

Variation in the properties of reaction ..........................:........-..---......-..... 70

Comparative value of the types for industrial and technologic purposes.............................. 73

Sources of water supply...................................................................... 73

Factors determining value for making steam and for domestic use............................... 74

Mineral content.......................................................................... 74

Hardness................................................................................ 74

Formation of scale....................................................................... 74

Foaming................................................................................ 75

Corrosion.............................................................:.................. 75

Water softening.............................................................................. 76

Comparison of representative waters............................!.............................- 77

Action oi oil-field waters on cement.......................................................... 78

Corrosion of well casing by waters............................................................ 79

Analyses of oil-field waters........................................................................... 80

General statement................................................................................ 80

Surface waters and shallow ground waters.........................................:.............. * . 81

Modified waters. ................................................................................ 83

Waters associated with the oil..................'..................'...,............................. 85

Brines in the central and eastern parts of the field............................................. 85

Waters of the mixed type in the western part of the field........................................ 87

Invasion of oil sands by water......................................................................... 92

General statement................................................................................ 92

Manner of invasion......................................................................"......... 93

Effects of invasion............................................................................... 94

Methods for prevention or cure.........................................,................."......... 96

General methods............................................................................ 96

Special studies.............................................................................. 97

Methods for the detection of offending wells..................................*............ 97

Methods for tracing the migration of waters................................................ 98

Use of temperature observations. ......................'..... .........-.................... 99

Use of water analyses.................................................................... 99

Index ................................................................................................. 101
ILLUSTRATIONS.

Page. 

PLATE I. Map showing rate of temperature increase with depth in different parts of the Sunset-Midway field,

based on temperature of fluid at mouth of well................................................. 40

II. Map of Sunset-Midway field showing ^location of water samples analyzed and areal distribution of the

brine and mixed types of water............................................................... 70

FIGURE 1. Diagram showing relation of gravity to percentage of hydrogen in California and other varieties of

petroleum................................................................................... 13

2. Diagram showing decrease in gravity with increase in distance from the outcrop as illustrated by

10 samples of oil from zone B................................................................. 24

3. Diagram showing relation of gravity to percentage of sulphur in 100 samples of oil from the SunsetMidway field............................................................................... 30

4. Diagram showing proportions of sulphate, carbonate and bicarbonate, and chloride^in the oil-field

waters..................................................................................... 60

5. Diagrams'showing increase in chloride and decrease in carbonate in waters with distance from the

outcrop..................................................................................... 69

6. Diagram showing change in properties of waters with distance from the outcrop.................... 71

7. Diagram showing decrease in production of an oil well in the northern part of the Midway field

caused by the invasion of the oil sand by water..............................'.................. 94

8. Diagram showing in three ways the decrease in the production of oil caused by the invasion of the

011 aand by water........................................................................... 95

5

PREFATORY NOTE.

The report on the Sunset-Midway field is published in two parts. Part I (Professional 

Paper 116), by R. W. Pack, describes the general geology of the Sunset-Midway region and 

the development and underground conditions in the productive field and discusses also the 

origin and migration of the oil. Part II (Professional Paper 117), by G. S. Rogers, contains 

analyses of the oil, gas, and oil-field waters and a discussion of their composition in relation 

to their geologic occurrence; some figures on the geothennal gradient; and a brief discussion 

of the invasion of oil sands by water.

The reader is referred to Part I for all general information regarding .the field and for 

detailed acknowledgments to those who cooperated in the field work. In addition, however, 

the author of Part II desires to express his especial appreciation of the generosity of Dr. E. A. 

Starke, who freely discussed the problems of the chemistry of oil-field waters and who contributed some of the analyses used in this report.

7

I< C.

THE SUNSET-MIDWAY OIL FIELD, CALIFORNIA.

PART II. GEOCHEMICAL RELATIONS OP THE OIL, GAS, AND WATER.

By G. SHEEBUBNE ROGEES.

CHEMICAL AND PHYSICAL PROPERTIES OF THE 

OIL AND GAS.

INTRODUCTION.

. California petroleum differs in many important respects from the varieties produced in 

other parts of the United States, and a considerable amount of chemical study has been 

devoted to it. The most refined and detailed 

studies have been made of oils from the coastal 

fields of California, but a large number of 

analyses or tests of the oil and gas from the 

Sunset-Midway field have also been made from 

time to time by different chemists. Although 

many of these analyses have already been published, it has appeared advisable to collect the 

best of them and reprint them here in order that 

the properties of the hydrocarbons may be 

studied in relation to their geologic occurrence. 

Despite the fact that the ordinary analysis of an 

oil is designed primarily for the use of the refiner and represents but poorly the geochemical 

character of the oil, it nevertheless gains in interest and significance when considered in relation to geologic conditions.

In the following pages a number of selected 

analyses or tests of the oil and gas from this field 

are given, with such descriptions of the analytical methods used as are necessary to an understanding of the results. These are followed by 

a discussion of the character of the oil and gas 

in relation to their geologic occurrence, and of 

the probable changes that they have undergone 

in the course of their migration.

CHEMICAL AND PHYSICAL PROPERTIES OF THE 

OIL.

METHODS OF ANALYSIS.

Petroleum consists of an extremely complex 

mixture of many bodies or compounds composed chiefly of carbon and hydrogen. Some

of these hydrocarbon compounds may also contain smaller quantities of oxygen, nitrogen, or 

sulphur, which have an important bearing cm 

the properties of the oil.

The simple hydrocarbon compounds may be 

separated according to the proportion of their 

hydrogen to their carbon atoms into several 

well-recognized se'ries, each of whose members 

thus has a general type formula. The so-called 

paraffin series, for example, comprises hydrocarbons having the following specific formulas: 

CH4 , CyBiQ, C3H8, C-joHia, etc. All these compounds contain two more than twice as many 

hydrogen atoms as carbon atoms, and the 

general formula for the series is therefore 

CnSjn^. Similarly the naphthene or polymethylene series (CJELjn), the acetylene series 

(CnH-tn-z), the terpene series (CJELjn-.J, and 

the benzene series, or aromatic hydrocarbons 

(CnH.sn-6) may be distinguished and certain 

members of still other series have been identified in some oils. The members of each hydro-? 

carbon series, though having the same type 

formula, differ from one another in specific 

composition and in physical properties, such as 

boiling point, specific .gravity, and index of 

refraction. Thus the first four members of the 

paraffin series, OH* to C4Hj0, are gases at ordinary temperatures; the next group, comprising 

more than a dozen, are liquids; and the most 

complex members of the series'are solids. In 

addition, the same specific formula may represent two distinct compounds or isomers, differing slightly in physical properties. Finally 

there are the oxygen, nitrogen, and sulphur 

derivatives of the hydrocarbon compounds.

Any given crude oil may be a mixture of 

scores of hydrocarbon compounds of several 

different series and of their oxygeja, nitrogen, 

and sulphur derivatives. As all these compounds differ slightly from one another in their
10 THE SUNSET-MIDWAY OIL FIELD, CALIF. PART II.

boiling points and in their behavior toward 

chemical reagents, it is possible, by extremely 

careful work, to separate many of them out. 

The preliminary separation is accomplished by 

taking advantage of the difference in boiling 

points; for example, the liquid that distills 

from an oil between 160° and 162° C. will 

probably consist largely of one hydrocarbon, 

and after repeated distillation and purification 

by reagents the compound may be obtained in a 

practically pure condition. This method, however, can be applied only to the compounds that 

boil below a certain temperature. When the 

heat is raised above this point the heavy fractions remaining in the flask begin to "crack" 

or to break down. The exact chemical constitution of very heavy tar or asphalt can therefore 

only be inferred. Furthermore, as an analysis 

of the oil by these methods is an extremely long 

and tedious process, requiring many months, it 

will readily be seen that its application to a 

large number of samples is impracticable.

A much shorter method of determining in a 

general way the composition of an oil is the 

ultimate or elemental analysis that is, the 

determination of the proportions of carbon and 

hydrogen and usually of the nitrogen, oxygen, 

and sulphur. If the oil consisted of a single 

hydrocarbon such an analysis would identify it 

precisely, but as all crude oils are mixtures the 

ultimate analysis simply indicates the general 

type or average of the hydrocarbons present. 

Such an analysis has no direct value for commercial purposes, but it sums up conveniently 

the broader differences between oils from 

different regions.

The third and by far the most common type 

of analysis is based on the fractional distillation 

of the oil. Certain arbitrary temperature 

points are selected, and the volume of liquid 

distilling over between each successive pair of 

these points is recorded. These figures correspond roughly with the proportions of gasoline, 

lamp oil, etc., that the crude oil will yield in 

refining and are therefore a rough index of the 

market value of the oil. An analysis of this 

type also constitutes a kind of epitome of the 

analysis by detailed fractionation; in other 

words, the gasoline fraction consists of several 

hydrocarbons belonging to one or more series, 

the kerosene fraction consists chiefly of several 

different hydrocarbons, and so on. If the oil 

has been first carefully studied and its general

constitution determined, some idea of the 

character of the hydrocarbons in each fraction 

can therefore be gained. On the other hand, 

such analyses, which are stated chiefly in arbitrary or conventional terms, are open to many 

criticisms. Slight differences in the character 

of the retort used or in details of technique 

may cause a very appreciable difference in 

results, and unless the methods used by the 

chemist are known the analyses have little 

comparative value.1 Although made prims rily 

for commercial purposes they indicate only 

approximately the refining value of the oil, 

partly because they test only small quantities 

and partly because they do not show definitely 

the stability of the hydrocarbons, wMch 

depends chiefly on the series to which they 

belong and which has become especially important since the introduction of the var'ous 

cracking processes. Nevertheless, such analyses, especially if made in the same laboratory, 

furnish a valuable and convenient means of 

comparing at least the relative character of 

different varieties of petroleum.

CONSTITUTION OF CALIFORNIA PETBOLBU!^.

Although the presence of petroleum in 

California was known more than 50 years ago, 

few attempts were made to study the oil 

chemically until production on a commercial 

scale was begun in Los Angeles County ^ in the 

early nineties. The marked differences in 

gravity, flash point, .color, etc., between OUfornia petroleum and the Appalachian oil exploited at that, time were early recognized, 

however, and when diesaical study was made 

possible by commercial ^production steps were 

taken to ascertain tjiejcliemical basis for ti ^se 

differences. It was ftrand, in brief, that 

whereas Pennsylvania petroleum is made -up 

chiefly of hydrocarbons of .the paraffin seres, 

the California petrdbam, is practically lacking 

in paraffins and is composed of hydrocarbons 

belonging to series lower, in..hydrogen, principally the naphthenes, terpenes, and aromatic 

compounds.,

As farbaek as 1894 8. F. Beekham published 

a general description of California oil and 

called attention especially to the nitrogen 

bases that it contains. In 1896 Frederick 

Salathe" gave the preliminary results of His

i Rittman, W. F., and D«an, E. W., The analytical distillation of 

petroleum: Bar. Mines Bull. 125, p. 8,1916.
CHEMICAL, AND PHYSICAL PROPEETIES OF THE OIL.

studies, stating that he had identified members 

of the paraffin, terpene, and aromatic series, as 

well as nitrogen bases of the pyridine and 

chinoline series. In 1897 C. F. Mabery began 

a detailed study of California petroleum, 

which was not completed until 1904. Clifford 

Richardson, in 1906, published the results of 

his studies and reviewed the previous work. 

Ultimate analyses, determinations of nitrogen 

and sulphur content, etc., have been contributed also by O'Neill, Prutzman, Alien and 

Jacobs, and others, but Mabery's work remains 

the most complete and valuable study of the 

chemical constitution, of California oil. The 

most important discussions of the character 

and chemical constitution of California oil are 

the following:

ALLEN, I. C., and JACOBS, W. A., Physical and chemical 

properties of the petroleums of the San Joaquin Valley, 

Calif.: Bur. Mines Bull. 19, 1911. Gives result of 

fractional distillations of many samples and ultimate 

analyses of five composite samples.

ALLEN, I. C., JACOBS, W. A., CROSSFIELD, A. S., and MATTHEWS, R. R., Physical and chemical properties of 

the petroleums of California: Bur. Mines Tech. Paper 

74,1914. Deals with fractional distillation and determination of commercial values of several hundred 

samples of oil from various California fields.

LENGFELD, F., and O'NEILL, E., A study of California 

petroleum: Am. Chem. Jour., vol. 15, p. 19, 1893. 

Preliminary note on the general character of California 

oils.

MABERY, C. F., Preliminary paper on the composition of 

California petroleum: Am. Chem. Jour., vol. 19, p. 

796, 1898. Describes detailed fractionation of oil 

from Ventura County.

MABERY, C. F., and HUDSON, E. J., On the composition 

of California petroleum: Am. Acad. Arts and Sci. Proc., 

vol. 36, p. 255, 1900. Describes the separation and 

identification of many hydrocarbons in samples of 

oil from Coalinga. This paper is also published in 

the Am. Chem. Jour., vol. 25, p. 253,1901.

MABERY, C. F., and HUDSON, E. J., Nitrogen compounds 

in California petroleum: Soc. Chem. Industry Jour., 

vol. 19, p. 504,1900. Discusses the character of nitrogen compounds in California oil and describes the 

separation and identification of a series of basic compounds, probably hydrochinolines.

MABERY, C. F., Hydrocarbons in Santa Barbara crude oil: 

Am. Acad. Arts and Sci. Proc., vol. 40, p. 340, 1904. 

Describes the separation and identification of seven 

hydrocarbons in sample of oil from the Summerland 

field.

MABERY, C. F., The composition of American petroleum: 

Am. Chem. Soc. Jour., vol. 28, p. 415, 1906. Sums 

up the composition of California petroleum and compares it to the oil from other fields.

O'NEILL, EDMOND, Petroleum in California: Am. Chem. 

Soc. Jour., vol. 25, p. 699, 1903. Gives a brief description of California oil, including fractional-distillation tests, determination of sulphur and nitrogen content, and ultimate analyses.

PECKHAM, S. F., Notes on the origin of bitumens: Am. 

Philos. Soc. Proc., vol. 10, p. 445, 1868. Describes 

California oil, contrasts it with Pennsylvania oil, and 

discusses the chemical basis for the differences between the two.

PECKHAM, S. F., On the nitrogen content of California 

bitumen: Am. Jour. Sci., 3d ser., vol. 48, pp. 250, 

389,1894. Discusses the general character of California petroleum with special reference to the. nitrogen 

and sulphur compounds.

PRUTZMAN, PAUL, Production and use of petroleum in 

California: California State Min. Bur. Bull. 32, p. 220, 

1904. Discusses the chemical character of California 

oil, gives a few ultimate analyses, and. many fractional-distillation tests.

PRUTZMAN, PAUL, Petroleum in southern California: California State Min. Bur. Bull. 63, 1913. Contains a 

great many commercial, analyses of southern California 

oils.

RICHARDSON, CLIFFORD, Petroleum from the Olinda field, 

Cal.: Soc. Chem. Industry Jour., vol. 19, p. 123. A 

short note on the fractionation of Olinda oil.

RICHARDSON, CLIFFORD, Petroleums of North America: 

Franklin Inst. Jour., vol. 162, pp. 57, 81, 1906. 

Gives the results of many tests of the chemical character of California petroleum and reviews most of the 

earlier work. Compares the character of California oil 

with that of the'petroleum from other fields.

SALATHB, FREDERICK, Re'sume' of original researches, analyses, and refining methods of petroleum, mainly from 

the- southern counties of California: California State 

Mineralogist Thirteenth Ann.. Rept., pp. 656-661, 

1896. A short preliminary discussion of the chemical 

character of California oil, with special reference to the 

nitrogen compounds.

Mabery studied samples of oil from a number 

of the southern California oil fields and also a 

sample from the Coalinga field. The southern 

California oils examined comprise varieties 

which closely resemble those produced in the 

Sunset-Midway field and which are probably 

very similar chemically. The Coalinga sample 

presumably represents Cretaceous oil, which 

differs from the ordinary Tertiary oil of California in being somewhat lighter in gravity and in 

containing some paraffin. A list of the hydrocarbons identified by Mabery in these oils, 

compiled from his articles already cited, is 

presented in the accompanying table. In interpreting these data it must be remembered that 

the hydrocarbons identified do not by any 

means include all the compounds present in the 

oil but only the simple hydrocarbons having 

boiling points below the temperature at which 

cracking begins. The| nitrogen and oxygen 

compounds were elimiiiated by treatment with 

reagents and were not considered.
12 THE SUBSET-MIDWAY OIL FIELD, CALIF. PABT II.

TABLE 1. Hydrocarbons in California petroleum. 

[C. F. Mabery and E. J. Hudson, analysts.]

Sample.

Well of Coalinga Oil

Co., Oil City district, 

Coalinga field. Specific gravity 0.8423,

or 36° B.

WellofPuenteOilCo.,

Specific gravity 0.892 ,

or 26.9° B.

cific gravity 0.8923, 

or 26.8° B.

Well at Scotts Hill,

Sespe district, Ventura County. Specific gravity 0.8782,

or 29.4° B.

Well at Summerland,

ty. Depth of well 245

feet. Specific gravity of oil 0.9845, or

12.2° B.

Fraction 

boiling at 

°C. 

68-70

79-81

96-98

109-110 

118-120

1 ^4 1 <lfi

137-140

150

160-161

169-170

181-191

oflft_oin

QC_QQ

118-120

160-162

168-172

iQA_onn

96-100

116-120

160-162

190-194

66-70

96-98

118-120

158-160

194-196

230-232 

244-246 

260-262

0150-155

0175-180

0190-195

0210-215

0250-255

0310-315

0340-345

Hydrocarbon.

hexamethylene . 

35.5 per cent benzol. . .

Heptamethylene. .....

54 per cent toluol. ....

60 per cent metaxylol.

T"i 4a1f~£) Tl fl fWl "t TlOTl O

TTn ^ ol/"Q n o T^Vi i Ti OTI o

Octonaphthene .......

ologue.

TTn ^ olrsi n o TiTi tVi on o

Heptamethylene.. . . . .

Hexamethylene and

hexane.

Tridekanaphthene. . . 

Tetradekanaphthene

.....do...............

.....do...............

.....do...............

.....do...............

.....do...............

Formula.

C

TT , e^iaCflHfl ......

/-< TT C7HI4......

G7H8 ...... 

G8Hie......

r 1.'8TT±110......

f\ TT ^10±120 . . - -

/I CuH^..-. TT

r* C TT 7HM......

C8Ty....

^10^20- - 

C

TT n-UjB- ....

r< TT .an,,......

C8H,e...;..

C^.... 

^11±122- - 

C6H12 and

CeH14 .

P TT c;|:::::::

r< ~lO*i20- TT - - -

CuH^e- .- - 

CuH^....

c*^^! _10 30

017H30 ....

C18H33 ....

r< CtfIL,.... w 

^aa-H-ao' - -

Boiling 

point.

°c.

96-98

"iis^L26"

134-135

150

160-161

195

91 ft

96-98

118-120

160-162

195

96-100

116-120

160-162

190-194

96-98

118-120

158-160

195

230-232 

244-246 

260-262

0150-155

0175-180

*190~105

«210-£15

®250-2S§

<*3ia-4J5

0340-345

Specific 

gravity.

0. 7413

"."7532'

.7591

.8117

.7841

.7749

.8044

.7440

.7540

.7745

804fi

.7420

.7566

.7905

.8046

.7436

.7569

.7751

.8022

,8134 

.8154 

.8171

.8621

.8808

.8919

QOOA

.9299

,9451

.9778

Index of refraction.

.......

3.4745 

1.4423

1.4681

1.470

1.4778

1.484

1.5146

Series.

Paraffin (CnH8n+3>

and naphthene 

(CnH2n) %

Benzene (CnHL.*). 

Naphthene (C Jff«B).

Do.

Benzene (0^^.

Naphthene (C^ffO.

Do.

Do.

Do.

Do.

Do.

Benzene (C^Hgn^,),

Naphthene (CnB\>n).

Do.

Do.

Do.

Do.

Naphthene (CnFTn)

and paraffin (UQ. 

TT i 

Naphffiene (CnH^ n).

Do.

Do.

Do.

 Do. 

Do. 

Do.

C TT

Do.

Terpene (GJLi^).

Do.

Do.

C

TT alL*n-$.

Do.

At 60 millimeters mercury pressure.

The table shows that the paraffin hydrocarbons, which are the main constituents of the 

Appalachian and Mid-Continent oils, are practically lacking in the California petroleum. 

The only paraffin compound identified was 

hexane, which forms a portion of the fractions 

boiling between 66° and 70° C. It is probable, 

however, that hexane and still lighter paraffins 

form a. larger proportion of the small fractions 

boiling below 66°. The fractions boiling above 

70° seem to consist entirely of members of $he 

naphthene or polymethylene series and of the 

benzene series or aromatic hydrocarbons, both.

of which are important constituents of the 

Russian petroleum. The very heavy Sunur^rland oil, however, contains no naphthen.es 

except perhaps in its lightest fractions; the 

portions, examined consist of members of unsaturated series still low«r in hydrogen. Tlie 

presence of members of the series CnH2n_^ is 

noteworthy, for thase very heavy and unstable 

hydrocarbons have been found only in certain 

foreign petroleums.

The broader differences between California 

petroleum and that from the Appalachian fieMs 

are well summarized in the following table,
CHEMICAL, AND PHYSICAJL, PROPERTIES OF THE OIL. 13

which, shows the ultimate composition of a 

series of oils ranging in gravity between 12° 

and 42° B. The first five analyses represent 

composite samples of oil from the main fields of 

San Joaquin Valley and indicate that the composition of the average oil from those fields 

varies but slightly. The next four analyses 

represent samples from several of the southern 

California fields. In a broad sense all these 

analyses indicate that California oil is fairly 

uniform in composition, and no sample differs 

markedly from the average of the nine. Analysis 10, which represents oil from the famous 

Lucas gusher of the Spindletop field, Tex., 

shows somewhat more hydrogen and a higher 

percentage of sulphur, though in general 

similar to the average of the California samples. 

Analyses 11 to 13 represent the lighter and 

higher-grade oils of the Mid-Continent and 

Appalachian fields. They differ from the 

California oils in their higher hydrogen content, 

which is due to the fact that their hydrocarbons 

belong chiefly to the paraffin series. The 

eastern oils are also lower in nitrogen and 

sulphur than the California petroleum. It is 

noteworthy, however, that despite the progressive increase in hydrogen, the percentage of 

carbon is. practically constant. With increase

in hydrogen there is supposed to be a tendency 

toward decrease in heating value, but variation 

in this property is apparently very small. The 

relation of these eastern oils to the Californian 

oil is shown graphically, in figure 1, which is

PER CNTOF. HYDROGEN 

4* W i- 

•8 »•<

•2

'•*3. 

4 5

.*

s»0 TEXA 

»7

"6

AUFORNIA 

AVERAGE

13

•

11 KANSAS

»

W.VA.

*ie OHIO

10 2Q 30 40, 50

GRAVITY, DEGREES BAUME

FIGURE L Diagram showing relation of gravity to percentage of hydrogen in California and other varieties of petroleum.

based on the decrease in gravity that accompanies increase in hydrogen.

TABLE 2. Ultimate analyses of petroleum from California and other fields.

Field.

California fields: 

1. Sunset, Kern County (composite sample) .....

2. Midway, Kern County (composite sample). . . . 

3. McKittrick, Kern County (composite sample) . 

4. Kern River, Kern County (composite sample) . 

5. Coalinga, Fresno County (composite sample).. . 

6. Puente Hills, Los Angeles County. ...........

7. Bardsdale, Ventura County. .................

8. Summerland, Santa Barbara County... . .......

9. Ventura County, (composite sample) ..........

Average ....................................

Other fields: , 

10. Spindletop, Tex............................

11. Cherryvale, Kans. .........................

12. Findlay, Hancock County, Ohio .............

13. Burning Springs, W. Va.... .. . ...............

Specific 

gravity.

0. 9705 

.9580 

.9600 

.9670 

.9505 

.8920 

.8923 

.9845 

.9120

.9430

.9130 

.8650 

.8149 

.8302

Gravity 

(°B.).

14.3 

16.1 

15.8 

14.8 

17.3 

26.9 

26.8 

12.2 

23.5

18.5

23.3 

31.8 

41.8 

38.6

Carbon.

85.64 

86.58 

86.51 

86.36 

86.37 

84.96 

84.17 

86.32 

84.00

85.66

85.03 

85.43 

84.35 

84.30

Hydrogen.

11.37 

11. Cl 

11.41 

11.27 

11.30 

11. 96 

12.15 

11.70 

12.70

11. 72j

V 12. 301 

13.07 

13. 36 

14. 10

Nitrogen.

0.84 

.74 

.58 

.74 

1.14 

1.20 

1.25 

1.25 

1.70

1.05

6.92

.13

Sulphur.

1.06 

,82 .74' 

.89 

.60 

.80 

.1.50 

.84 

.40

.85

1.75

.27

.68

Oxygen.

OL09 

».25 

0.70 

a. 74 

o.59

1.20

cl.60

Beating 

value, 

per gram.

Calari&t. 

10,233 

10,814 

10,186 

10, 312 

10,400

10, 280

10, 874

10,223

a Undetermined; probably chiefly oxygen. & Includes oxygen. « Probably includes nitrogen and sulphur.

1-5. Alien, I. C., and Jacobs, W. S., Physical and chemical properties of the petroleums of the San Joaquin Valley, 

Calif.: Bur. Mines Bull. 19, p. 28, 1911.

6-7. Mabery, C. F.. and Hudson, E. J., On the composition of California petroleum: Am. Aead.,Arts and Sci. Proc., 

voL 36, p. 255, 1900. '

8. Mabery, C. P., Hydrocarbons in Santa Barbara crude oil: Am. Acad. Arts and Sci. Proc., vol. 40, p. 340, 1904.

9. Salath4 Fred, State Mineralogist California Thirteenth Kept., p. 656, 1896.

10. Richardson, Clifford, The petroleums of North America: Franklin Inst. Jour,, voL 162, p. 113, 1906. - Calorific 

value determined on another sample of oil from same well: Redwood, Boverton, Petroleum and its products, voi 1, 

p. 208, 1906. ...

11. Bartow, Edward, and McCollum, E. V., Kansas petroleum: Kansas Acad. SciJ Trans., vol. 19, p. 58., 1903.

12. Mabery, C. P., On the composition of the Ohio and Canadian sulphur petroleums: Am. Ghent Jour., vol. 17, 

p. 727, 1895. . 13. Ste. Claire-Deville, H., Sur les proprie't&s physiques et le pouvoir caloriflque des p4troles et des huile 

mine'ralea: Compt. Rend., voL 66, p. 442, 1868; voi. 68, pp. 349, 485, 686, 1869.
14 THE SUNSET-MIDWAY OIL FIELD, CALIF. PART II.

The nature of the oxygen, sulphur, and 

nitrogen compounds in California oils has 

never been fully studied, though then* presence was recognized by the earliest investigators. Probably the commonest oxygen 

compounds are the phenols and the naphthenic acids. The latter are formed by the 

oxidation of the naphthene hydrocarbons and 

have the general formula CnH2n_2O2 . They 

have been recognized by W. E. Perdew in 

waters associated with the oil in the SunsetMidway and Coalinga fields. They are probably potent agents in the emulsification of 

the oil that is so troublesome in some localities in the California fields; and they are important also because their presence' in water 

may be regarded as an indication that the 

water has been closely associated with oil.

California petroleum contains in general a 

fairly high proportion of sulphur, though the 

nature of its compounds has apparently never 

been investigated. Salathe" 1 states that the 

sulphur is contained chiefly in the heaviest 

fractions and that most of it is transferred to 

the middle fractions during distillation in the 

form of sulphur addition products. The sulphur in California oils is easily removed in refining and is not an especially deleterious constituent as it is in some of the eastern oils. 

The sulphur content of oils from the SunsetMidway field, appears to be closely related to 

tfceir-gravity, the heaviest oils containing the 

most sulphur. (See p. 13 and fig. 3.)

California petroleum is especially noteworthy for its high nitrogen content; Mabery2 

states that some specimens examined by him 

contain 20 or 25 per cent! of nitrogen compounds. These compounds are not difficult 

to remove in refining but, being valueless in 

themselves, reduce thej value of the crude oil 

accordingly. The nitrogen bases have been 

investigated to some extent by Peckham, 

Salathe", and Mabery. Salathe" states that he 

isolated pyridin and chinoline, but Mabery 

regards the nitrogen compounds as probably 

hydrochinolines and states that they have a 

high specific gravity and a pungent odor resembling that of nicotine. The following

1 SalathiS, Frederick, op. cit., p. 658.

s Mabery, C. F., The composition of American petroleum: Am. Chem. 

Soc. Jour., voL 28, p. 415, 1906.

series of nitrogen bases have been identi%d 

by Mabery: 3

Boiling point <°C.). 

C^E17N........................... 130-140

OuHwN........................... 197-199

014H19N........................... 215-217

015H19N........................... 223-225

C18H19N........................... 243-245

C17H21N........................... 270-275

Although the details of the particular hydrocarbons identified in an oil are perhaps ,of little 

interest except to specialists, the broad conclusions for which such work forms the b«».sis 

are of interest both to the oil operator and 

to the geologist. The most striking physical 

properties of California oil are its high gravity 

and its high viscosity; its most important 

characteristics from the refiner's standpoint 

are the comparatively small proportions of 

distillate obtained below 250° C. and the instability of the crude oil when subjected to 

higher temperatures. These characteristics 

are explained by the fact that the oil is composed so largely of naphthene hydrocarbons 

and of series still poorer in hydrogen. The 

early attempts to refine California oil by 

methods which had proved successful ,?ia 

Pennsylvania were failures, and for a long 

time the oil was used chiefly as fuel. Owing 

to the comparatively small proportions of 

light paraffins or of light hydrocarbons of 

other series it contains, the gasoline yield was 

very low, and owing to the high proportions 

of naphthenes and of aromatic hydrocarbons 

the kerosene was rather unstable and buirxed 

with a smoky yellow flame. Finally, the 

unstable character of all the heavier hydrocarbons rendered them liable to decompose 

when distilled in the presence of air at high 

temperatures. These difficulties, which irere 

thus directly due to the peculiar chemical 

character of the oil itself, were later in Irrge 

measure overcome by controlling the temperature and pressure under which the distillation is conducted-and by the increased use 

of reagents in* purifying the distillates obtained. It is int§re^tit^ to note, however, 

that even now tb® gasoline produced f^om 

California oil averages about 5° Batrai6 

heavier than-gasoline of similar volatility and

* Mabery, C. F., On the nitrogen, bases in California petroleum- Soc. 

Chem. Industry Jour., vol. Id, p. 505,1900.
CHEMICAL AND PHYSICAL PEOPEETIES OF THE OIL.

working efficiency derived from Appalachian 

oils. More recently it has been found that 

the conditions under which decomposition of 

the heavier hydrocarbons takes place may be 

controlled by regulating the temperature and 

pressure so that gasoline or light distillate isj 

obtained as a decomposition product. Several 

processes for "cracking" or decomposing the 

heavier hydrocarbon molecules into lighter and 

more valuable ones have been commercially kn 

troduced and offer- promise of greatly increasing 

the yield of motor fuel from California oil.

The chemical composition of the oil is a matter of interest to the geologist also, for it furnishes important evidence as to the origin and 

history of the oiL For example, the 'nitrogen 

present in such noteworthy proportions in California oil is regarded as very strong* evidence of 

the derivation of the oil from organic remains, 

which is completely in accord with the geologic 

evidence on the origin of the oil. (See Prof. 

Paper 116.) The fact that California petroleum consists chiefly of naphthenes, terpenes, 

aromatic hydrocarbons, and other series poor in 

hydrogen indicates its relationship with the 

oils of southern Texas and Louisiana, of Mexico, 

of Russia, etc.,"rather*than with the light paraffin oils of the Appalachian and Mid-Continent 

fields. This relationship is corroborated - by 

the geologic evidence, for the California and 

similar oils are chiefly of Tertiary age, whereas 

the Appalachian and Mid-Continent oils are of 

Paleozoic age. David White * has recently suggested that the ultimate criterion is not strictly i 

the age but rather the degree of regional metamorphism to which the containing rocks have 

been subjected. He has shown that the light 

paraffin oils occur only in regions in which the 

coal has reached the bituminous stage of altera-i 

tion, whereas the heavy asphaltic oils are found 

where the coal is still in the stage of lignite. 

His compilations indicate a remarkably close j 

sympathy, regionally considered, between the 

composition and character of the organic detrital residues or coal and the gravity of the oil. 

Another factor that probably has an influence 

on the character of oil is the composition of 

the organic remains from which it was derived, 

but concerning this little is yet known.

Although considerable progress has been 

made in correlating broadly the chemical com-

> White, David, Some relations in origin between coal and petroleum: 

Washington Acad. Sci. Jour., vol. 5, pp. 189,212,1915.

15

position of an oil with, its geologic history, there 

is yet little definite information as to the reasons for the variation in the character of the 

oil from different pjurts of a single district. 

White's work throws light on the fundamental 

differences between California and Pennsylvania petroleum, but it does not explain why oil 

from the eastern part of the Sunset-Midway 

field has an averagje gravity of about 30° 

Baum6, whereas that from the western part is 

10° or more heavierJ As the constitution of 

these oils has neverj been studied, the true 

chemical basis for this difference is unknown, 

but light is shed on the subject by the many 

commercial analyses available, and the question will be considered in more detail, in the 

following pages.

COMMERCIAL, ANALYSES. 

METHODS OF TESTING.

The commercial analyses and fractional distillations whose results are given in the large 

tables below (pp. 17-21) were made according to 

standardized method^ by the Bureau of Mines, 

and a brief description^ of these methods is therefore given.2

Sampling.—The samples were collected at 

the wells by members of the Bureau of Mines. 

They were put in 1-gallon tin cans that were 

soldered tight and shipped at once to the laboratories where the analyses were made. The 

samples were taken, where possible, by allowing the oil to run fro^a the outflow of the well 

directly into the sample can; where this method 

was impracticable a <jipp©r was used.

Specific gravity.—Tfhe specific gravity was 

determined by means!of the Westphal balance.

Flash point. As niost of the crude oils examined contained at l^asfc a trace of water, they 

showed a marked tendency to froth when 

heated and gave considerable difficulty with the 

closed Pensky-Martei^s flash tester, many of 

them frothing over ai temperatures much below the flash point of the oil. For this reason, 

and to obtain comparative tests, it was considered advisable to dletermine the flash points 

of all the crude samples hi an open PenskyMartens cup carefulty screened from air currents. On account oi the frothing of the samples the temperature hjad to be increased slowly; 

a rise of 2° to 3° G. a minute was found to give

» Abstracted from Bureau of Mines Tech. Paper 74, pp. 6-10,1914.
16 THE SUNSET-MIDWAY OIL FIELD, CALIF. PART II.

good results. The gas test flame, of the size 

and form recommended for the Abel tester, was 

exposed for 1 second 1 centimeter above the 

surface of the oil at each rise of 1 ° C., beginning 

at 10° below the flash point as determined by a 

preliminary test.

Burning point.—After the flash point had 

been determined, the heating was continued 

without interruption, exactly as before, until 

the "flash" became permanent that is, until 

the oil ignited and continued to burn quietly.

Viscosity.—The viscosity was determined in 

an Engler viscosimeter at 20° C.

Calorific value.—The calorific value was determined in a Berthelot combustion bomb of 

the Dinsmore-Atwater model. The British 

thermal units per pound were calculated by 

multiplying the calories per gram by 1.8.

Sulphur.—Sulphur was determined by carefully washing out with distilled water the contents of the bomb after the combustion, the 

sulphuric acid being precipitated with barium 

chloride in the usual manner and the percentage 

of sulphur calculated.

Water.—Water was most accurately and 

most conveniently determined during the 

course of an ordinary fractionation; it distilled over in those fractions having a boiling 

point between 100° and 150° C. under atmospheric pressure and could be removed readily 

from the receivers with a micropipette and 

weighed.

Fractionation.—The fractionation, or separation of each oil into its crude commercial 

components, was made in an electrically 

heated still and was conducted as follows: 200 

grams of the .sample of oil was weighed into a 

£-liter flask. The flask was then connected 

to a Liebig condenser placed vertically, and 

the distillates were collected in weighed receiving tubes placed in a Bruehl receiver.

The oil was distilled under atmospheric 

pressure at increasing temperatures up to 

325° C.j the receivers being changed at each 

increment of 25°. The temperature was then 

allowed to drop to 125° C., to keep the oil 

from boiling over when the vacuum was used, 

and the distillation was again continued under 

a vacuum of 10 to 20 millimeters mercury 

pressure till the temperature within the flask

reached 325° C. These cuts at each increment 

of 25° C. are termed collectively the "fractional distillation."

Refining.—The oils motor fuels, lamp oils, 

and lubricants were refined as follows: 250 

grams of the oil was put in a 1-liter separitory 

funnel and shaken vigorously that is, 120 to 

150 shakes a minute for 15 minutes in a 

shaking machine, four times with 10 cubic 

centimeters of concentrated sulphuric ac; d (or 

until the oil was not appreciably colored by 

this acid treatment), once with a 10 per cent 

solution of sodium carbonate to remove the 

free acids, and three or four times with water 

to remove the last traces of soda, etc. The oil 

was then dried with Glauber's salt and distilled. This refining acid treatment yielded 

a water-white, practically odorless product of 

excellent quality.

Because of their high viscosity, it is adv;<?able 

to dilute the heavier fractions (those dif tilled 

under a vacuum at temperatures above 250° 

G.) with I part of chemieally pure benzene 

before subjecting them to the acid treatment.

RESULTS OF TESTS.

The accompanying sets of tables show in 

detail the results of the examination of 64 

samples of oil; the samples being grouped 

according to the geologic zone in which the 

oil occurs. Each table consists of two parts; 

the first part gives particulars regarding the 

source of the sampif, t|te results of various 

commercial tests, an4 the percentage of rnfined 

prpducts; the seecsid part gives simply the 

results of the fractional distillation.

The analyses are taken, with certain ir edifications, from the tables published in Bureau of 

MmesBulletin 19|«}4:T0eJinicalPaper74. Many 

of the lease names ui^di^.wHch the sampler were 

listed in those puJbKcfitaons have since been 

changed, and the accompanying tables give 

the present names. In d0terjnining the geologic zone and the .depth from which the oil 

came some uncertainty may be introduced by 

the fact that the well, has been deepened or 

reperforated since th© sample was taker, but 

the zone and the depth ^howaare believed to be 

correct for the ^am^le actually analyzed, 

though they may not indicate the source oi the 

oil produced by the well at the present time.
TABIE 3-A. Physical and chemical properties of oils from zone A.

Serial No.

1 

2 

3 

4 

5 

6 

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23

Lease.

Chanslor-CanfieJd Midway Oil. ......

Midland Oilfields........... ........

Fairbanks... ..................... ...

Indian & Colonial ...................

Elkhorn... .........................

Paraffine..... .......................

Section Twenty-five.. ...............

W.T.&M...., .....................

.....do..............................

.....do....:.........................

Average, 23 samples from zone A .

ttell No.

1 

2 

1

2 

2

1 

1

1

f,

1

2 

6

8

5

\

2 

2

8

3 

2 

5 

2

4

Location.

See.8,T. 32S..E. 231.....

Sec.l6,T. 32S., B. 23E....

Sec. 22, T. 32 S., B. 23 E . . . .

Sec. 25, T. 328., B. 23 E....

.....do......................

.....do......................

.....do......................

.....do......................

Sec. 26, T. 32 S., B. 23 E . . . . 

.....do.. ... .................

.....do......................

. ....do.. .............. ......

.....do......................

Sec. 33, T. 12 N., B.24W... 

Sec. 34, T. 12 N., B. 24 W . . .

.....do!. ....................

Sec. 35, T. 12 N., B. 24 W...

8e>f> IT 11 N K 34 W

Sec.2,T. UN., B.24W....

.....do......................

.....do......................

Portion ofgeologic zone.

"Upper?"

Lower. . 

"Upper?.. 

Lower?.. 

Lower... 

All......

Upper...

Lower...

0 g 

4-3 P

k

Feet. 

1,000 

1,000

800 

1,000

1,100 

1. 100 

1 200 

1,350 

1,050 

650 

1,250 

600 

950 

1,000 

550

500 

600

600

550

1 """"

ft 

"3

July 14,1909 

.....do....... 

Oct. 21,1907 

July 14,1909 

.....do.......

July 13, 1909 

Oct. 21,1907 

July 13,1909 

.....do....... 

Oct. 21,1907 

.....do....... 

July 14,1909 

.....do....... 

Oct. 19,1910 

Oct. 16,1910 

July 13,1909 

Oct. 22,1907 

July 13,1909 

Oct. 21,1907 

July 13,1909 

Oct. 22,1907 

.....do.......

.....do.......

>>

I?Sbo

«s

fS

a 9625 

.9550 

.9880 

.9695 

.9700 

.9570 

.9645 

.9540 

.9665 

.9260 

.9560 

.96S5 

.9630 

.9654 

.9890 

.9660 

.9770 

.9660 

.9705 

.9940 

.9775 

.9665 

.9660

.9660

Gravity on Baume scale at60° F.

°B. 

15.5 

16.6 

11.7 

14.4 

14.3 

16.3 

15.2 

16.8 

14.8 

21.2 

16.4 

14.6 

16.4 

15.0 

- 14.5 

14.9 

13-3 

14.9 

14.3 

10.8 

13.2 

14.8 

14.9

14.9

Heating value.

o S 

ft

10,297 

10,368 

9,939 

10,311 

10,041 

10,369 

10,322 

10,3?9 

10,299 

10,455 

10,345 

10,321 

10,377 

10,317 

10,340 

10,321 

10,269 

10*324 

10,271 

10,129 

10,202 

10,326 

10^265

10,286

|lfi C «.T5 5 «3i&

18,535 

18,662 

17,890 

18,560 

18,074 

18^664 

18,580 

18,700 

18,538 

18,819 

18,621 

18,578 

18,679 

18,571 

18,612 

18,578 

18,484 

18,583 

18,488 

18,232 

18,364 

18,587 

18,477

19,690

Flash point (open

cup).

"C. 

96 

78 

122 

106 

115 

66 

99 

62 

95 

20 

81 

95 

85 

91 

114 

60 

107 

60 

101 

120 

124 

98 

111

93

Burning point

(open cup).

"C. 

110 

95 

138 

123 

140 

96 

116 

93 

115 

35 

102 

115 

103 

127 

142 

fS 

134 

81 

128 

144 

154 

126 

134

114

Viscosity at 20°C. (Engler scale).

256.8 

89. 1 

7.903.3 

474.2 

821.5 

182.3 

341.1 

109.6 

444.4 

12.1 

211.7 

511.0 

210.3 

220.4 

440.1 

313.7 

1,488.2 

316.0

"796.9

Sulphur.

p. a.

1.32 

.75 

1.14 

.71 

.76 

.87 

.87 

.84 

.69 

.65 

.88 

.82 

.61 

.84 

.86 

1.11 

1.14 

.76 

1.07

1.20

1.30

1.05

1.11

.92

Re

S

i

IB

P.

1

1

...
TABLE 3-B. Fractional distillation of oils from zone A.

1

GQ

1

2 

3

4

I

7 

8 

9 

10 

11 

12 

13 

14 

15 

16 

17 

18 

19 

20 

21 

22 

23

Lease.

Midland Oilfields...... ...............

W.T.&M.. .........................

Mascot................................

.....do................................

.....do................................

North American Oil Consolidated .....

Union (J. B.andB.)..., ..............

Case M. and P.. ......................

Ida May......... .....................

Standard (Monarch) .

Average, 23 samples from zone A.

Well No.

1 

2 

1

2 

2 

1 

1 

1 

2 

1

a

6

8 

5 

1 

2 

2 

8 

3 

2 

5 

2 

4

£

P.ct. 

0.4 

Tr. 

1.5

Tr. 

2.8 

.1 

Tr. 

Tr. 

Tr.

Tr. 

Tr. 

.4 

.1 

Tr. 

Tr. 

Tr. 

Tr. 

Tr. 

Tr. 

Tr. 

Tr.

Summary of distillation (unrefined products).

5 

&.

it>"

i

P.ct.

1.6

.3

1.5

1.6

s

^ 

,20

ft®

P.c*. 

14.0 

16.8 

4.5 

13.6 

5.2 

17.2 

8.6 

15.9 

12.8 

30.1 

14.8 

10.4 

18.6 

7.7

12.2 

8.1 

. 13.6 

5.5

6.5

2.8 

5.5

5.8

10.8

3&.a 

1 

"^of

 nagS

 StslP

^

P.c*. 

47.1 

49.2 

43.8 

46.2 

43,7 

43.9 

45.0 

46.5 

49.6 

36.3 

46,8 

48.9 

47.4 

47.2 

52.0 

45.3' 

45.4 

41.9 

4«.l 

44.2 

44.5 

45.7 

47.1

45-8

at

R*

 3

*

<{

P.ct. 

37.9 

34.5 

49.7 

39.6 

47.6 

36.7 

45.9 

36.6 

36.6 

30.5 

37.9 

40.3 

33.3 

44.2 

47.5 

42,0 

46.4 

43,9 

48.1 

48.4 

52.3 

48.4 

46.8

42.3

Distillation in detail.

At atmospheric pressure.

*s

o> (*.

h H 

g§ 

00 V

<u a 

f* w 

PH

Mm. 

739 

743 

739 

748 

746 

741 

'751 

738 

741 

747 

736 

750 

756 

745 

.744 

742 

739 

740 

744 

735 

734 

743 

740

742

d

S

o 4-9

£

P.ct.

0.8

.2

.04

U

§

s

P.ct.

0.8

.3

1.3

.1

0

l 

§

P.cfc 

0.3

.7

.1

1.0

.3

3.2 

.2

1.1 

.6

.8

.2 

.3

O

T

P.<*.

0.2 

1.0

- .1

1.1 

.1

.7

6.5 

.4

1.0

1.5 

.3 

.5 

.1

.3

.2 

.6

O

1

P.rt. 

0.6 

2.5 

2.6 

.7 

1.1 

2.1 

.3 

2.2 

1.7 

7.4 

2.4 

.8 

3.5 

.8

2.7 

.7 

2.5 

.5 

.7 

.2 

.3 

.5

1.6

O

f

P.rf. 

3.1 

4.5 

.4 

4.2 

.4 

6.9 

1.6 

5.0 

4.0 

45 

6.7 

4.8 

6.4 

1.1

3.0 

1.7 

3.3 

2.3 

1.5 

.5 

1.0 

1.3

2.8

0 

1

P.ct. 

9.8 

7.1 

1.5 

8.5 

3.7 

7-1 

6.6 

7.7 

7.1 

8.5 

6.1 

4.8 

7.7 

5.8

3.9 

4.8' 

6.5 

2.6 

4.3 

1.8 

4.2 

3.6

6.3

W

P.ct.

8.5 

9.4 

8.1 

9.3 

10.4 

7.1 

10.2 

8.7 

10.4 

5.0 

10.2 

9.8 

9.3 

7.8 

13.0 

7.8 

7.8 

6.2 

8.0 

6.8 

5.9 

5.6 

10.0

8.4

In vacuum.

o

o> X

J3 g

CO M

n aj

£S

dn

Mm. 

18 

18 

18 

18 

20 

18 

20 

18 

18 

14 

13 

18 

18 

21 

13 

18 

14 

18 

15 

18 

18 

18 

17

17

W

S

7

1

P.ct. 

1.5 

.6

.3

.4 

.4 

.4 

.3 

1.1 

.3 

.4

.7

.2 

.5

.3

d 

K

P.d.

4.0 

3.3 

2.0 

3.0 

1.0 

2.1

i;i

1.8 

2.5 

2.4 

2.2 

3.8 

1.4 

3.6

3.2 

1.6 

1.1 

1.1 

3.3 

3.1 

.5 

1.2

2.1

d

?

P.ct. 

5.2

5.5 

4.2 

4.4 

6.5 

4.6 

3.7 

6.1 

4.4 

4.1 

6.4 

6.7 

4.8 

4.9 

5.3 

4.2 

7.0 

5.8 

4.1 

4.2 

4.7 

4.5 

3.1

4.9

W

|

P.ct. 

6.0 

6.6 

6.2 

6.3 

4.7 

5.3 

7.4 

7.4 

7.0 

6.5 

6.6 

6.5 

6.4 

6.1 

6.2 

5.3 

6.8 

4.9 

8.4 

6.1 

5.0 

7.9 

7.5

6.3

O

5

P.

6

7

7

6

6

6

8

6

7

5

6

6

6

6

7

7

6

6

6

5

8

8

6

6
TABLE 4-A. Physical and chemical properties of oils from zone E.

Serial No.|

24 

25 

26 

27 

28 

29 

30 

31 

32 

S3 

34 

35 

36 

37 

37a 

38 

39 

40 

41 

42 

43 

44 

45 

46 

47 

48 

49 

50 

51 

52 

53 

54

Lease.

General Petroleum.... ..............

.....do..............................

Final Dome. ........................

El Camino. .........................

American Oilfields. .................

Honolulu ............................

.....do..............................

United..............................

.....do..............................

Babcoek Petroleum. . ...............

Griffith Crude... ....................

Standard............................

.....do..............................

.....do..............................

.....do..............................

.....do..............................

.....do..............................

.....do..............................

.....do..............................

.....do..............................

.....do.............................. 

Ruby...............................

Average, 32 samples from zone B .

Well No-.1

3 

1 

1 

10 

79 

1 

2

2 

5

7 

1

1

5

1

3

8

4 

1 

1 

1 

25

37

1

4

8

12 

8 

10

5 

4

1

Location.

t

See. 14, T. 318., R. 22 E.... 

Sec. 15, T.31S-, R. 22E..... 

Sec.23,T.31S.,R.22E....

Bee. 26, T. 31 S.,R.22E.... 

Sec. 36, T. 31 8., R. 22 E....

Sec. 31, T. 31 S., R. 23 E . . . . 

.....do......................

Sec.6,T.328.,R.23E.....

Sec. 23, T. 32 8., R. 23 E ....

.....do......................

Sec. 24, T. 32 8., R. 23 E .... 

.....do......................

Sec. 20, T. 32g., R. 24 E. . . .

.....do'.....................

Sec. 30, T. 32 8., R. 24 E .... 

.....do......................

Sec. 32, T. 12 N., R. 23 W . . .

Sec. 25, T. 12 N ., R. 24 W ... 

Sec. 1,T. 11N.,R. 24W.... 

....Ao.. ....................

.....do. .....................

.:... do.. ....... .............

.....do......................

.....do......................

Sec.2,T.llN.,R.24W....

.....do.. ....................

flflrf* 1 9 T 11 1ST "P 9.1 W

.....do......................

Sec. 6, T. 11. N.,R. 23 W...

Portion ofgeologic 

zone.

Lower...

(a)

..........

..........

Lower.. - 

...do....

...do....

Lower... 

Upper...

Lower. . . 

All...... 

Upper a.

Upper a.

Upper «. 

...do.....

Upper o.

Approxi mate 

depth of zone.

Feet. 

1,000 

900 

700 

1,400 

750 

1,850 

2,300 

950 

1,200 

1 250 

1,600 

1,400 

1,750 

3,000

2,150 

1,700 

1,350 

1,600 

1,950 

1,150 

1,200 

1,150

1,000 

1,000

1)100

1,100 

1,000 

1,050 

1,050 

950 

1,350

Date ofsampling.

Oct. 18,1910 

.....do....... 

.....do....... 

.....do....... 

.....do....... 

.....do....... 

.....do....... 

.....do....... 

.....do....... 

Oct. 19,1910 

July 14,1909 

.....do....... 

.....do....... 

Oct. 17,1910 

May 11,1918 

.....do....... 

.....do....... 

July 13,1909 

Oct. 16,1910 

Oct. 17,1910 

.....do....... 

.....do....... 

.....do.......

.....do....... 

.....do....... 

. ....do. ...... 

July 13,1909 

Oct. 17,1910 

.....do....... 

July 13,1909 

Oct. 22,1907 

Oct. 16,1910

>» 

'?

s»M3

(§ta 

OQ

0.9740 

.9750 

.9535 

.9940 

.9220 

.9160 

.9410 

.9125 

.9440 

.9384 

.9500 

.9295 

.9180 

.9105 

.916 

.9275 

.9480 

.9550 

.9349 

.9285 

.9553 

.9398 

.9430 

.9613 

.9515 

.9453 

.9451 

.9644 

.9700 

1.0050 

.9760 

.9211

.9458

Gravity on Baum6 scale at60°F.

°B. 

13.74 

13.59 

16.83 

10.85 

21.84 

22.84

ia?s

23.42 

18.31 

19.19 

17.37 

20.62 

22.51 

23.76 

22.8 

20.94 

17.68 

16.60 

19.75 

20.78 

16.55 

18.97 

18.46 

15.64 

17.14 

18.10 

18.13 

15.17 

14.33 

10.00 

13.44 

21.99

18.13

Heating value.

Q

10,152 

10,269 

10,354 

9,569 

10,481 

10,554 

10,483 

10, 524 

10,444 

10,434 

10,403 

10,437 

10, 467 

10,530

10,453 

10,436 

10,357 

10.408 

10,420 

10,332 

10,412 

10,380 

10, 319 

10,332 

10,372 

10,375 

10,281 

10,273

10,247 

10,444

10,030

**s

2gjg 

m*"

18,274 

18,484 

18,637 

17,224 

18,866 

18,997 

18,869 

18,943 

18,799 

18,781 

18,725 

18,787 

18,841 

18,954

18,815 

18,785 

18,643 

18,731 

18,756 

18,598 

18,742 

18684 

18,574 

18,598 

18,670 

18,675 

18,506 

18.491

18,445 

18,799

18,060

-S 

IfAib

 S

03 

S

"C. 

120 

126 

71 

135 

17 

34 

60 

10 

55 

42 

72 

15 

15 

10

29 

72 

49 

24 

33 

55 

24 

29 

66 

38 

28 

31 

75 

84 

85 

109 

9

52

Burning point

(open cup).

•c,

156 

152 

104 

187 

42 

56 

88 

35 

76 

71 

93 

30 

24 

38

54 

103 

65 

58 

58 

97 

56 

67 

105 

77 

70 

70 

115 

129 

108 

122 

40

82

Viscosity at 20°C.

(Engler scale).

884.6 

943.7 

61.8

7.1 

7.5 

27.7 

5.0 

34.4 

18.5 

47.5 

12:0 

7.5 

5.2

13.6 

49.7 

109.7 

17.8 

17.9 

103.9 

24.0 

36.3 

173.7 

63.0 

41.6 

42.6 

261.9 

543.5

7.5 

127.5

Sulphur.

P.ct. 

1.06 

.97 

.72 

1.57 

.60 

.53 

.67 

.58 

.69 

.65 

.84 

.59 

.75 

.54 

.51

.82 

.61 

.97 

.74 

.85 

.94 

.68 

.89 

.92 

1.02 

.88 

.79 

.88 

1.10

1.18 

.62

.78

Re

c

"3

£

"S

S

P.c

2

1

1

0

May include oil from zone A.
20

3

THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

*SC5 * * «1 " " M4 M4-«d I * * v-4 *w* *w4*>4 •ssoj

d fp

'0 oSS8-oOOS

'0 oSiS-<,O

'0 0OSS-oS

:o oSzz-o

•0 oSil-oO

jo ojnss8j<£

•0 oSil-oOST

jo ejnssaij;

-jaw)

'(etip

•(umttOTA ui -Q 

OS8 <4 emssead

oOOg)

•('0 oOOS i) sip d

w -Co .en 0!). dn) jetu

eo i-i eo t~- eo to o»ra o»ra oo m o • eo -^ to to oo o «; co -^ >ra to t- to i-< t

. i~ to' to ta >a to' to >ra u> ui >ra i^ ^' ^' ^' ^' ui ui ^ *£ *£ •* ^ ^ co •* ^< •<£ *£ co 06 -^< «rf

.tow • •coe<ic«ie<i^'e<ie<irti-<cir-ii-Hi-<i-!eoe<ic4e<ic4eoe<seoffiicoi-5e<i co OH : :

.to^< .too . •«« .r-iooeo

^ o oo oo o m t 1 COIM i"=oot- i"

:g coto «;««-^ t->ra•« r-<o>toi-i ^'eot-wuS'OO'^'W^'toc^irao^'t^N

" r-< co o o»n co IM « o> w co «o -* i-i oo co o to co i-i m oo r~ o to oo o oo

to i~ eo to' eo >ra t^ us "5 to >ra us i-J ^< ^< us eo eo eo co eo cico e< « .-J-^ eo

ito o>i-i i«'«j'aioocoto 1-(^(o>'*oo>aitoOt~^io«i-(Nioi« so

o «>n«5 co»t~o to '^^ tdc<ieoeococicotc'e<i-pi " "^ eo

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toioeoootoo*

o>too»<-i-icoeo IH

. 

.OOOOOOOOOOCKNiH 'lOOO *9OO * - OO *OOQOO<-4 "*

•^COCOi-H-l ; ' '. h '• N*^*^ "^ u*it^l"*T'l i4 <a! <st ci

"ON TT9AV «rii-ioo!-He<iN«t->-<i-*«r^ wwe»^<tHi>"iw«|5|jTi*Ti«ooe»ooo»Q"»!-i

i§S"tS :p inil : i : : ixf

UTW*ff Jn W "V I**' • t it*«* i o v* i

i i £ :|^

- oo a> o i-t c« eo •« >o to r» oo IN «S w ra eo eo eo eo

eo •« > 

eo eo e
TABLE 6-A.—Physical and chemical properties of oil from zone C.

Serial No.|

55 

56 

57 

58 

59 

60 

61 

62 

63 

64

Lease.

Midland Oilfields. ............ .....

Rock................................

Consolidated Mutual.... ............

California Midway ..................

.....do..............................

Average, 9 samples from zone C

|

1 

2 

1 

1 

1 

1 

1 

1 

2 

7

Location.

Sec. 12, T. 31 S., R. 22 E . . . .

Sec. 23. T. 31 S., R. 22 E . . . . 

Sec. 25, T.31S.,R.22E.....

Sec. 30, T.31 S., R. 23 E ...... 

Sec.31,T.31S.,R.23E...... 

Sec.32,T.31S..R.23E......

Sec.4,T.32S.,R.23E.......

8ec.l4,T.32S.,R.23E...... 

.....do...................... 

Sec.l6,T.32S.,R.24E......

I

"H §

Upper...

..........

Upper .. 

...do....

Approximate depth of 

zone.

Feet. 

1,750 

2,000 

2,450 

2,750 

2,000 

2,900 

2,900 

2,650 

2,900

Date ofsampling.

Oct. 18,1910 

Oct. 19,1910 

Oct. 18,1910 

.....do....... 

.....do....... 

Oct. 19,1910 

.....do....... 

.....do....... 

.....do....... 

May 11,1918

*%iIH

GQ

0.9550 

.9295 

.9300

"."8975" 

.9050 

.8915 

.9294 

.9091

.9163

•o

8 ! 

F

16.60 

20.62 

20.54

"25.'99" 

24.70 

27.04 

20.63 

24.00

22.51

Heating value.

e

73 J

C 3

IB

a 

O

10,411 

10,468 

10,504 

10,554 

10,513 

10,564 

10561 

10,464 

10,438

10,497

.S ft ""S,

•2 « 

«!f

18,740 

18,842 

18,907 

18,997 

18,923 

19,015 

19,010 

18,835 

18,788

18,895

I

o

1

93 

40 

64 

20 

10 

15 

0 

25 

18

32

f

"C. 

122 

63 

93 

35 

11 

39 

24 

76 

50

57

Viwjsity at 20° C.

(Engler scale).

93.9 

12.4 

20.2 

5.2 

3.0 

4.5 

2.8 

10.4 

5.1

17.5

f

P.et. 

0.74 

.61 

.62 

.49 

.53 

.51 

.46 

.63 

.55 

.53

.63

TABLE 6-B.—Fractional distillation of oils from zone C.

i

55 

56 

67 

5$ 

59 

60 

61 

62 

63 

04

- Lease.

Midland Oilfields.. ................

Rock.................................:

Chanslor Canfield Midway Oil

Standard.,......:.....................

.....do.................................

Average, 10 samples from zone C.

Well No.

I 

1 

1 

1 

1 

1 

1 

2 

7

S "8 

£

P.ct. 

0.1 

Tr. 

.1 

Tr. 

Tr. 

Tr. 

Tr. 

9.5 

1.1

1.1

Summary of distillation 

(unrefined products).

o

iu

1? 

ts

P.ct. 

0 

0 

0 

0 

1.5 

0 

.7 

6.1 

3.6 

25.1

3.7

8TH

42 W "So

A

P.ct. 

0.4 

18.8 

14.1 

24.4 

28.2 

26.5 

28.8 

1«.9 

25.7 

21.0

20.5

®t a

r* d * S 

*•* H *•* 5e 

jjjs J3 3 58 p"*

P.e*. 

55.8 

45.7 

48.6 

41.1 

36.8 

42.4 

41.0 

34.9 

36.4 

25.5

40.8.

e 

•i

S^A

s§ 

S*

03

.d 

O.

IB

•<

P.ct. 

43.2 

34.7 

36,8 

34.0 

33.2 

30.2 

28.3 

31.1 

30.9 

28.4

33.1

Distillation in detail.

At atmospheric pressure.

0

*& 

°l

s s

£S

fc

mm. 

746 

742 

742 

763 

742 

746 

746 

745 

753 

742

746

CJ

3 

ft 

t>

P.e*.

5.6 

2.5 

19.6

2.8

O

?

SIH

P.<*.

1.5

.7 

.5 

1.1

5.5

.9

d

|

S

P.ct.

2.3 

5.5 

.4 

4.0 

.3 

3.9 

4.9

2.1

O

?

1

P.rf.

0.2

5.8 

6.2 

4.9 

6.4 

1.0 

6.6 

5.2

3.5

O

l

i

P.et.

2.9 

.3 

6.5 

6.2 

6.2 

5.9 

3.5 

4.6 

5.8

4.2

O

?

i

p.e*.

7.1

4.3 

4.4 

4.9 

6.9 

6.1 

6.8 

6.3 

5.1

5.2

O

I

§

P.rf. 

0.4 

8.6 

9.5 

5.4 

5.4 

8.1 

6.4 

5.3 

5.3

5.4

O

?

i •

P.c*. 

11.6 

9.3

10.2 

6.4 

6.2 

8.5 

8.4 

7.2 

7.2

7.5

In v

o

® >i

g|

l4 H '

fM

fltTtt.

12 

10 

9 

20 

20 

9 

9 

21 

21 

40

17.1

O

?

1

P.e«.

1.3

4.0 

.5

O

l

S

P.ct. 

3.7 

1.7

4.0 

3.4 

2.0 

3.6 

2.4 

2.3 

2.0

2.5

O

I

P.c*. 

6.3 

5.2 

7.4 

4.4 

4.3 

4.3 

4.0 

3.2 

3.5 

5.0

4.8

P
22 THE SUNSET-MIDWAY OIL FIELD, CAMS'.'—PABT II.

In the tables headed "Fractional distillation" 

are given the-volume of the -fractions distilled 

in each 25° interval up to 325° C. at atmospheric pressure and thence, in vacuum up to 

325° C., making in all 15 "cuts." The part 

remaining in the flask undistilled is termed 

asphaltum or residue. A summary of the 

results is given at the beginning of the table by 

grouping the fractions under then* commercial 

names—motor fuel, lamp oils, lubricants, and 

asphaltum. In the tables published by the 

Bureau of Mines the term "naphthas" was 

used for the fraction distilling below 150° C., 

"lamp oils/' for the fraction between 150° and 

300° C., and "lubricants" for the fractions 

between 300° C. at atmospheric pressure and 

325° C. in.vacuum. Owing to modifications 

in commercial practice since those tables were 

published it is thought advisable to include 

the fractions up to 175° C. under the term 

"motor fuel" and those between 175° and" 

300° C. under the term "lamp oils," the terms, 

"lubricants" and "asphaltum" being used as 

before. Similarly, in the ^columns headed 

"refined products" in the first table of each 

group an amount equal to the volume of the 

fraction boiling between 150° and 175° C. 

minus the refining loss has been added to the 

figure under "motor fuel" and subtracted 

from that under "lamp oils." In most of the 

samples no distillate was obtained below 

175°, so that the figures are unaltered, and in 

the remainder the value of this fraction is very 

small. It should be recognized that these 

commercial groups have no very distinct 

limits and are always subject to modification— 

for example, the fraction boiling between 300° 

and 325° C. (atmospheric pressure) is sometimes sold as unrefined stove oil and is sometimes refined and used for medicinal purposes 

or as a very light lubricant.

GRAVITY AS AN INDEX OF THE PROFEBTIE& OF 

OIL.

Aside from the detailed determinations given 

in the foregoing tables, which should be useful 

simply as matters of reference, it is interesting 

to study the relation- between the gravity of an 

oil and its commercial characteristics. California oil from a given field is usually purchased 

by the' pipe-line .companies at prices determined by its gravity, the lowest price being 

paid for the heavy oil and the highest for the 

light oil. Gravity is doubtless the mont convenient general index of the refining quality 

of oils from a given district, but the taHes indicate that two oils of the same gravity may 

differ considerably in regard to many minor 

characteristics. Analyses 35 and 57, representing, oils of about0.9&gravniy (20.5°B<iume), 

and analyses 30 and 44, representing oils of 

about 0.94 gravity (18.8° Baum.e), illustrate 

this fact. Furthermore, not only may two 

oils of the same gravity yield different volumes 

of distillate at a given temperature, bu* these 

distillates themselves generally differ somewhat in gravity.1 These differences, ere too 

great to be due to analytical error and indicate 

slight differences in the chemical character of 

the oil. * Additional evidence of this fact is 

afforded by the close relation between the 

gravity of the oils and their sulphur conleiit, as 

shown in figure 3 (p. 30).

It is commonly supposed that the he wy oil 

produced in the western part of the fNnsetMidway field is or might be derived from the 

lighter oil by the loss of the lighter fractions 

through simple evaporation, but the forgoing 

evidence that variation in gravity is related to 

variation in chemical character casts doubt on 

this assumption. Mabery's work furnishes additional evidence, for the sample of heav7 Summerland oil consists largely of terpenes and 

series even poorer in hydrogen and could not 

have been derived by simple evaporation from 

the lighter oils composed chiefly of nap! thenes 

and aromatic hydrocarbons. It therefore seems 

probable that although variation in gravity 

may be brought about by evaporative losses it 

is in nature generally due more to difference in 

chemical composition. In other words, variation in gravity is more likely to be caused by 

chemical influences than by purely physical 

conditions.

i The gravity of the several fractions is not shown in the foregoing 

tables but was determined by Alien in his examination of similar oils 

from the CoaUnga field* See Alien, I. C., Chemical and physical properties of the petroleums of the Coalinga district: U. S. Geol. Surrey Bull. 

398, p. 264, 1910.
CHEMICAL, AND PHYSICAL PBOEEBTIES OF THE OIL.

PEOPERTIES OF THE OIL IN RELATION TO ITS 

GEOLOGIC OCCURRENCE.

FACTORS INFLUENCING THE PROPERTIES OF OIL.

Although the chemical and physical properties of oil have been extensively investigated by 

chemists and the occurrence of oil in the rocks 

has been studied by geologists, the two lines 

of work have unfortunately never been correlated. The geochemistry of petroleum, or its 

chemical relation to the reactive minerals and' 

solutions in the rocks, has received but scant 

attention. The factors influencing the properties of oil can therefore only be inferred from 

field observations of variation in gravity and 

interpreted in the light of the few physical and 

chemical data bearing on the subject.

The three producing oil zones in the SunsetMidway field are characterized by oils that 

differ appreciably in average gravity, the highest zone, A, carrying the heaviest oil, and the 

lowest zone, C, carrying the lightest. Although 

individual samples may depart widely from 

the average for the zone, and although the 

normal downward succession from heavy oil 

to light is in places reversed, the deeper zone 

in most localities carries oil perceptibly lighter 

than the upper zone. Abundant evidence of 

this is presented in the paragraphs headed 

"Character of the oil" in Part I of this report, 

and additional data are contained in the analytical tables (pp. 17-21), in which the samples are 

grouped according to the zone from which they 

were taken. The averages given in these tables 

indicate that the average gravity of the oil in 

zone A is 0.966 (14.9° Baum6); that in zone 

B 0.946 (18.1° Baum6), and that in zone C 

0.916 (22.5° Baum6). If more samples of the 

light oil from zones B and C in the deeper 

eastern part of the field were included the difference in average gravity would be considerably 

greater.

If the three producing zones represented distinct formations, the difference in the gravity 

of their oils might be due to variation in the 

composition of the organic matter from which 

the oils were derived or to difference in the 

degree of dynamic metamorphism to which 

the oils had later been subjected. The producing zones, however, are simply groups of 

sandy beds in the later Tertiary deposits, and 

the oil- they carry is believed to have been all 

derived from organic remains in the formation

underlying them. As these broader factors 

have played no part, the differentiation of the 

oil must have been effected by local conditions 

or forces either during its migration- into the 

several zones or after it had come to rest in 

them. Most of the variation probably represents the algebraic sum of the effects of several 

factors, the most important of which are the 

following:

1. Physical or structural conditions, such as 

depth beneath the surface, distance from the 

outcrop of the producing sands, position on the 

structure, faulting or fissuring in the surrounding rocks, and grain of the containing reservoir.

2. The action of chemical reagents, such as 

sulphur and oxygen, carried for the most part 

by mineralized waters.

The influence of the physical or structural 

conditions mentioned is very marked, and they 

are probably to be regarded as the chief immediate causes of variation in the gravity of the 

oil, not only as between the different zones but 

also within any one zone. The influence of 

most of these conditions has usually been 

ascribed to their action iix facilitating or preventing loss of volatile constituents by evaporation. In the writer's opinion, however, the 

explanation for much of their influence is to be 

found in the second factor, the chemical action 

of mineralized water, <whieh thus seems both 

directly and indirectly to be a potent cause of 

variation in the gravity of the oil. In the following pages the influence of physical and 

structural conditions will be analyzed and the 

chemical action of water, the importance of 

which perhaps has not hitherto been realized, 

will be pointed out.

INFLUENCE OF PHYSICAL OR STRUCTURAL CONDITIONS.

The fact that the oil in the three producing 

zones differs appreciably in average gravity is 

due partly to the fact that in each of these zones 

it is exposed to slightly different conditions. 

As stated elsewhere in this report, the three 

zones have fairly definite vertical and areal 

limits. (See Part I, PI. III.) Thus zone A is 

recognized only within a mile or so of the outcrop and extends down the dip duly to a depth 

beneath the surface of about 1,500 feet. Zone 

C, on the other hand, is recognized only in the 

deeper territory several miles from the outcrop, 

as beneath Midway Valley and the Buena Vista
24 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

Hills. The territory in which, zone B is productive overlaps that of the other two zones; 

zone B is recognized in the deep Buena Vista 

Hills territory and also in the northern part of 

the field at shallow depths and close to the outcrop. This zone thus has wider areal limits than 

the other two zones and also a greater range in 

depth, and its oil is therefore characterized by 

wider variation. Where it lies at shallow 

depth and close to the outcrop its oil is heavy 

and seems entirely similar to the normal oil of 

zone A, but in the Buena Vista Hills, where 

zones B and C are both deep and far from the 

outcrop, their oils differ very slightly.

in this locality yields oil of about 0.933 gravity 

(20° Baum6) and about 2 miles farther c'own 

the dip to the northeast yields oil as liglt as 

0.897 (26° Baum6). A similar decrease in 

gravity is well shown by analyses 43 to 51 and 

54 in Table 4-A, the gravity decreasing rr ther 

regularly down the dip away from the outcrop 

for a distance of nearly a mile and a half. This 

decrease is shown graphically in figure 2.

The decrease in gravity with increase in 

depth is naturally most apparent at relatively 

shallow depths. The most conspicuous examples are the so-called tar sands, which ir, the 

western part of the field normally occur sev22

-UJ

= 20 

CO

to

UJ

16

6000 FEET 7.000 8.000 9,000 10,000 II.OOO 12.000 I3,OOO 

APPROXIMATE DISTANCE OF WELL FROM NEAREST POINT ON OUTCROP OF PRODUCING OIL SANO

FIGUEB 2.—Diagram showing decrease in gravity with increase in distance from the outcrop as illustrated by 10 samples of oil from zone B.

Numbers refer to analyses in Table 4-A.

The chief factors causing variation in the 

gravity of oil within a given zone also seem to 

be related to distance from the outcrop and 

depth beneath the surface. Thus in zones A 

and B, which both approach close to the outcrop in different localities, a gradual increase 

in gravity with increase in proximity to the 

outcrop is commonly apparent. This increase 

is of course generally most apparent within a 

mile or so of the outcrop and culminates at the 

outcrop itself, where the oil is a heavy tar or 

asphalt. At some localities, however, tlie decrease in gravity down the dip from the outcrop 

is apparent for several miles. For example, on 

Twenty-five Hill, near the outcrop, zone A 

yields oil having a gravity of about 0.983 

(12,5° Baum&), and about 2 miles away zone A 

yields oil of about 0.966 (15° Baum4); zone B

eral hundred feet nearer the surface thar the 

productive sands and carry very heavy and 

viscous oil or tar. On Twenty-five Hill there 

is a fairly regular gradation in gravity frora the 

tar sands through the uppermost producing 

heavy-oil sands of zone A to the lighter-oil 

sands at the base of zone A. In the territory 

where the sands lie deeper decrease in gravity 

with increase in depth is generally less marked, 

though on Maricopa Flat the uppermost sand 

yields oil as heavy as 0.946 (18° Baume) ani the 

lowest sands produce oil of 0.892 gravity (27° 

Baume"). Although variation in depth or distance from the outcrop thus appears to be 

rather generally accompanied by variation in 

gravity, it must not be supposed that the 

gradation k everywhere as regular as ir the 

localities described. In some places variation
CHEMICAL AND PHYSICAL PBOPEBTIES OF THIS OIL.

in the factors mentioned has no very marked 

effect on the gravity, and on the other hand 

there are many irregularities in gravity that 

seem to be entirely unrelated to these factors.

The general increase in gravity with increasing proximity to the surface has usually been 

ascribed to the escape and loss of the lighter 

hydrocarbons. The gas and the more volatile 

constituents of the oil are supposed to have 

worked their way to the surface and escaped, 

leaving the heavier fractions behind as a kind 

of residuum. Although this process has probably been effective to some extent, it is inadequate, in the writer's opinion, to explain the 

facts. The gas pressure in the shallow zone 

near the outcrop is of course much lower 

than in the deeper territory to the east, but 

it is by no means negligible. Practically 

©very well drilled in the shallow territory has 

shown some gas; a few have produced considerable volumes of. gas, and many have 

yielded a small but constant supply for years. 

If the gas itself is not wholly lost, it is illogical 

to argue that a large proportion of the lighter 

liquid hydrocarbons, which are less mobile 

than gas, -have escaped. Moreover, underground evaporation could have little effect on 

the gravity df the oil several miles from the 

outcrop or 2,000 feet beneath the surface, 

yet the decrease in gravity may in places 

extend as far as this. Furthermore, as already 

noted, it is probable that the heavy oil has a 

different chemical constitution from the light 

oil and could not represent a residuum derived 

from it through simple evaporation. Most of 

the variation in gravity, therefore, seems to be 

a function of chemical rather than physical 

change. The most potent chemical reagent 

witii which oil is likely to come into contact is 

mineralized water, especially surface water; and 

the fact that the chances of contact are greatest near the outcrop or near the surf ace seems 

to offer the'b^st explanation of the increase 

in the gravity Of the oil in those directions.

The influence of the other structural or 

physical conditions noted above is less marked 

and less com|tnon. Fracturing or faulting 

of the containing rocks, however, is of importance in the extreme northern part of the field, 

where zone B consists chiefly of tar sands and 

zone C yields Abnormally heavy oil. The increase in gravity is probably due in part to

the escape of the more volatile hydrocarbons, 

and in part to oxidation and to contact with 

sulphate waters. How large a part the action 

of mineralized water has played in this "locality 

is doubtful, as the producing beds do not contain much water at present. Circulation of 

water across the strata must have been at first 

facilitated by the fissuring, although as the 

oil grew heavier and sealed the fissures the 

circulation would naturally become more 

nearly normal again.

The relation between the gravity of oil and 

its structural position is apparent in some 

localities, the lighter oil occurring near the 

crest of the fold. Thus, as pointed out by 

Mr. Pack (Part I, p. 154), zone C, in the CalidonRecord area, carries oil averaging about 0.892 

(27° Baume") near the crest of the United 

anticline, whereas down the dip to the west the 

average gravity of its oil is about 0.921 (22° 

Batone")', In the Buena Vista Hills, southeast 

of this locality, a similar but much smaller 

variation may be observed in the gravity of 

the zone B oil. Whether this segregation of 

the lighter oil near the crest of the fold is 

entirely due to gravitational adjustment is not 

clear. It is possible that an edge-water condition, or the presence of water in increasing 

quantity down the flanks of the folds, has to 

some extent influenced the gravity of the oil.

Within certain limits the grain of the reservoir rock appears to influence the gravity of 

the oil, shale or very fine grained sand usually 

carrying a somewhat lighter oil than the medium 

.OT coarse grained sands near by. Thus the 

"shale oil" produced by a few wells near Taft 

and by others south of Maricopa is a few 

degrees lighter than that obtained from neighboring sandy beds. This association of lighter 

oil with shale has been observed in many fields 

throughout the world, and in many areas it is 

more marked than in the Sunset-Midway field. 

The shale probably acts as a kind of filter, 

allowing only the lighter and less viscous 

portion of the oil to migrate into it. Day's 

work 1 on the fractionation of oil by diffusion 

through ifuller's earth, has shown that under 

certain conditions a true chemical separation 

is effected in this way, the heavy unsaturated 

compounds being largely removed

i Day, D. if., Gilpta, J. E., and Cram, M. P., The fraettmation of 

crude petroleiim by capillary diffusion: IT. 8. Geol. Survey Bull. 365, 

1908.
26 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

EFFECTS OF CONTACT WITH WATER. . 

GENERAL NATURE OP EFFECTS.

Although, the chemical action of mineralized 

water on oil has apparently never been scientifically studied, there is a common belief among 

practical oil men that contact with water 

increases the gravity of oil. This belief is 

partly founded on the observation, to which 

frequent reference has been made in Part I 

of this report, that wells in which water is 

troublesome usually yield slightly heavier oil 

than those in which the water has been shut 

out. This difference is of course due partly 

to the facts that oil containing a small proportion, of water is heavier than clean oil and that 

in the process of eliminating the water in 

order to test the true gravity some of the 

volatile constituents of the oil doubtless 

escape. The belief that contact with water 

''injures the gravity" of oil can. not, however, 

be wholly explained in this manner, for it is 

corroborated by many field observations.

In the Sunset-Midway field the most obvious 

example of the association of very heavy oil 

with water is afforded by the tar sands, which 

generally occur several hundred feet above 

the producing sands of zones A or B. The tar 

sands are regarded as marking the farthest 

limit of migration of the oil from the diatomaceous shale below. They are sands partly 

impregnated with a heavy viscous oil or tar 

having a gravity of 0.993 (11° Baume*) or 

heavier. The tar sands generally carry sulphur 

water, and it is now recognized that they 

should in general be treated as water sands and 

cased off. A study of the well logs indicates 

that most of the tar sands become wholly 

water-bearing farther down the dip.

Detailed study of underground conditions 

reveals the fact that certain beds in the producing zones themselves also become waterbearing down the dip. This edge-water condition has been fully described by Mr. Pack 

in Part I of this report (Professional Paper 116) 

and is illustrated in his Plates XVI, XVII, 

XXVII, XXVIII, XXIX, and XXXI. There 

is good reason to believe that the gravity of 

the oil in such sands increases as the water is 

approached, though as most wells produce a 

mixture of oil from several sands it is difficult 

to obtain data as to the gravity of the oil in a 

single sand unless it is so heavy as to be

actually tar. In some wells, however, vbi 

have penetrated an edge-water sand near the 

lower boundary of the oil body, the petroleum 

encountered is definitely reported to bo tar. 

This condition is suggested also in Plates XVI, 

XVII, and XXVII of Part I. The write*- has 

noted a similar condition in several localities 

in the Coalinga field, and it is probable that if 

more data could be obtained this marked 

increase in gravity near the water line might 

be found to be fairly widespread.

A somewhat different illustration o.f tiie 

effect of water upon oil is afforded by sands 

which though apparently not actually containing water are in close proximity to water 

sands. For example, in much of the area 

northwest of Fellows zone C is closely underlain by a water sand and the lowest bedb in 

the producing zone carry oil several dosjrees 

heavier than that in the upper beds. Similarly, in the eastern part of sec. 32, T. 3 2 K,, 

E. 23 W., an oil sand lying close above tl <* b^ 

water sand carries oil of 0.972 gravity (14° 

Baume*), though the neighboring sands both 

above and below generally yield oil of 0.927 

to 0.892 gravity (21° to 27° Baum6). It is 

reasonable to suppose that where the varHtion 

in gravity is so marked as this the oi^ and 

water sands are connected at some point and 

that the two fluids either are now in contact 

or have been at some time in the past.

It has already been pointed out th^t increase in gravity with increase in proximity to 

the outcrop or surface, though perhaps due 

partly to the escape of the volatile fractions, 

may be more reasonably explained on the 

ground that oil near the surface or outcrop .is 

most likely to come into contact with descending surface waters* So far as the field evidence 

indicates, therefore, contact with, water is 

probably the most important single cause of 

increase in the gravity Of the oil.

INTERACTIONS BETWEEN .WATER AND HYDROCARBONS.

The belief that mineralized water may exercise a chemical effect upon oil is corroborated 

by the reverse evidence—that is, the effect of 

the reaction upon the composition of the watej* 

itself. It has been shown elsewhere by the 

writer * that the waters associated with the 

oil in the San Joaquin Valley oil fields are

1 Rogers, G. 8., Chemical relations of the oil-field waters in Bar Joaquin 

Valley, Calif.: TJ. S. GeoL Survey Bull. 653,1917.
CHEMICAL AND PHYSICAL PROPERTIES OF THE OIL

almost or quite lacking in sulphate, notwithstanding the fact that the shallower waters of 

the region are characterized by a large concentration of sulphate. An equally striking feature of many of the waters associated with the 

oil is the presence of alkali carbonate, which 

is lacking in the shallow waters on the- west 

side of the valley. Between the sulphate and 

carbonate zones is a zone characterized by 

waters carrying hydrogen sulphide. Outside 

the oil fields sulphate and carbonate maintain 

the same mutual proportions to great depths 

and hydrogen sulphide waters are rare; the 

conclusion is therefore irresistible that a change 

in the composition of the oil-field waters has 

been caused directly or indirectly by constituents of the oil or gas. As sulphate is abundant 

in the shallower waters everywhere on the west 

side of the San Joaquin Valley, whereas sulphide is found only near the hydrocarbons, it 

is reasonable to suppose that the sulphide has 

been derived under special conditions through 

reduction of the sulphate.

The observation that waters associated with 

oil contain no sulphate is by no means new, for 

it was pointed out in 1874 by Bidder l that the 

waters associated with oil in the Caucasian oil 

fields contain no sulphate, and this observation 

has been amply confirmed by later workers 

there and in other fields. Hofer 3 mentions 

this widespread peculiarity of oil-field waters 

and presents a compilation of 27- analyses of 

sulphate-free water from various fields in 

Europe, Asia, and North America. It is generally supposed that the absence of sulphate is 

due to the reducing action of hydrocarbons, 

the sulphate being reduced to sulphide, which 

passes off as hydrogen sulphide, and an equivalent portion of the-oil or gas being oxidized to 

carbon dioxide or carbonate. Hofer writes 

the reaction substantially as follows:

CaSO4 +CHt =CaO+H2S+CO2 +H2O

or

CaSO4 + CH4 4- 2H2O = Ca€O3 + H2S

These .reactions, however, are hypothetic 

and have, never been definitely substantiated 

in the laboratory. It has long been known

1 Eichler, Wy Elnige vcrlaufige Mttheilungen iiber das Erdol von 

Baku: Soc. imp. nat. Moscou Ball., vol. 48, No. 4, 1874.

2 Engler, C., and Hofer, H., Das Erdol, Band 2, p. 28, 1909.

that sulphate solutiojns are decomposed 

some conditions in the presence of organic 

matter with the formation of hydrogen sut»; 

phide, but it was sh<f>wn by Meyer,3 and more 

definitely by Plauchjid,4 that this decomposition is due not to tte mere presence of dead 

organic matter but ^o the vital processes of 

microorganisms. Numerous observers have 

since studied these creatures, whose functions 

are diverse and whose importance from the 

standpoint of the g^ochemist appears to be 

considerable,5 Thus Van Delden,6 in experimenting with a species of bacteria that inhabits the estuaries \on the coast of Holland, 

finds that they liberate in 27 days 843 milligrams of hydrogen pulphide per liter, which 

represents the reduction of 1,984 milligrams of 

sulphur trioxide. Hydrogen sulphide has been 

repeatedly observed in sea water at places 

where organic matte* is abundant and where 

the circulation is slight, and has been quantitatively determined by several observers. 

Lebedinzeff 7 finds that water from a depth of 

8,290 feet in the Black Sea contains 6,550 parts 

per million of hydrogen sulphide, and Zelinsky8 

has identified in thje bottom muds of the 

Black Sea several spejcies of anaerobic bacteria 

that are very active ifr the formation of hydrogen sulphide. It is therefore well established 

that sulphate may b|e reduced by bacteria in 

the presence of orgajjiic matter, but the bearing of this process upon the reduction of sulphate in the oil-field waters is doubtful. There 

is no evidence to slow that even anaerobic 

bacteria can continue to exist in the muds 

after the muds have been covered with a 

thousand, feet or moj*e of sediments and elevated into land, yet there is reason to supaMeyer, Lothar, Chemische TJatersuchung der Thermen zu Landeck 

in der Grafschaft Glatz: Jour, prpkt. Chemie, Band 91, pp. 6-6, 1864.

* Plauchud, E., Recherches stir la formation des eaux sulfureuses 

naturelles: Compt. Rend., vol. :54, p. 235, 1877; Sur la reduction dea 

sulfates par les sulfuraires, et sur la formation des sulfures metalliques 

naturels: Idem, vol. 95, p. 1363, 1882. See also Etard, A., and Olivier, 

L., De la reduction des sulfates par les etres vivants: Idem, vol. 95, 

p. 846,1882.

s Winogradsky, Sergfus, Ueber Schwefelbacterfen: Bot. Zeitung, Nog. 

31-37,1887.

«Van Delden, A., Beitrag ZUB Kenntnis der Sulfatreduktion durch 

Bakterien: Centralbl. Bakteriologie, Band 11, Abt. 2, pp. 92-83,113-119, 

1903.

* Lebedinzeff, A., Vorltafige Mitteilung uber den chemischen TJntersuchungen des Sclrwarzen und Asowischen Meeresin Sommer 1891: Soe. 

nat. Odessa Trav., vol. 16, fasc. 2, p. 149, 1891; abstract in Roy. Oeog. 

Soe. Proc., new ser,, vol. 14, p. ^61, 1892.

s Zelinsky, N. [Sulphydric feimentation in the Black Sea]: Russ. 

Cnem. Soc. Jour., vol. 25, pp. 298--303,1894; abstract in Chem. Soci Jour, 

vol. 66, pt. 2, p. 200,1894. Andr issow, N., Physical exploration to the 

Black Sea: Roy Geog. Soc. Jour., vol. 1, p. 49,1893.
28 THE StJNSET-MIDWAY OIL FIELD, CALIF.——PART II.

pose that in some localities surf ace waters are 

percolating down to the oil zone and are being 

altered at the present time.

The belief that hydrocarbons can reduce sulphate in the absence of bacteria and at moderate temperatures has been tacitly accepted 

for many years, and few attempts have been 

made to prove it in the laboratory. The experiments of the earlier workers are discredited 

by the fact that no precautions were taken to 

exclude bacteria, and certain later attempts 

proved unsuccessful, but recently Kharitschoff l has described some simple experiments 

that seem to have been at least partly successful. He studied mixtures of equal volumes of 

10 per cent sodium sulphate solution and kerosene or benzene under different conditions of 

temperature and pressure. In three samples 

heated in the open for 420 hours at 96° C. 

some sulphide was formed, presumably through 

reduction of sulphate. A solution of magnesium sulphate mixed with kerosene and heated 

for 420 hours apparently underwent somewhat 

more reduction than the solution of sodium 

sulphate. Kharitschoff concludes from these 

experiments that the reduction of sulphate can 

be accomplished by hydrocarbons, but that 

high pressure and temperature during a long 

period of .time are necesssary to insure complete reduction.

Although the exact manner in which the 

alteration of the waters is brought about is not 

definitely known, the usual view, that it is due 

to reaction with the hydrocarbons, certainly 

explains the chief phenomena—the disappearance of the sulphate and the formation of 

sulphide and of carbonate. It should be 

recognized, however, that the reaction as 

written above, involving methane, is improbable. Methane, being itself a decomposition product, is the most inert member of the 

paraffin series, which are the most stable of all 

hydrocarbons. Certain series, poorer in hydrogen, which are abundant constituents of 

California oil, are much less stable and probably react more readily with sulphates. In 

fact, it is quite possible that certain constituents of the oil other than simple hydrocarbons 

are most active hi the reduction of the sulphate 

solutions. In any event the equation showing 

the reaction as written can be considered only

i Kharitschoff, E. V., The waters in petroleum wells: Petroleum 

Rev., vol. 29, p. 368,1913.

a condensed representation of the type of 

change that takes place, the stages in the 

decomposition of the hydrocarbons on the one 

hand and of the sulphate on the other beinf as 

yet unknown.

Economically the most important result of 

the reduction of sulphate in the oil-field waters 

is the formation of hydrogen sulphide. As 

this gas is found in many of the waters ab-we 

the oil measures and as these waters still contain some sulphate, it is probable that they 

are undergoing alteration at the present true. 

Few waters, however, carry more than 100 

parts per million of hydrogen sulphide, and 

none of the Sunset-Midway waters yet analyzed contain more than a fraction of this 

amount. As the complete reduction of 100 

parts of sulphate would yield 35 parts of hydrogen sulphide, and as all the upper waters 

carry several hundred or several thousand 

parts of sulphate, it is evident that either the 

sulphate in these waters is not all reduced or 

else the hydrogen sulphide is being removed 

from solution nearly as fast as it is being 

formed. Some of it may unite with iron to 

form iron sulphide, which is precipitated, and 

some of it may mix with the hydrocarbon 

gas, but the total quantity accounted for in 

this way is not great.

Hydrogen sulphide readily oxidizes to sulphur, probably in accordance with the equation 

2H2S+Oa = 2H2O+2S. Under more strongly 

oxidizing conditions or in the presence of certain 

bacteria the sulphur becomes thiosulphuric, 

sulphurous, and finally sulphuric acid. '"Tie 

complete reversion of hydrogen sulphide to 

sulphuric acid or sulphate is probably not 

widespread i» buried strata, but the change to 

free sulphur, which takes place even under v^ry 

feebly oxidizing conditions, must be taken 

into account. It is probable that considerable 

amounts of hydrogen sulphide are oxidized to 

sulphur and are removed by precipitation 

from the waters above the oil measures.3 As 

the strata above the oil measures have not 

been examined for sulphur this hypothesis 

can Hot be definitely proved, but commercial 

deposits of sulphur have been found near the 

south end of Sunset field, in sec. 21, T. 11 N., 

R. 23 W., in pockets and fissures in the

a The precipitation of sulphur by the oxidation of hydrogen sulphide 

is discussed in detail by Walter F. Hunt (Origin of the sulphur deposits 

•ot Sicily: Ecoa. Geology, vol. W» PP- 643-679,1915).
CHEMICAL AND PHYSICAL PROPERTIES OF THE OIL. 29

MeKittrick group, which, includes the oil 

measures in the producing field near by. 

Most of the sulphur is amorphous, but some 

of it occurs as clear yellow crystals as much 

as a quarter of an inch in diameter. A steady 

flow of hydrogen sulphide is emitted from a 

pipe which has been driven a short distance 

into the ground near one of the prospect pits. 

A very interesting feature of this sulphur, to 

which the writer's attention was first directed 

by Dr. E. A. Starke, of the Standard Oil Co., 

is its intimate mixture with hydrocarbon 

material, which seems to constitute 20 per 

cent or more of the amorphous substance. 

No oil or tar seeps are found in the immediate 

neighborhood of the sulphur deposits, but 

deposits of brea occur less than a mile away. 

Small deposits of disseminated sulphur are 

found elsewhere along the western edge of 

the Sunset-Midway field, and it seems probable 

that these accumulations have been derived 

from sulphate by the reducing action of 

hydrocarbons.

CHEMICAL ACTION OF SULPHUR, AND OXYGEN ON PETROLEUM.

It has been shown above that hydrogen 

sulphide, presumably formed through the 

reduction of sulphate by hydrocarbons, exists 

in the waters directly above the oil measures, 

and that much of this gas is probably oxidized 

to sulphur. The chemical action on the oil 

of this sulphur and also of oxygen, another 

active agent carried in solution by most 

descending surface water, will now be considered.

If paraffin or paraffin-bearing oil is digested 

with sulphur at moderate temperature it becomes black and heavy and finally passes to a 

substance resembling solid asphalt. Similarly, if a hght asphaltic oil is treated with sulphur it also becomes darker and more viscous, 

finally becoming asphalt. Under laboratory 

conditions the reaction is accompanied by the 

evolution of hydrogen sulphide, and in fact 

an old laboratory method of generating hydrogen sulphide consists in heating paraffin and 

sulphur in a retort. The smlphur atom, by 

extracting 2 atoms of hydrogen from the oil, 

causes a condensation or polymerization of the 

hydrocarbon molecule, and this change is reflected in the increase of the gravity of the oil 

itself as it approaches solid asphalt. A simple

example of change through the action of sulphur, from the polymethylene series of the 

general formula CnH3n to the heavier aromatic 

series of the general formula CJE^^, may be 

written as follows : *

Hexamethylene+sulphur — benzene+hydrogen sulphide

C6H12 4-3S -CVH,+

Although this condensation of the hydrocarbon molecule caused by the formation of 

H2S is the change of greatest geologic interest, 

under most conditions some of the sulphur 

enters into combination with certain oil constituents to form simple sulphur compounds 

or complex sulphur derivatives. As already 

stated, California petroleum contains a relatively large percentage of sulphur compounds, 

though their exact nature is unknown.

Sulphur is readily soluble in petroleum, and 

certain Texas oils contain both, hydrogen sulphide and free sulphur in solution, in addition 

to the compounds of sulphur. Apparently the 

solution of sulphur in the heavier hydrocarbons 

of petroleum is immediate, even at ordinary 

temperature, though its solubility in oil naturally varies according to the series of hydrocarbons involved. In Peckham's opinion the 

reaction between sulphur and the hydrocarbons, whereby the latter are rendered heavier 

and more asphaltic, also proceeds at ordinary 

temperature.2 Finally, according to Endemann,3 heavy hydrocarbons react with pyrite 

just as free sulphur, half of the sulphur in. the 

pyrite molecule (FeSj) being given oijf as H3S 

and the rest remaining as a lower sulphide of 

iron.

Oxygen also exercises a pronounced effect on 

petroleum, the general character of which is 

commonly known. When oil is exposed to the 

air for a long time it becomes dark, heavy, and 

viscous, and finally passes to asphalt. This 

change is due chiefly to the evaporation of the 

more volatile constituents but partly to oxidation. Thus, if hot air is passed through oil 

for several hours the oil becomes black and 

asphaltic.4 The action of oxygen is similar to

i Kohler, H., Die Chemie und Technologic der natiirlichen und 

kunstlichen Asphalte, p. 112, Braunschweig, 1904.

* Peckham, S. F. and H. E., On the sulphur content of bitumens: 

Soc. Chem. Industry Jour., vol. 16, pp. 996-997,1887.

^ Endemann, H., discussion of paper by S. F. and H. E. Peckham, 

The analysis of asphaltum: Soc. Chem. Industry Jour., vol. 16, p. 426, 

1897.

4 Jenney, W. P., On the formation of solid oxidized hydrocarbons 

resembling natural asphalts by the action of air on re.lned petroleum: 

Am. Chemist, vol. 5, p. 359,1875..
30 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PART II.

that of sulphur; some of the oxygen may be 

taken into combination with the oil to form 

complex acids or phenols, and part of it abstracts hydrogen from the hydrocarbon molecule to form water. This reaction is involved 

in the Byerly process for preparing asphalt by 

slowly distilling petroleum while passing air 

through it.1 Oxygen, like sulphur, may also 

Cause direct polymerization. Hausmann and

known of the structure of the oxygen conrv 

pounds. However, naphthenic acids, whicH 

are the oxygen derivatives of the naphthenef, 

having the general formula CnH2n_2O3, are 

known to exist in California oils. According 

to Ostrejko, 3 if Russian oil, similar to tie 

Californian, is exposed to the air, especially in 

sunlight, these acids form at ordinary temperature, with, resulting turbidity and darkening

SPECIFIC GRAVITY

I.C 

.00

.20 

.4-0

| .60

5

D 

10

a. -80

0

h

UJ 

g 1.00

UJ

a.

1.20

«

1.40

1.60 

1

>00 .990 .980 .970 .960 .950 .940 .930 .920 .910 .900 .890 .880

!>

•

• 

•

— ®-

•

•

• 

• 

•

»

4

:•'

• 

• •

•

N

•'• *

••• •

N®

• 

•

•

i ———

•

I9

w

•

'*

• • 

•

•

•

•

<f

• 

•

•„ •

1

•

•

•

1

•

•

<r

•

t

•

•

• 

•

1

•

•

• •

•

' •

>

•

0 , 12 14 16 18 20 22 , 24 26 28 a

GRAVITY, DEGREES BAUME 

FIGURE 3.— Diagram showing relation of gravity to percentage of sulphur in 100 samples of oil from the Sunset-Midway field. 

represented by small solid circles made by Bureau of Mines; the others by diBerent chemists.

Analy.'««

Pilat 2 note that a naphthene may be transformed into an aromatic hydrocarbon by the 

action of oxygen at 140° C., and suggest that 

a similar change may be accomplished underground by some such agent as manganese 

dioxide.

Oxygen is usually not determined in the 

analysis of oil, and comparatively little is

1 Mabery, 0. F., and Byerly, J. H., The artificial production of asphalt 

from petroleum: Am. Chem. Jour., vol. 18, p. 141,1896.

2 Hausmann, J., and Pilat, S., Studien iiber die Oxydation der Petrolkohlenwasserstoff e: Congres intemat. pgtrole Compt. rend. Sess. 3, 

p. 378,1907.

of the oil. Hydroxyl derivatives of the nature 

of pnenols have been found in California ard 

other oils,4 and formic" and oxalic acids are 

reported in petroleum from the Gros.ny district, 

Russia, the quantity increasing with the gravity 

of the oil.5 *

The ease with, which petroleum takes up 

oxygen naturally varies according to the pr<v

3 Ostrejko, R. A., Influence of sunlight and air on petroleum products 

(abstract): Soc. Chem. Industry Jour., vol. 28, pp. 345, 645,1896.

* Mabery, C. F., The composition of American petroleum: Am. Chftn. 

Soc. Jour., vol. 28, p. 426, 1906.

6 Schidkoff, N., Acid content of Grosny petroleum and derivatives 

(abstract): Soc. Chem. Industry Jour., vol. 18, p. 360,1899.
CHEMICAL AND PHYSICAL PROPERTIES OF THE OIL. 31

vailing series of the hydrocarbons in it. For 

example, the terpenes, which have the genera] 

formula CnH2n_4 and which are noteworthy 

constituents of some California petroleum, 

have a well-known tendency to oxidize and to 

polymerize and doubtless contribute to the 

viscosity and resinification of the heavy oils.

.REI^ATION OF SULPHUR CONTENT TO GRAVITY.

So far as the chemistry of the process is concerned there is no question as to the ability 

of sulphur and oxygen to render petroleum 

heavier and more asphaltic; and if the action 

of these agents in nature has really been widespread it is reasonable to expect that variation 

in gravity would be accompanied by variation 

in the sulphur and oxygen content of the oil, 

as shown by analysis. It is evident, however, 

that there can be no exact relation, for the, 

particular part of the sulphur or oxygen that 

contributes chiefly to increasing the gravity of 

the oil is the part given off and lost as H2S or 

BLjO; and the size of this part in relation to 

that remaining in the oil as sulphur or oxygen 

is apparently indeterminate. In other words, 

only the traces of the reactive substances can 

be found by analysis; the portions of those substances that have actually been effective have 

been lost. Furthermore, inasmuch as oxygen 

is not determined in the industrial analysis of 

petroleum, the data are not available for studying variation, in gravity in relation to oxygen 

content, and as all the gravity variation can 

not be ascribed to sulphur alone the relation 

between sulphur and gravity can not be uniformly exact.

In view of these considerations, the relation 

between sulphur and gravity, shown in the 

accompanying diagram (fig. 3), seems reasonably close. This diagram shows the relations 

in a hundred samples, which include all those 

analyzed by the Bureau of Mines and the few 

represented by published analyses made by 

other chemists. It appears in general that oil 

lighter than 22° Baum6 contains less than 0.6 

per cent sulphur, and that oil heavier than 14° 

Batone" contains more than 1 per cent. The 

heavy tar found above the productive oil sands 

in the western part of the field probably contains in general more than 1.5 per cent of 

sulphur. There are a few samples, however, 

in. which the relation between sulphur and 

gravity departs more or less widely from the

average. It is not unreasonable to suppose 

that these departures represent variation in 

the unknown factor, that is, the oxygen content. 

Heavy oils abnormally low in sulphur may owe 

their high gravity to excessive oxidation, and 

light oils that seem abnormally high in sulphur 

may be free from oxygen and affected only by 

reaction with sulphur. The great majority, 

which fall within a fairly narrow zone, have 

probably been affected by both oxygen and 

sulphur.

CHANGE IN PROPERTIES DURING MIGRATION.

Although the gravity of oil is affected by 

several structural or physical conditions, it is 

evident that a most important factor, geologically as well as chemically, is contact with 

oxygenated or mineralized water. This explains not only the high gravity of the oil in 

direct contact with water or even in close 

proximity to water, but also to a large extent 

the marked increase in gravity with increase 

in proximity to the outcrop or the surface. 

As oil in the course of its migration is practically certain to encounter water, it follows 

that the gravity of the oil, within certain 

limits, increases roughly witH increase in the 

distance which the oil has migrated.

As described in Part I of this report, the 

oil in the Sunset-Midway field is believed to 

have originated in diatomaceous shale of 

Miocene age and to have migrated up into the 

Miocene or Pliocene formations which rest 

unconformably on the shale. The basal sandy 

beds of these formations probably constituted 

the main avenue of migration, the oil working 

through these beds until it reached the surface. At the outcrop, through evaporation 

and oxidation and in some degree through 

the action of sulphate waters; the oil became 

changed to tar or asphalt and sealed the 

avenue of escape. Further movement in this 

direction being cut off, the oil that followed 

presumably migrated from the general sandy 

zone into the individual sands that extend out 

from it in angular unconformity. These sands 

constitute the reservoirs from which the bulk 

of the oil is now obtained.

From what has already been shown it is 

evident that oil which migrates, being more 

likely to encounter reactive substances (and perhaps fresh supplies of them), is likely to become 

altered in the course of its migration. It is
32 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

evident, however, that the action of oxygen, 

sulphur, or other agents on the oil will be more 

or less localized, because ordinarily the quantity of these substances available is small 

compared with that of the, petroleum. The 

oil that is the first to traverse a given course 

comes into contact with reacting substances 

at their highest potential and therefore becomes changed more radically than the oil 

that follows it. If these reacting substances 

should become exhausted then oil might pass 

them unaffected. On the other hand, oil 

that moves with extreme slowness and remains a very long time in contact with reactive agents may undergo changes just as 

marked as those in oil which had previously 

moved through the channel at a more rapid 

rate. In general, however, that portion of 

the oil which migrated first or farthest will 

be the most altered.

When the oil migrated up from the diatomaceous shale into the basal sandy zone of 

the overlying beds it must have come into 

contact with the water then occupying those 

beds and displaced the water. As the beds 

were for the most part laid down beneath the 

sea it is probable that the water contained in 

them was mostly sea water, though near the 

outcrop or the surface meteoric or surface 

water had doubtless driven out the original 

sea water to some extent. Some of the later 

Tertiary beds, however, were laid down in 

lakes, and these beds were doubtless saturated 

with brackish or fresh water. Ordinary sea 

water contains 2,700 parts per million of sulphate, and the fresh or brackish surface waters 

of the west side of San Joaquin Valley carry 

from 50 to 7,000 parts, averaging perhaps 

2,500 parts. (See analyses, Tables 18 and 19, 

pp. 81-82.) On the other hand, oxygen is much 

more soluble in fresh water than in salt water.1 

Such fresh or brackish meteoric water as the 

oil may have encountered in its upward migration certainly carried more oxygen than the 

sea water entrapped in the sediments; it may 

have carried much more or much less sulphate, 

but on the average it probably carried about 

the same amount. The 2,700 parts of sulphate contained in the sea water which the 

oil first encountered was undoubtedly sufficient 

to effect alteration, especially as the oil in its

i Clarfce, F. W., The data of geochemistry,3d ed.: U. S. Geol. Survey 

Bull. 616, p. 141,1916.

slow upward migration continually encountered fresh supplies.

The time required for the reduction of a 

given quantity of sulphate by a given quanl 'ty 

of oil is unknown but is probably fairly long—~ 

that is, all the sulphate in the water encountered by the first oil to move was probably 

not reduced, and most of it remained to re^et 

with the oil that followed. The first oil, however, was doubtless the most altered; and wl <m 

this oil in its upward course reached the zone 

of surface waters and became subjected alsc to 

the action of oxygen its alteration must have 

become still more pronounced. This 

radical alteration ctdminated at the 

itself, where evaporation and atmospheric cmdation became added factors and caused the 

oil to become so viscous that movement in t^at 

direction was largely stopped. The oil tvat 

followed migrated into the sands that branch, 

off from the main sandy beds, zone A probably 

being filled first because the water to be displaced in that zone was under lower pressure., 

As the oil migrated farther and farther out ia 

zone A it became more and more altered, until 

the first oil to enter the beds had become so 

tarry and viscous that movement ceas«d. 

Zones B and C were filled with oil which, 

probably had a shorter distance to migrate 

than that entering zone A and which was accordingly less altered. Further differentiation 

was doubtless brought about later by descending surface waters, which naturally affected 

most strongly the oil in zone A and in those 

portions of all three zones lying nearest the 

outcrop. How much of the alteration of the 

oil has come about since it reached its present 

position is a matter of conjecture; but if, as 

the writer supposes, mueh of it was effected 

during migration |t is evident that none of the 

oil could have migrated very far.

CHEMICAL CHARACTEB OF THE GAS. 

COMPOSITION OF KATtTBAL GAS.

Natural gas is much more simple in chemical 

composition than oil, and its possible constituents are relatively few in number. Most gas 

is a mixture of two or more light hydrocarbons 

with small proportions of the inert grses 

nitrogen and carbon dioxide. It has long 

been known that the predominating hydrocarbons in aH natural gas are the light mem-
CHEMICAL CHARACTEK OF THE GAS. 33

bers of tlie paraffin series—chiefly methane 

and ethane—but until recently it was supposed that members of the olefin series, such 

as ethylene, are also present. Burrell and 

Oberfell i have shown, however, that the olefins 

do not occur in natural gas and ascribe the 

fact that they are often reported to the erroneous analytical methods in common use. Hydrogen and carbon monoxide are also frequently reported, but the same investigators 

state that they do not exist in natural gas. 

Oxygen is present in many samples but in 

most it is probably due to an admixture of air 

during sampling. In general, therefore, the 

constituents of natural gas are the lighter 

paraffins, carbon dioxide, and nitrogen.

The several lighter paraffins occurring in 

natural gas are not separated and identified by 

the ordinary or eudiometric method of analysis. 

The total paraffins are determined, and it is 

assumed that they consist entirely of methane 

and ethane, the proportions of which are calculated from theoretical equations. As a 

matter of fact, however, it is known that the 

next higher paraffins, propane and butane, 

are present in many gases and small quantities 

of pentane and hexane vapor in some. As all 

these hydrocarbons are of different heating 

value, illuminating power, specific gravity, and 

other properties, it is evident that the ordinary 

analysis of a gas affords only a rough basis for 

estimating its commercial value.

In general, the commercial value of natural 

gas depends chiefly on its heating power and 

on its content of gasoline vapor. Its heating 

power is determined by the relative proportions of the several hydrocarbons and of the 

carbon dioxide and nitrogen.' The heating 

value of methane at 0° C. and 760 millimeters 

p'ressure is 1,065 British thermal units, of 

ethane 1,861 British thermal units, of propane 

2,654 British thermal units, and of butane 

3,447 British thermal units; that of carbon 

dioxide and nitrogen is nil. Most natural gas 

consists chiefly of methane and therefore has a 

heating value somewhere near 1,100 British 

thermal units; the presence of ethane, propane, 

and butane increases the heating value and the 

presence of carbon dioxide and nitrogen lowers 

it. As the heating value reported by the

i Burrell, G. A., and Oberfell, G. G., Composition of the natural gas 

used in twenty-five cities: Bur. Mines Tech. Paper 109, p. 11,1915.

110973°—19——3

chemist is commonly calculated from the proportions of methane and ethane, which are 

simply assumed quantities, the figure reported 

may not agree very closely with the actual 

heating value. The illuminating power of 

natural gas, which is controlled by the same 

factors as the heating value, is generally so 

small that it is of little commercial importance. 

The value of gas for gasoline extraction 

depends on its content of the gases propane 

and butane and the vapor of the liquids pentane, 

hexane^ and heptane. By compression or 

refrigeration, or by solution in mineral oil, 

much of the propane and butane and practically all of the heavier hydrocarbons can be 

co^ensed to the liquid form, and after blending 

with heavier refinery naphtha may be used as 

motor fuel. As the relative proportions of 

these higher hydrocarbons are not determined 

in ordinary gas analysis, it is impossible by 

inspection of the analysis to estimate the value 

of the gas for gasoline extraction. The specific 

gravity of the gas is a rough index of its value 

for this purpose, though not sufficiently accurate or reliable to serve as a definite criterion. 

Determination of the proportion of the gas 

absorbed by claroline or other oil furnishes a 

better laboratory test, but the only entirely 

satisfactory method of determining the percentage of gasoline that may be extracted is an 

actual test with a small portable plant.2

ANALYSES.

The accompanying tables show the composition of 27 samples of gas from the SunsetMidway field as determined by the ordinary 

analytical methods. Many of the analyses, 

including most of those of Table 6, represent 

casing-head gas, which is directly, associated 

with the oil; others represent "dry" gas, 

occurring several hundred feet above the 

highest oil-producing zone, and still others 

represent the gas occurring in an oil zone but 

at a point where the zone carries only gas. 

Methane is the predominating constituent in 

all the samples; ethane is generally present, 

and in sample 19 it amounts to 37.5 per cent. 

As the figures for methane and ethane are 

simply calculated from the determination of

2 Burrell, G. A., and Jones, G. W., Methods of testing natural gas for 

gasoline content: Bur. Mines Tech. Paper iS7, 1916. Burrell, G. A., 

Seibert, F. M., and Oberfell, G. G., The condensation of gasoline from 

natural gas: Bur. Mines Bull. 88,1016.
34 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

total paraffins, they have no very exact value 

separately and seem to bear only a slight relation to the geologic horizon at which the gas 

occurs. Ethane, however, is usually fairly 

high in the casing-head gas, as in samples 5, 6,

7. and 19, and is generally low or absent in the 

gas occurring far above the oil, as in samples

8. 15, 25, and 27, though some samples of such 

gas contain a considerable percentage of ethane. 

Ethane is of course fairly high in the gases that 

are valuable for the condensation of gasoline, 

such as sample 19, and these gases ^are alsq 

characterized by higher specific gravity. Nearly 

all the samples contain a small percentage of 

nitrogen, some though not all of which probably 

represents admixed air. >^

The most striking feature of the funsetMidway gas is its rather high proportion of 

carbon dioxide. In seven samples from the 

western part of the field the carbon dioxide 

averages 18 per cent, and in 20 gases from the 

eastern part it averages 5.5 per cent. Accordingly the heating value of the 7 gases averages 

about 900 British thermal units, whereas that 

of the 20 averages 1,070 British thermal units, 

or about the same as that of methane. 1 Tatural 

gas from the Appalachian fields contains but 

little carbon dioxide or nitrogen and accordingly has a higher heating value; the gas used 

in the city of Cleveland, Ohio, for example, 

has a heating value of about 1,200 British 

thermal units.

TABLE 6.-—Analyses of natural gas from the western part of the Sunset-Midway field.

Oxygen (O2 ). - ........................

Methane (CH^). ......................

Ethane (CoHj • .......................

Nitrogen (Nj..... . ...................

Specific gravity (air=l). .............

1

19.7 

.0

73.8 

5.7

.8

100.0

0.78 

892

2

10.5

87.7 

.0 

1.8

100.0

934

3

20.0 

.0

74.7 

4.4 

.9

100.0

0.77 

904

4

9.8 

.0 

89.1 

.0 

1.1

100.0

0.65 

949

5

22.8

65.9 

10.7

99.4

766

6

24.2 

.0 

65.2 

9.4 

1-2

100.0

0.84 

869

7

20.0 

.0 

62.5 

16.4 

1.1

100.0

0.83 

971

a Gross heating value at 0° C. and 760 millimeters pressure, calculated in British thermal units per cubic foot. ,

1. Chanslor-Canfield Midway Oil Co. well 6, sec. 31, T. 31 S., R. 23 E. Gas associated with oil of 22° B. gravity 

chiefly in zone C. Sampled by G. S. Rogers, July, 1914; analyzed by G. A. Burrell, Bureau of Mines.

2. Hawaiian Oil Co. well 1, sec. 31, T. 31 S., R. 23 E. Sampled by I. C. Alien, July, 1909; analyzed ly G. A. 

Burrell, Bureau of Mines.

3. Hale-McLeod Oil Co. well 5, sec. 8, T. 32 S., R, 23 E. Gas associated with oil of 17° B. gravity in zone A. 

Sampled by G. S. Rogers, July, 1914; analyzed by G. A. Burrell, Bureau of Mines.

4. Indian & Colonial Oil Co. well 23, eec. 22, T. 32 S., R. 23 B. Gaaaasociated with oil of 14° B. gravity in zone A. 

Sampled by G. S. Rogers, July, 1914- analyzed by G. A. Burrell, Bureau of Mines.

5. Kern Trading &OilCo. wells in sec. 31, T. 12 N., R. 23 W. Gas associated with oil of average gravity cf 21° B. 

in zone B. Sampled and analyzed by W. E. Ferdew; authority, Kern Trading & Oil Co.

6. Topaz Oil Co. well 3, sec. 18, T. 11 N., R. 23 W. Gas associated with ."shaleoil" of 17° B. gravity in zone B, 

Sampled by G. S. Rogers, July, 1914; analyzed by G. A. Burrell, Bureau of Mines.

7. Spreckels Oil Co. well 5, sec. 32, T. 12 N., R. 23 W. Gas from bed 80 feet above producing oil sand (in zone 

B). Sampled by G. S. Rogers, July, 1914; analyzed by G. A. Burrell, Bureau of Mines. ,
CHEMICAL, CHAKACTBB OF THE GAS, 35

TABLE 7.—Analyses of natural gas from wells of the Standard OH Co. in the northern part of the Bu&ia Vista Hills, Midway

field (T. 31 8., R. 24- E.)fl

Carbon dioxide (CO2) ........

Oxygen (CU. ................

Methane (OH,). ...... .........

Ethane (C2H<j) ...............

Illuminants (chiefly C2H4) ....

Nitrogen (N2). ...............

Heating value &...-. ..........

8

0.3

.1

96.3

3.3

100.0

0.56

1,084

9

0.7

.3

94.3

.1

4.6

100.0

0.57

1,030

10

3.2

.3

92.8

.4

q Q

100.0

0.63

1,070

11

4 1

.3

86.7

6.3

.5

2.1

100.0

0.63

1,110

12

• 3.7

.2

95.1

.2

.8

100.0

0.57

1,092

13

3.6

.8

90.9

1.4

.6

2.7

100.0

0.59

1,087

14

11.7

.1

82.8

2.4

1.6

i.4

100.0

0.68

1,080

15

3.4

.1

90.5

.1

2:8

3.6

100.0

0.60

1,014

o California State Min. Bur. Bull. 69, pp. 250-251,1914.

ft Gross heating value at 0° G. and 760 millimeters pressure, calculated in British thermal units per cubic foot.

8. Well 1, sec. 22.

9. Well 2, sec. 22.

10. Well 2, sec. 26.

11. Well 3, sec. 26.

12. Well 4, sec. 26.

13. Well 5, sec. 26. 

the oil in zone B.

14. Well 7, sec. 36.

15. Well 9, sec. 36.

Gas chiefly from bed about 100 feet above top of oil zone B.

Gas from horizon of oil zone B.

Gas from horizon of oil zone B.

Gas from horizon of oil zone B.

Gas chiefly from horizon of oil zone B but probably in part from horizon of oil zone 0.

Gas chiefly from bed 250 feet above top of oil zone B but probably in part associated with

Gas probably associated with oil in zones B and G. 

Gas from bed about 200 feet above top of oil zone B.

TABLE 8.—Analyses of natural gas from the southern part of the Buena Vista Hills, Midway field (T. 3$ 8., R.

Carbon dioxide (C02) . . 

Carbon monoxide (CO).

Oxygen (02). .........

Methane (CH4). ........

Ethane (CaHJ. .......

Illuminants (chiefly 

C2IL)................

Other hydrocarbons. . . .

Hydrogen (H2 )......_.

Nitrogen (N2) .........

Specific gravity (air=l)

Heating value (British 

thermal units per 

cubic foot)...........

16

4.2 

.9

.6

86.2

7.6

.5

.0

100.0

0.66

1,073

17

7.0

.3

87.6

.2

1.2

3.7

100.0

0.65

a 966

18

7.6

.0

76.5

15.2

.7

100.0

0.71

al, 097

19

16.5

.0

42.2

37.5

3.8

100.0

0.96

al, 147

20

8.1 

1.6

.2

76.4

12.5

1.2

.0

100.0

0.72

1,076

21

6.9 

1.1

.5

76.4

14.1

1.0

.0

100.0

0.70

1,100

22

5.6

.5

1.7

85.6

5.7

.9

100. 0

0.69

1 037

23

1.6 

.3

.9

86.1

9.7

1.4

.0

100. 0

0.74

1,126

24

3.0

.7

.2

94.6

.6

q

.0

100.0

0.64

1,040

25

7.7

.7

87.5

3.6

99.5

«992

26

7.5

.1

90. 0'

1.2

.2

1.0

100.0

a 6i

al,056

27

3.2

.3

92.0

.8

3.2

.2

.3

100.0

0.61

»1, 125

a Gross heating value at 0° C. and 760 millimeters pressure.

16. Honolulu Oil Co. well 7, sec. 4. Gas about 300 feet above top of oil zone B.

17. Honolulu Oil Co. well 1, sec. 6. "Dry" gas about 200 feet above top of oil zone B. California State Min. 

Bur. Bull. 69, p. 250, 1914.

18. Honolulu Oil Co. well 5, sec. 6. "Dry" gas about 200 feet above top of oil zone B. Sampled by G. 8, 

Rogers, July, 1914; analyzed by G. A. Burrell, Bureau of Mines.

19. Honolulu Oil Co. well 7, sec. 6. "Wet" gas associated with oil of 31° B. gravity, chiefly in oil zone C. 

Sampled by G. S. Rogers, July, 1914; analyzed by G. A. Burrell, Bureau of Mines. ,

20. Honolulu Oil Co. well 5, sec. 8. Gas about 250 feet above top of oil zone B.

21. Honolulu Oil Co. well 6, sec. 8. Gas about 400 feet above top of oil zone B.

22. Honolulu Oil Co. well 7, sec. 8. Gas about 300 feet above top of oil zone B.

23. Honolulu Oil Co. well 3, sec. 10. Gas about 250 feet above top of oil zone B.

24. Honolulu Oil Co. well 4, sec. 10. Gas chiefly from horizon of oil zone C.

25. Honolulu Oil Co. well 1, sec. 14. Gas about 1,000 feet above top of oil zone B. Analyst, W. E. Perdew,

26. Standard Oil Co. well 2, sec. 16. Probably associated with oil in zone B. California State Min. Bur. Bull. 

69, p. 251, 1914.

27. Honolulu Oil Co. well 1, sec. 24. Dry gas 1,500 feet or more above horizon of oil zone B. California State 

Min. Bur. Bull. 69, p. 250, 1914.
36 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

CHARACTER OF THE GAS IN RELATION TO ITS 

GEOLOGIC OCCURRENCE.

The only constituent of the Sunset-Midway 

gas which appears to vary in relation to its 

geologic occurrence is the carbon dioxide. The 

relative proportions of methane and ethane 

have little significance; the oxygen and nitrogen, though invariably low, are generally due 

in part to admixture of air; and the carbon 

monoxide, hydrogen, and ethylene reported 

in some samples, whether actually present or 

not, are stated to occur in amounts so small 

that they are of little importance. Carbon 

dioxide, however, which occurs in unusually 

large proportions, appears to vary markedly in 

different parts of the field. In the western 

portion of the field or near the outcrop, where 

the productive sands lie at shallow depths, it is 

invariably high, whereas in the Buena Vista 

Hills territory, where the sands lie deeper, it is 

much lower. In the writer's opinion most of 

the carbon dioxide has been formed by reaction between the oil and mineralized waters, 

and this marked increase near the outcrop is 

due to the fact that the reactions have been 

more vigorous there, as already described.

According to the conventional reaction 

between sulphate and hydrocarbons, as written 

on page 27, the sulphate is reduced to sulphide 

and an equivalent portion of the hydrocarbon 

is oxidized to carbon dioxide or carbonate. 

This theory is corroborated by the fact that 

the deeper oil-field waters in a broad zone near 

the outcrop carry large amounts of carbonate, 

while those farther east have evidently undergone a chemical change in which carbonate, 

derived from some outside source, has played a 

part. Furthermore, there is almost invariably 

sufficient carbonic acid to form bicarbonate 

exclusively in the waters near the oil zones, and 

in addition many of these waters contain a 

dissolved excess of carbon dioxide. Free carbon dioxide is present also in many of the waters 

close above the oil measures, but it has-not been 

observed in the shallow surface waters, many 

of which are deficient in carbon dioxide and 

consequently contain some normal carbonate.

If the reduction of sulphate is to be ascribed 

to the action of hydrocarbons, the formation 

of carbonate is a necessary concomitant, and 

the presence of these unusual amounts of carbonate in the deeper oil-field waters is explained by this reaction. The convertional 

reaction, it is true, explains only the carbonate 

and not the excess of carbon dioxide, bnt the 

course of the reaction is unknown and it is 

quite possible that the hydrocarbons actually 

involved yield both of these end products. It 

is also possible that oxygenated waters coming 

into contact with the oil may cause direct 

oxidation of the hydrocarbons to carbon dioxide.. Whatever the exact chemical change 

may be, it is clear that the largest amounts of 

carbonate in the waters, and of carbon dioxide 

in both waters and gas, occur near the ortcrop, 

where waters can most easily come into contact 

with the oil and where the reaction would naturally be most vigorous.

Although the average carbon dioxide content 

of 20 gases from the Buena Vista Hills is only 

5.5 per cent, 2 samples contain more tl an 10 

per cent. These are not gases from beds 

above the oil measures and therefore nearest 

the surface, as perhaps might be expected, but 

are gases associated with the oil. P this 

condition is really widespread it suggests that 

the reaction between water and the hydrocarbons is initiated and perhaps carried on by reactive substances in the oil itself, and that the 

simple light paraffins of which the gas i* composed, being stable and inert, are incapable of 

reacting with the water.

TEMPERATURE GRADIENT.

GENERAL PHASES.

It is welLknown that the temperature of the 

earth increases with depth beneath the p'lrface 

at a more or less regular rate. It was formerly 

assumed that the normal increase is 1° F. for 

ev,ery 60 or 70 feet. As data have been accumulated, however, it has been found that so many 

local factors affect the rate of increagp that it 

varies widely in different localities, and no 

normal rate can yet be established. Geologic 

factors such as the structure and Ethology of 

the rocks, the proximity of recent igneous intrusions, and .the presence of minerals that are 

subject to chemical alteration evidently affect 

the gradient, as well as less obvious factors such 

as the character of the topography and the 

proximity of large bodies.of water.

Many more or less accurate measurements of 

the geothermal gradient have been made in dif-
TEMPERATURE GRADIENT. 37

ferent parts of the world, andPrestwich,1 Hofer,2 

Koenigsberger and Muhlberg,3 Tanasescu,4 aad 

others have compared them and have attempted to define some of the factors that 

cause variation. It is interesting to note that 

Koenigsberger and Miilhberg, after studying 

and correcting the measurements, conclude that 

the geothermal gradient is abnormally high 5 

in oil fields and that temperature measurements may therefore be used in prospecting 

for oil. Their conclusions have not been generally accepted, owing to the facts that the 

data are very incomplete and that although 

the average of the known oil-field gradients is 

somewhat higher than that of gradients in other 

regions, .there is a wide variation between gradients in different oil fields. Accordingly, the 

writer, in the hope of gaining an approximate 

idea of the gradient in the Sunset-Midway field., 

measured the temperature of the fluid produced 

by 130 oil and water wells. Measurements of 

this type are affected by many incidental 

factors and have little absolute value, but they 

are of considerable interest as showing a wide 

but fairly regular variation within the limits of 

a single field. To some extent they support the 

contention that oil-field gradients are unusually 

high; and in connection with the corroborative 

evidence already presented they help to explain 

this condition. The figures are therefore given 

in the following pages, with a brief discussion 

of the factors that have probably caused the 

wide variation between individual measurements, and also the general steepness of the. 

average as compared with that in other regions.

TEMPERATURE MEASUREMENTS.

In the following tables are given the temperature of the fluid produced by 130 wells. The

i Prestwieh, J., On underground temperatures: Roy. Soc. London 

Proc., vol. 41, pp. 1-116,1886; On underground temperatures: Collected 

papers on some controverted questions in geology, pp. 166-279, published 

separately, London, 1895.

* Hofer, Hans, The temperature in o regions (translation by C. W. 

Washburne): Econ. Geology, vol. 7, p. 636, 1912. Also Engler-HSfer, 

Das Erdol, Band 2, p. 225,1909.

a Koenigsberger, Joh., Normale und anonnale Werte der geothermischen Tiefenstufe: Centralbl. Mineralogie Jahrbuch, 1905, pp. 673- 

679. Koenigsberger, Joh., and Muhlberg, Max, On. the measurements 

of the increase of temperature in bore holes: Inst. Min. Eng. (England) 

Trans., vol. 39, pp. 617-644, 1910; Uber Messungen der geothermischen 

Tiefenstufe: Neues Jahrb., Beilage Band 31, pp. 107-157,1911.

* Tanasescu, I., Etudes pre'limuraires sur le regime thennlque: Inst. 

Geol. Romanei Annarul, vol. 5, fasc. la, p. Ill, 1912.

6 Although the geothermal gradient should strictly be stated in units 

of temperature per unit of depth, it is customary to use the reciprocal 

statement, units of depth per unit of temperature—for example, feet per 

degree. A high or steep gradient is represented by a small number of 

feet per degree, such as 25, whereas a low gradient is represented by a 

large number, such as 100.

measurements were made with an ordinary 

standardized mercury thermometer. The temperature of the fluid was taken where the lead 

line discharged into the sump or tank; at most 

of the wells selected this point was within 20 

feet of the mouth of the well, and at only one 

well was it more than 40 feet away. At the^ 

same time the method of operation of the well 

was noted and also the character of the oil— 

whether it was rich or poor in gas and whether 

or not accompanied by sand or by water.

The depth of the oil or water sand given in 

the tables is the mean depth of the producing 

zone. In some wells the producing zone is 

only 20 feet or so thick, but in others it is 200 

feet thick, and there is usually no way of telling which part of the zone contributes the greatest part of the product. In the few wells 

which draw their product from, several distinct 

sands scattered through a vertical range of several hundred feet the mean depth given is 

marked with a ± sign.

The mean annual air temperature of the 

district is 65° F.6 Authorities differ as to 

whether the mean annual ground temperature 

at the surface is the same or greater or less than 

the mean annual air temperature, but the sim7 

plest assumption is that it is the same. Accordingly, the rate of increase 'with depth was 

computed by simply dividing the mean depth 

fn feet of the producing zone by {the temperature 

in degrees Fahrenheit of the fluid minus 65.

Inasmuch as the gradient appears to vary 

with distance from, the outcrop of the producing sands the measurements ar$ grouped in the 

following tables hi order to bring out this variation. Thus Table 9 shows the gradient in 

the western pftrt of the field, or within 2 miles 

of the outcrop; Table 10, the gradient in the 

central part, more than 2 miles and less than 4 

miles from the outcrop; and Table 11, the gradient in the eastern part of the field, more than 

4 miles from the outcrop. It should be reiterated that these determinations of the gradient, 

which are based simply on the temperature of 

the fluid at the mouth of the well, are subject 

to considerable error and have little absolute 

value. They should be considered in connection with the discussion of the iactors influencing the accuracy of the observations given on 

|>ages 38-40.

«Climatological data for the United States, vol. 3, No. 13, U. B. 

t»ept. Agr. Weather Bureau, 1917.
38 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

TABLE 9.—Geoikermal gradient in the western part of the Sunset-Midway field 

[Based on temperature of oil produced by wells within 2 miles of the outcrop of the lowest producing oil sand.]

No.

1

2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21

22

23

24

25

26

27

28

29

30

31

32

S3

34

35

36

37

38

39

40

41

42

43

44

45

46

47

48

49 

50

51 

52 

53 

54 

55 

56 

57 

58 

59 

60 

61

62

Sec.

15

15

15

15

15

14

14

23

23

23

23 

23

23

23

35

36

35

36

36

36

30

31

31

1

1

1

1

1

6

6

6

5

5

8

17

21

23

26

26

26

23

23

23

24

26

26

26

26

26 

35

26 

26 

26 

25

25 

25 

25

25 

25 

25 

25

2

Location

T.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S. 

31 S.

31 S.

31 S

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

31 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S

32 S

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S. 

32 S.

32 S. 

32 S. 

32 S. 

32 S. 

32 S. 

32 S. 

328. 

32 S. 

32 S. 

32 S. 

32 S.

11 N.

WeL

R.

22 E.

22 E.

22 E.

22 E.

22 E.

22 E.

22 E.

22 E.

22 E

22 E.

22 E. 

22 E.

22 E.

22 E

22 E.

22 E.

22 E.

22 E.

22 E.

22 E.

23 E.

23 E.

23 E.

22 E.

22 E.

22 E.

22 E.

22 E.

23 E.

23 E.

23 E.

23 E.

23 E

23 E

23 E.

23 E.

32 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E.

23 E. 

23 E.

23 E. 

23 E. 

23 E. 

23 E. 

23 E. 

23 E. 

23 E. 

23 E. 

23 E. 

23 E. 

23 E.

24 W.

1.

.....do. ...'.........

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do. ............

.....do............. 

.....do.............

.....do.............

.....do..............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.... .do... ..........

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do...............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do.............

.....do..............

.....do.............

,... .do. ............ 

.....do.............

.....do............. 

.....do............. 

.....do............. 

.....do............. 

... ..do. ........ ...i 

.....do............. 

.....do............. 

.....do............. 

.....do............. 

.....do............. 

.....do.............

.....do.............

Mean depth 

of 

oil sand.

Feet. 

1,000±

750

900

900

880

1,475

1,200

1,500

1,630

1.450

1,600 

1; 700

1,800

1,840

1,250

i;300

1,080

1,050

1,860

1,750±

2,860

1,940

1,900

510

650

760

960

910

890

2,100

1,870

2,200

2,210

990

840

1,050

950

850

1,000

900

1,200

1,250

1, 230 ±

1,800

1,070

975

1,080

1,250

1,150 

860±

1,080 

1,060 

1,100 

1,220 

1,350 

1.400 

1^380 

1,350 

1.350 

1, 450 

1,450

520

perature

0 F. 

95

85

93

88

89

93

95

89

94

92

88 

90

93

91

97

97

98

94

95

90

88

102

89

98

84

90

88

86

88

90

98

94

95

88

98

84

101

93

91

84

89

89

84

92

93

90

90

96

90 

95

94 

97 

93 

86 

92 

91 

97 

92 

97 

101 

93

85

Depth per

degree of 

increase 

in temperature.

?Feet. 

' 33.3

37.5

32.3

39.3

36.8

52.8

40.0

62.6

56.3

53.7

69.6 

68.0

64.4

70.8

39.1

40.7

32.7

36.2

62.0

70.1

124.5

52.2

79.2

15.5

34.2

30.5

41.7

43.3

38.7

84.0

56.7

75.9

. 73.7

43.0

25.5

55.2

26.4

80.4

38.5

47.4

50.0

52.0

64.8

66.6

38.3

39.0

43.2

40.3

46.0

28.7

37.3 

33.1 

39.3 

58.0 

50.0 

53.8 

43.2 

50.0 

42.2 

40.3 

51.8

26.0

Remarks.

Makes much sand.

Makes considerable sand.

Do.

Makes much sand. Oil very h^avy.

Makes considerable Band.

Do.

Makes some sand.

Makes much Band.

Makes very little sand.

Makes much sand.

Makes very little sand. Oil partly

emulsion.

Temperature measured in tank; probably too low. 

Makes little sand. Oil gassy.

Makes considerable sand.

Makes little sand.

Makes considerable sand.

Do.

Makes much sand.

Makes some sand.

Makes considerable sand.

Do.

Makes much sand.

Makes no sand

Makes some sand

Makes considerable sand.

Makes much sand.

Makes considerable sand.

Makes much sand.

Do.

Do.

Makes much sand. Oil gassy.

Makes considerable gas. Ver^ little

sand. 

Makes some gas. Very little s*md . Makes no sand.

Makes very little gas. No sani.

Makes considerable sand.

Do.

Do. vFluid 75 per cent water.

Makes some sand. Considerable gas. 

Makes considerable sand. O;l very

heavy. 

Makes much sand. 

Do. 

Makes some sand. Oil gassy. 

Oil gassy. 

Makes some sand.

Do. 

Fluid 25 per cent water. Sona e sand . 

Fluid 75 per cent water. Little sand. 

Fluid 75 per cent water. Some sand. 

Makes some sand.

Makes considerable sand.
TEMPERATURE GRADIENT. 

TABLE 9.—Geoihermal gradient in the western part of the Sunset-Midway field—Continued.

39

No.

63 

64 

65 

66 

67 

68 

69 

70 

71 

72 

73 

74

Ave]

Well.

Lopation.

Sec.

2 

2 

2 

1 

36 

2 

1 

1 

1 

12 

12 

12

rage, 7^

T.

UN.

11 N. UN.

UN. 

12 N. 

UN. 

UN. 

UN. 

UN. 

11 N. 

UN. 

UN.

measure

R.

24 W. 

24 W. 

24 W. 

24 W. 

24 W. 

24 W. 

24 W. 

•24W. 

24 W. 

24 W. 

24 W. 

24 W.

ments

How operated.

Compressed air. . . . .

Pumped............

.....do. ............

.....do.............

.....do.............

.....do.............

.....do.............

.....do..............

.....do.............

.....do.............

Flows. ..............

Mean depth 

of 

oil sand.

Feet. 

800 

1,200 

1,130 

1,025 

1,100 

770 

700 

1,180 

1.170 

L170 

1,0.50 

1,000

Temperature 

of oil.

0 F. 

87 

90 

90 

87 

86 

84 

85 

91 

88 

91 

85 

78

Depth per 

degree of 

increase 

in temperature.

Feet. 

36.3 

48.0 

45.2 

46.6 

52.4 

40.5 

35.0 

45.4 

50.9 

45.0 

52.5 

76.9

48.4

Remarks.

Makes much sand and water. 

Makes much sand. 

Do.

Oil gassy. 

Do. 

Makes much sand. 

Do. 

Makes considerable sand. Oil very 

gassy.

TABLE 10.—Geoihermal gradient in the central part of the Sunset-Midway field. 

[Based on temperature of oil produced by wells more than 2 miles and less than 4 mDes east of the outcrop of the lowest producing oil sand.]

No.

75 

76

77 

78 

79 

80 

81 

81A 

82 

83 

84 

85 

86 

87 

88 

89 

90 

91 

92 

93 

94

95

96

Avei

Well.

Location.

Sec.

24 

10

1 

13 

24 

19 

32 

25 

26 

36 

36 

33 

25 

25 

6 

31 

31 

32 

32 

32 

32

5 

4

•age, 22

T.

31 S. 

32 S.

32 S. 

32 S. 

32 S. 

32 S. 

32 S. 

12 N. 

12 N. 

12 N. 

12 N. 

32 S. 

12 N. 

12 N. 

11 N. 

12 N. 

12 N. 

12 N. 

12 N. 

12 N. 

12 N.

UN. 

UN.

measure

R.

22 E. 

23 E.

23 E. 

23 E. 

23 E. 

24 E. 

24 E. 

24 W. 

24 W. 

24 W. 

24 W. 

24 E. 

24 W. 

24 W. 

23 W. 

23 W. 

23 W. 

23 W. 

23 W. 

23 W. 

23 W.

23 W. 

23 W.

vm^nits

How operated.

Pumped............ .

.....do..............

TflnTOS

Pumped.............

.....do..............

Flows...............

.....do..............

.....do.............. 

.....do..............

.....do..............

.....do........../...

.....do..............

.....do.............. 

.....do.............. 

.....do.............. 

.....do.............. 

Flows...............

.....do..............

Flows...............

Mean depth 

of oil sand.

Feet^ 

2,000 

2,830

3,175 

2,950 

2,270 

2,270 

2,940 

2,225 

1,950 1,980- 

1,700 

2,450 

2,180 

2,260 

2,580 

1,860 

1,625 

1, 820± 

2,600 

2,560 

3,120

2,400 

3,015

Temperature 

of oil.

OJP.

93

84

98 

90 

94 

89 

101 

92 

87 

92 

90 

100 

95 

83 

84 

86 

91 

97 

93 

89 

115

100 

98

Depth per 

degree of 

increase 

in temperature.

Feet. 

71.4 

149.0

96.1 

118.0 

78.2 

94.6 

81.8 

82.4 

88.8 

73.4 

68.0 

70.0 

• 72.7 

125.5 

135.8 

88.6 

62.5 

56.9 

92.9 

106.5 

62.4

68.5 

91.3

88.7

Remarks.

Makes considerable sand. 

Makes some water, probably from 

above the oil. 

Makes much gas. 

Makes no sand. 

Oil gassy. 

Makes little sand. 

Makes some sand. 

"Wild "gusher. 

Makes very little sand.

Oilgaflsy. 

Considerable water.

High gas pressure. 

High gas pressure. Makes practically 

no sand.

"Wild" gusher, making about 40,000 

barrels of fluid, about 75 per cent 

emulsion. Temperature measured 

in ditch 100 feet from well.
40 THE SUNSET-MIDWAY OIL FIELD, CALIF. —— PABT H.

TABLE 11. — Geoihermal gradient in the eastern part of the Sunset- Midioay field. 

[Based on temperature of oil produced by wells more than 4 miles east of the outcrop of the lowest producing oil sand.]

No.

97

98

99

100

101

102

103

104

105

106

107

108

109

110

Sec.

1

6

6

6

32

5

7

8

8

16

9

16

16

16

Location

T.

32 S.

32 S.

32 S.

32 S.

31 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

32 S.

We

R.

23 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

24 E.

l.

Flows...............

.....do..............

.....do..............

.....do..............

.....do..............

.....do..............

.....do..............

.....do..............

.....do..............

Pumped.............

Flows...............

.....do..............

Mean depth 

of oil sand.

Feet. 

2,660

2,430

2,380

2,375

3,000

2,990

2,510

2,600±

2,660

2, 780 ±

2,575

2,650±

2,575

2,640

Temperature

of oil.

"F. 

83

79

75

85

91

93

78

75

77

88

79

82

89

88

Depth per

increase

ature.

Feet. 

147.5

173.5

238.0

118.8

115.4

106.8

193.0

260.0

221.7

120.9

183.9

155.9

107.3

114.8

161.2

Remarks.

sand.

sand.

ured after oil had passed through 

gas trap.

Do.

Makes a great deal of gas and some

sand.

Oil gassy.

Makes a little sand.

TABLE 12. — Geothermal gradient in western, part of Sunset- Midway field. 

[Based on temperature of water produced by 20 water wells. Wells operated by compressed air except as otherwise' indicated.]

No.

Ill

112 

113

114 

115

116

117 

118 

119

120 

121 

122 

123

124 

125 

126

127

128 

129

130

Avei

Avei 

in? 

pr<

Well.

General Petroleum (Carnegie).

StrattonNo. 3. ...........

General Petroleum (Foxtail) No. 2. 

Traders No. 71. ...........

Traders No. 81 ............

Mascot No. 17 ............

August (California Amalgamated) No. 2.

Standard (Monarch) 0. ....

Standard (M. & M.) No. 7.. 

Standard (Wellman) ......

Midway Northern No. 5.. . . 

Standard (Occidental) No. 

4.

Adeline No. 31...........

Good Roads No. 14.........

Union (Diamond) No. 2.... 

'"age 20 0ieafliiremeTits

Location.

Sec.

9

35

7

15 

23

23

26 

25 

35

31 

31 

26 

36

36 

32 

2

2

2 

12

13

T.

31 S.

31 S. 

32 S.

32 S. 

32 S.

32 S.

32 S. 

32 S. 

32 S.

32 S. 

32 S. 

12 N. 

12 N.

12 N. 

12 N. 

11 N.

11 N.

UN. 

UN.

11 N.

R.

22 E.

22 E. 

23 E.

23 E. 

23 E.

23 E.

23 E. 

23 E. 

23 E.

24 E. 

24 E. 

24 W. 

24 W.

24 W. 

23 W. 

24 W.

24 W.

24 W. 

24 W.

24 W.

Mean depth of 

water sand.

Feet. 

3,870

1,610 

760±

1,790. 

1,300

1,100

1,500 

1,470 

1,100

1,480 

1, 500± 

2,170 

2,630±

1,080 

2,530 

1,520

.1,600±

1,865 

3,600

650

Temperature of 

water.

"F. 

131

120 

90

102 

99

101

99 97" 

84

105 

94 

119 

118

108 

115 

107

114

114 

104

90

•age'of Nos. Ill, 112, li4, 118, 120 122, 123, 126, and 128, assunil that temperature of water has been lowered 2° by the comassed air.

Depth per 

degree of 

increase 

in temperature.

Feet. 

58.6

29.3 

30.4

48.5 

38.2

30.6

44.1 

46.0 

57.9

37.0 

51.8 

40.2 

49.6

25.1 

50.6 

36.2

32.6

38.1 

92.3

26.0

43.2 

41.0

Remarks.

Probably a mixture of waters from 

above and below the oil.

Makes about 10 per cent oil. Water 

has probably migrated up from 

lower bed. 

Makes about 5 per cent oil. Water 

has probably migrated ur from 

lower bed.

Sulphur water. Probably ircludes 

considerable water from phallow 

depths.

Probably mixed with upper waters.

Water from sands between 2,3^5 and 

2,870 feet. 

Makes considerable oil. 

Water flowing between casings 

Water from sands between 1,4«5 and1.556 feet. 

Well pumped. Exact depth of water 

Band unknown.

Flowing between casings and probably cooled during ascent. 

Sulphur water. Well pumped.
U. S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 117 PLATE 1

EXPLANATION

Surface contours(generalized) 

Interval 250 feet

Outcrop of upper part of Maricopa shale

Heavy line represents outcrop of lowest oil sand

Axis of a major anticline 

Showing also directions of pitch of fold

• 52.8 Measurement.at one oil well

.1 Average of measurements at group 

of oil wells

O 29.3 Measurement at one water well

Figures show depth in feet per degree 

of increase in temDeratiirp

S.

MAP SHOWING RATE OF TEMPERATURE INCREASE WITH DEPTH IN DIFFERENT PARTS OF THE SUNSET-MIDWAY FIELD. 

Based on temperature of fluid at mouth of well and therefore only approximate. Geology adapted from Plate III, Professional Paper 116.
TEMPERATURE GRADIENT. 41

The foregoing figures are of interest as showing (1) the wide variation, in the gradient in 

different parts of the field, and (2) the fact that 

this variation appears to bear a definite relation 

to distance from the outcrop of the oil sands. 

Thus, in the zone within 2 miles of the outcrop 

the calculated rate of temperature increase 

averages 48.4 feet per degree; in the zone 

between 2 and 4 miles away the average rate is 

88.7 feet; and in the zone more than 4 miles 

away it is 161.2 feet. These data are presented 

graphically in Plate I, which shows the temperature gradient in different parts of the field. 

Owing to the small scale on which the map is 

reproduced, measurements made at adjoining 

wells have been averaged and are not shown 

separately. The map brings out strikingly the 

decrease in the calculated gradient with distance from the outcrop and shows that despite 

local irregularities the variation as a whole is 

surprisingly uniform. This variation is probably due largely to incidental factors which

have affected the accuracy of the observations 

but in part to chemical reactions which have 

raised the gradient in the zone along the 

outcrop.

The following table, inserted for purposes of 

comparison, shows the rate of temperature 

increase in some other oil fields and in 

several districts in which the gradient is supposed to be "normal." Each of the oil-field 

measurements cited was selected as typical 

of a number of observations in the locality, 

and the list is probably a representative one 

of recorded gradients in oil fields. The 

gradients in the other regions cited were 

selected chiefly because they are based on 

fairly accurate measurements in deep wells 

and are apparently not affected by any 

abnormal conditions. It happens that all but 

one of the gradients cited are rather closely 

concordant and average about 61 feet per 

degree, but this may or may not represent the 

true normal gradient for the globe.

TABLE 13.—Geothermal gradient in oilfields and in other regions.

Oil fields:

Florence, Colo..... . .......

Findlay, Ohio. ............

Wheeling, W. Va. .........

Bibi-Eibat, Apsheron Peninsula, Russia. 

Samarinda, Borneo. .......

Other districts: 

Bay City, Mich.. ..........

Charleston, S. C. ..........

Maris, Holland.............

Schladebach, Germany. . . .

Paruschowitz, Germany....

Depth of well.

Feet. 

1, 470-3, 870

1,275

1,100

3,000

4,462

2,276

1,692

2,726

1,575

2,695

2,214

2,381

3,455

2,001

2,100

4,265

5,630

6,427

Temperature at 

bottom.

°F. 

Q7— 1 31

84

101

82.1

110. 15

122.9

99.3

70.7

114.5

118.6

97.0

99.7

63.4

138

133.9

156.7

Depth per 

degree of 

increase in 

temperature.

Feet. 

41.0

51.0

34.5

44.0

95.8

75.2

48.6

25. 3-38. 3

M 7

69.8

47.7 

51.0

OQ O

00 E

K7 E

129.6

50.5

67.2

62.1

Remarks.

perature of water in 9 wells in 

western part of field. 

Oil well... .......................

Oil and water well.................

Based on average temperature of

oil produced by many wells.

Furbero oil field. - ................

Dry hole. ........................

Thermometer submerged for 11 

hours in oil well. _

Temperature of outflowing water. . .

.....do...........................

.....do...........................

.....do...........................

Observer.

Woodruff/*

Fenneman. &

Washburne.c

Hallock.«

Miihlbeig./

Tanasescu. *

Do.

<jfoloub}atnikov. < 

MiibJberg./

Beyer.?»

T, $*>

a Personally communicated by N. H. Barton.

6 Fenneman, N. M., Oil fields of the Texas-Louisiana Gulf Coastal Plain: U. S. Geol. Survey Bull. 282, p. 56,1906.

e Washburne, C. W., The Florence oilfield, Colo.: U. S. Geol. Survey Bull. 381, p. 530,1910.

<* Johnston-John, and Adams, L. H., On the measurement of temperatures in bore holes: Econ. Geology, vol. 11, p. 741,1916.

« Hallock, William, Deep well at Wheeling, W. Va.: Am. Jour. Sci., 3d ser., vol. 43, pp. 234-236, 1892; School of Mines Quart., vol. 18, pp. 

148-153, 1897.

/ Konigsberger, J., and Miihlberg, M., On measurements of the increase of temperature in bore holes: Inst. Min. Eng. (England) Trans.. 

vol. 39, pp. 617-644, 1910.

e Branca, W., Ve/. Naturkunde in Wiirttemberg Jahreshefte, 1897, p. 42.

ft Tanasescu, I., Etudes preliminaires sur le regime thermique: Inst. Geol. Romanei Annarul, vol. 5, fasc. la, p. Ill, 1912.

* Goloubjatnikov, D., Observations geothermiques a Bibi-Eibat et Sourakhany [in Russian]: Com. geol. Mem., nouv. ser., livr. 141, p. 32, 

1916. The observation cited is close to the average of several hundred careful measurements. The average gradient in the neighboring Sourakhany field is 44.5.

i Kawamura, On the geothermic gradient in the Echigo oil fields, Japan [in Japanese]: Geol. Soc.Tokio Jour., vol. 19,pp. 179-185,222-227,1912.

* Lane, A. C., The geothermal gradient in Michigan: Am. Jour. Sci., 4th ser., vol. 9, p. 435,1900. 

l Stephenson, L. W., A deep well at Charleston, S. C.: U. S. Geol. Survey Prof. Paper 90, p. 70,1915. 

« Beyer, S. W., Iowa Agricultural College water supply, pp. 13-14, Ames, 1897.

» Temperatur-Metingen in diepe Boorgaten: Ryksopsporing van Delfstoffen Jaarverslag, 1912, pp. 27-28. 

° Dunker, E., Ueber die Temperatur-Beobachtungen 1m Bohrloche zu Schladebach: Neues Jahrb., 1889, Band 1, pp. 29-47. 

p Henrich, F., Ueber die Temperaturverhaltnisse m dem Bohrloch Paruschowitz V: Zeitschr. prakt. Geologie, vol. 12, pp. 316-320,1904.
42 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

It will be noted that the oil-field gradients 

shown in Table 13 differ widely and are not 

very much higher than those in regions in 

which no oil occurs. The high gradient at 

Batson, Tex., is due to the fact that the oil 

field is on a salt dome and the water has probably ascended steeply from a considerable 

depth. The Ohio and West Virginia measurements, which are representative of a large 

number of very careful observations in the 

Appalachian fields, are unusually low. The 

gradient in the Alsace fields appears to be 

unusually steep, to judge from the many 

measurements that have been made, but that 

in the Rumanian fields approximates the 

average in non oil-bearing regions. The measurements in Russia and Borneo indicate a 

gradient slightly higher than normal, and 

those in Japan show a rather steep gradient. 

Although the average of the oil-field gradients is probably somewhat higher than 

normal, it appears improbable that the difference is great enough or regular enough to 

make temperature measurements of much 

practical value in prospecting for oil.

FACTORS AFFECTING ACCURACY OF OBSERVATIONS.

Several factors injure the value for geothermal calculations of measurements of the 

temperature of fluid made at the mouth of a 

well. This is particularly true of oil wells, 

on account of the cooling effect of the expanding gas. The method by which the fluid is 

brought to the surface also affects the temperature. .Furthermore, calculations of the 

geothermal gradient based on such measurements are generally open to the criticism 

that the depth from which the fluid is derived 

can not be determined within many feet.

Measurements of the temperature of water 

generally represent more nearly the true 

earth temperature than those of oil. Tests 

made on wells by Fuller 1 "show that with a 

steady and moderately rapid flow of water 

through a pipe with a diameter of one-half 

inch the change in temperature due to a difference of 15° in the surrounding material 

amounts to only about 1° for 1,000 feet." 

As the pipes through which the water is 

conducted to the surface in the wells exam1 Fuller, M. L., Amount of free water in the earth's crust: U. S. Geol. 

Survey Water-Supply Paper 160, p. 64,1906.

ined by the writer are generally between 3 and 

6 inches in diameter, they carry a much larger 

volume of water, which would retain its t?,at 

longer, and the loss of heat during ascent in 

such pipes is probably negligible. The temperature of the water produced by a flowing 

well should therefore furnish a fairly satis^actory basis for calculating the gradient, provided the source of the water is definitely 

known and no surface drainage is included. 

Nearly all the wells listed in Table 12, however, were operated by compressed air, wlich 

doubtless lowers the temperature of the 

water somewhat. The writer's observations 

were made in August, 1914, when the normal 

air temperature was 100° or more. As the 

air is generally compressed and delivered 

immediately to the well, it probably loses 

little heat on the way, and after expanding 

in the well is only slightly below its original 

temperature. The water is doubtless cooled 

somewhat by the air during ascent, but as the 

temperatures of the two are not very different, 

the loss is probably small. If the measured 

temperature of the water at the surface is 

increased by 2° or 3°, the true temperature at 

its original horizon will probably be closely 

approximated.

Most of the oil wells in the Sunset-Midday 

field, especially in the western and central 

portions, are operated by pumping, and as 

the loss in mechanical efficiency of the pump 

is converted into heat the temperature of 

the oil is thereby raised to some extent. 

Furthermore, most of the wells make more or 

less sand, which must increase the friction 

somewhat, despite the fact that the pump is 

working in a lubricating medium. The oil 

in wells making a large quantity of sand is 

generally a few degrees warmer than that in 

wells making 'no sand, though the observed 

relation is vague. Even if the loss in mectanjcal efficiency of the pump is 50 per cent, the 

oil theoretically will be heated less than 5°. 

This factor has doubtless operated to r^.ise 

the apparent gradient in the zone nearest the 

outcrop, but the modification in the gradient 

as measured in wells of average depth in this 

district would seldom amount to more than 

10 feet per degree.

The greatest alteration in the temperature 

of oil during ita ascent to the surface is effected 

by expanding gas, and variations in the amount
TEMPEKATURE GRADIENT. 43

of gas doubtless account for much of the variation in the gradient in different parts of the 

field. (See PI. I.) Nearly all the wells in 

the Buena Vista Hills (Table 11) were flowing 

when visited by the writer and naturally made 

large quantities of gas, whereas nearly all of 

those near the outcrop (Table 9) were pumped 

and made relatively little gas. Little information is available as to the proportions of oil 

and gas made by any of the wells, but those 

in the Buena Vista Hills probably averaged 

between 400 and 800 cubic feet of gas per 

barrel of oil, and those in the western part of 

the field probably averaged only one-fifth or 

one-tenth as much. Furthermore, as the 

gas pressure in the Buena Vista Hills was still 

high, the expansion of the gas in the wells 

was greater than in the older territory in the 

western part of the field.

The cooling effect of expanding gas is theoretically great, especially if part of the gas is 

dissolved in the oil. To what extent the oil in 

the Sunset-Midway field is actually cooled by 

the expanding gas, however, is not clear. 

Certainly in the western part of the field its 

temperature can not have been greatly altered, 

for the average gradient calculated from 

measurements at 74 oil wells is only slightly 

lower than that based on 20 water wells which 

are unaffected by gas. Furthermore, measurements 93, 94, and 96 (Ta-ble 10) were made at 

wells flowing more than 7,000 barrels a day of 

very gassy oil, yet the gradients based on these 

measurements are not nearly as low as those 

based on apparently similar observations made 

at the Buena Vista wells. On the other hand, 

measurements 98 and 108 (Table 11) were made 

in the Buena Vista Hills at wells in which the 

gas pressure had diminished so much that the 

well no longer flowed, yet the gradients based 

on these observations approximate the average 

of thbse at neighboring wells.

Although experimental data on the cooling 

effect of gas are scanty, a direct observation, 

Jdndly communicated by Mr. C. E. Van 

Orstrand, is of interest. Mr. Van Orstrand, in 

the course of a very careful study of the 

geothermal gradient in the Appalachian oil 

fields, measured temperatures at various depths 

in a well making about 1 barrel of oil and 570,000 

cubic feet of gas a day. At the point at which 

the flow of gas entered the well he observed 

an abrupt drop in temperature of 9° F., and he

concludes that this represents practically all 

the cooling powers of the gas under a decrease 

in pressure of several hundred pounds. In some 

other wells which made both gas and oil the 

drop in temperature amounted to only 5° or 6°. 

In view of the considerations set forth above 

it seems probable that in the Buena Vista Hills 

the extra loss in temperature due to the 

expansion of gas does not exceed 10° F. If 10° 

is added to the temperature of the oil at the 

wells listed in Table 11, the average gradient 

for the 14 wells becomes 97 feet instead of 

161 feet. This gradient, however, is still far 

below that derived from wells near the outcrop 

(48.4 feet) or even that shown by wells in the 

intermediate zone (88.7 feet), and the increment of heat due to pump friction accounts 

for only a small fraction of the difference. It is 

evident that a much more liberal correction 

might be made for the cooling effect of gas in 

the Buena Vista" Hills without entirely wiping 

out the difference in the calculated gradients.

CHEMICAL REACTIONS AFFECTING THE GEOTHERMAL GRADIENT.

Although the influence of many factors on 

the geothermal gradient has been recognized 

in one place or another, the data are yet too 

scanty to permit a satisfactory evaluation of 

their relative importance. In most oil fields the 

most obvious cause of high gradients—proximity to recently intruded igneous rocks, or the 

presence of thermal (magmatic) ascending waters—need not be considered. Rise in temperature due to orogenic movements may, however, 

be an important factor in Tertiary oil fields 

which have suffered recent deformation. Tanasescu1 suggests that as petroleum [oil and gas] is 

compressible it may suffer considerable reduction in volume through orogenic movement, and 

that this reduction in volume would be transformed into heat—in other words, that the 

heating of the rocks by earth movements is 

accentuated if petroleum is present. He calculates that if a deposit of oil and gas is subjected 

to sufficient pressure to cause a reduction to 

two-thirds of its original volume its tempera^ 

ture will be raised 120° F., and that reduction 

to one-third of its original volume will raise the 

temperature 327° F. It is very improbable 

that so great a reduction in volume could be 

brought about by earth strains, for movements

Op. cit.
44 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PABT II.

of the fluids would probably take place and 

hydrostatic equilibrium would be restored; 

but it does seem possible that earth movements 

in comparatively recent geologic time may still 

affect the gradient in some oil fields. This 

possibility may in part explain the fact that 

the gradient in the Appalachian fields, which 

are hi Paleozoic rocks that have undergone 

no recent deformation, is unusually low, whereas the gradient hi the other oil fields studied, 

which are in more or less deformed Tertiary or 

Cretaceous rocks, is unusually high.

If oil-field gradients in general prove to be 

high it is possible that radioactivity has been 

a factor. Boyle * has shown that radium emanation is about fifty times as soluble in crude 

oil as in water and that thorium emanation is 

also considerably more soluble. Oil may thus 

tend to concentrate whatever radium and 

thorium emanation may be present in the 

rocks, and the heating effects of these substances might be sufficient to cause a perceptible increase in the geothermal gradient. Although little weight can yet be attached to this 

suggestion, it would seem that an investigation 

of the radioactivity of crude oils might be of 

value.

-> Variation in the gradient within the limits 

Vof a field must, however, be ascribed to other 

causes, the most effective of which is probably 

the heat of chemical reaction. It has already 

been shown that both the oil and the water 

have undergone certain chemical changes, 

which have been and probably are now most 

vigorous in the zone nearest the outcrop. 

Some of these reactions are perhaps endothermic, absorbing heat; others are exothermic, 

generating heat. As the series of reactions as 

a whole is certainly exothermic, the higher 

gradient near the outcrop seems to be adequately explained. Among the chief reactions 

involved are these:

i Boyle, E. W., Note on the solubility of radium emanation in 

liquids: Eoyal Soc. Canada Trams., 3d ser., vol. 3, sec. 3, p. 75,1909. 

See also McLennan, J. C., On the radioactivity of natural gas: Nature, 

vol. 70, p. 151, 1914; Burton, E. F., A radioactive gas from crude petroleum: Philos. Mag., 6th ser., vol. 8, p. 498, 1904; Himstedt, F., 

tiber die radioaktive Emanation der Wasser- und Ohjuellen: Annalen 

der Physik, 4th ser., vol. 13, p. 573, 1904; also in Physikal. Zeitsehr., 

vol. 5, p. 210,1904.

1. Reduction of sulphate to sulphide and 

oxidation of hydrocarbon to carbonate. Js 

the exact course of this reaction is unknown 

its thermal value can not be determined. The 

reaction as written on page 27 would, according 

to Wells,2 yield several hundred calories an4 

would therefore be weakly exothermic.

2. Oxidation of hydrogen sulphide to sulphur. This reaction is strongly exothermic, 

yielding 59,100 calories.3

3. Reaction of the oil with sulphur, leading 

to the formation of sulphur compounds. Tie 

thermal character of this reaction is unknown.

4. Oxidation of the oil by oxygen-bearing 

waters, probably a rather strongly exothermic 

reaction.

5. Condensation or polymerization of tt^ 

hydrocarbon molecule through the action of 

sulphur or oxygen, or in other ways. According to Berthelot 4 the polymerization of acetylene (C2H2 ) to benzene (CaH6) produces 1£3 

calories, and other similar changes are ako 

known to be exothermic. In Stremme's 

opinion 5 such reactions may account for a 

higher geothermal gradient in oil fields.

As the net thermal value of these reactions is 

unknown, it is impossible to estimate the;r 

quantitative effect. It is significant, howeve^, 

that oil nearest the outcrop and highest in 

sulphur is almost invariably hotter in proportion to its depth than that farther away. 

Similarly, water containing hydrogen sulphide 

(sulphur water) is in general abnormally warm 

unless it is mixed with shallow (sulphate) 

waters. On the other hand, the oil low in 

sulphur and the water from which all sulphate 

and hydrogen sulphide have been removed are 

usually much cooler in proportion to their 

depth. Though much or most of the difference 

in the calculated gradient in different parts of 

the field is undoubtedly due to incidental 

factors, as already explained, the conclusion 

that the geothermal gradient has been affected 

by chemical reactions seems unavoidable.

2 Wells, R. C., personal communication.

»Seeker, G, F., Geology of the quicksilver deposits of the Taciflc 

slope: TJ. S. Geol. Survey Mon. 13, p. 254,1888.

* Berthelot, M,, Thermo-ohimie, vol. 1, pp. 488-492,1897.

6 Stremme, H., Das pdymerislerende ErdSl als Warmquelle im 

Erdboden: Centralbl. Mineralqgie, 190% p. 271.
HYDROLOGIC RELATIONS OP THE FIELD. 45

OIL-FIELD WATERS. 

SCOPE OF DISCUSSION.

One of the most important problems in the 

development of the California oil fields is that 

of determining the position of the waterbearing strata in relation to those that carry 

the oil. In most localities several waterbearing sands are intercalated in the sediments 

above the oil measures, and water sands also 

occur some distance below; in many places 

one or more of the sands in the oil measures 

are occupied by water, though some distance 

away the sand at the same horizon contains 

oil. In sinking a well through this complex 

it is difficult to prevent the water, which may 

be under a high head, from entering the oil 

sands, and if it does it may drive the oil some 

distance back and so ruin a considerable tract 

of land. Although "difficulty in shutting out 

the water is experienced in every oil field 

it seems to be accentuated in the California 

fields by the practically unconsolidated nature 

of the sediments, and at the same time, perhaps 

because of the chemical character of the oil 

itself, the invasion of water into the oil sands 

in those fields seems to exercise a particularly 

harmful effect on production.

Oil-field waters may be studied from several 

different points of view, each of which leads to 

conclusions of value.. Determination of the 

position of the principal water sands with 

relation to the oil, which is usually possible 

from a study of the well logs,, is of course of 

primary importance. Investigations of the 

chemical character of the waters have also 

proved to be of direct value, for it has been 

found that the source of a water is indicated 

in a general way by its composition. Studies 

of the manner in which water gains access 

to the oil sands and of its effect on the productivity of the sands are concerned partly with 

geologic and partly with technologic factors. 

Investigations of the best methods of excluding 

water from the well, which are of most immediate interest to the operator, are strictly 

technologic.

The stratigraphic position of the main water 

sands in relation to that of the oil sands is dis- • 

cussed by Mr. Pack in Part I of this report, 

and the chemistry of the water will be discussed in this chapter. Although the field 

work on which this report is based also included

a survey of water conditions throughout the 

field, it is felt that details of the appearance, 

source, effects, etc., of water in individual wells 

have little permanent interest. The constantly changing water conditions are being 

closely watched by officials of the California 

State Mining Bureau,1 whose reports contain 

much detailed information on the subject. 

Accordingly only the general principles governing the invasion of water and its effects on 

production will be considered here. These 

matters and also the problem of shutting out 

the water from the wells have been discussed in 

several reports of the Bureau of Mines,2 and of 

the California State Mining Bureau, as well as 

in numerous recent papers in the periodical 

press.

HTDBOLOGIC RELATIONS OF THE FIELD.3

The Sunset-Midway field lies on the west 

side of San Joaquin Valley, which is a portion 

of the great nearly level floored depression that 

lies in the central part of California. The 

northern two-thirds of the valley is drained by 

Sap. Joaquin River, but the southern, more 

arid third has no surface outlet under normal 

conditions, and the surface waters accumulate 

in the depressions occupied by Buena Vista 

Lake, just east of the field, and Tulare Lake, 

some 50 miles to the north. The streams that 

drain into the valley from the Sierra Nevada 

on the east carry about all the surface water 

that reaches it, for the streams on the west 

side are shorter and practically dry during the 

greater part of the year.

A large portion of the water that drains into 

San Joaquin Valley sinks into the sand and 

silt of the valley floor and joins the underi McLaughlin, R. P., California State Min. Bur. Bull. 73,1917; Bull. 

82,1918.

Lewis, J. O., and McMurray, W. F., The use of mud-laden fluid in 

oil and gas wells: Bur. Mines Bull. 134, 86 pp., 3 pis., 18 figs., 1916.

Tough, F. B., Methods of shutting off water in oil and gas wells: Bur. 

Mines Bull. 163, 122 pp., 20 pis., 7 figs., 1918.

Arnold, Ralph, and Garflas, V. B., The cementing process of excluding 

water from oil wells, as practiced in California: Bur. Mines Tech. Paper 

32, 12 pp., 1 fig., 1913.

Pollard, J. A., Arnold, Ralph, and Garfias, V. R., The prevention of 

waste of oil and gas from flowing wells in California, with a discussion of 

special methods used: Bur. Mines Tech. Paper 42,15 pp., 2 pis., 4 figs., 

1913.

Pollard, J. A., and Heggem, A. G.vMud-laden fluid applied to well 

drilling: Bur. Mines Tech. Paper 66, 21 pp., 12 figs., 1914.

Arnold, Ralph, and Garfias, V. R., Methods of oil recovery in California: Bur. Mines Tech. Paper 70, 57 pp., 7 figs., 1914.

8 For a complete account of the underground waters of San Joaquin 

Valley see Mendenhall, W. C., Dole, R. B., and Stabler, Herman, 

Ground water in San Joaquin Valley, Calif.: U. B. Geol. Survey WaterSupply Paper 398,1916.
46 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PART H.

ground circulation, which follows the surface 

flow in general direction but at a far slower 

rate. The rate of movement of underground 

water is governed by several factors, important 

among which are the gradient of the slope, the 

shape and size of the materials through which 

the water must flow, and the freedom of the 

outlet by which it escapes. In San Joaquin 

Valley all these factors militate against rapid 

flow; the gradient is low, the materials are 

generally fine, and the outlet at San Francisco 

Bay is narrow. As a result of these conditions 

the ground-water circulation is abnormally 

sluggish, the deeper waters being highly 

mineralized and practically ponded, especially 

near the north end of the valley.

As the west side of the valley is a region of 

very scanty rainfall, practically all the drainage 

sinks beneath the surface before reaching the 

valley proper and circulates through the great 

thickness of sedimentary formations described 

by Mr. Pack in Part I of this report. These 

strata contain a large amount of disseminated 

gypsum and other sulphates, which are readily 

dissolved by the waters leaching through them. 

All the water that drains from the west side of 

the valley is therefore high in mineral matter, predominantly sulphates. Many of the 

shallower waters in the Sunset-Midway field 

are notable for their very high proportion of 

sulphate.

Rain water falling on the upturned and 

truncated edges of the sedimentary formations 

in the Temblor Range, west of the SunsetMidway district, naturally tends to enter the 

strata and percolate down into San Joaquin 

Valley, becoming a part of the underground 

circulation of the valley and finally reaching 

the ocean at San Francisco. Inasmuch, however, as underground water in a region of sedimentary rocks tends to follow the bedding 

planes, the structure of the rocks has an important effect on the freedom of circulation. 

Ram water f ailing on the northeast slope of the 

Elk Hills or the Buena Vista Hills, for example, 

enters the beds and presumably finds a relatively free passage down into the valley. 

Water falling in the western part of the main 

field, however, enters the strata and percolates 

down into the Midway syncline, where its 

farther passage is impeded and at least temporarily blocked by the Buena Vista and other 

anticlines that separate the syncline from the

main valley trough. The degree of completeness with which the water is ponded in the 

synclinal trough is somewhat increased by the 

fact that this trough pitches in general toward 

the southeast, whereas the trend of the circulation in the valley below is toward the nor*hwest. If a sufficient hydrostatic pressure accumulates a part of the water trapped in the 

syncline will of course be forced around the 

end of the barrier or will be forced over it, 

presumably at some structurally low point. 

It is obvious that a certain amount of metecric 

water is practically1 ponded in the syncline, 

and it is furthermore believed that a part of 

the connate water (sea water that the beds 

contained when they were deposited) has never 

been driven out. The belief that the oil-fHd 

waters consist in part of rain water and in p*,rt 

of slightly altered sea water is borne out, as 

will be shown later, by the chemical character 

of the waters in different parts of the field.

OCCURRENCE OF THE OIL-MELD WATERS. 

GENERAL DISTRIBUTION.

It Js generally assumed that ground water 

exists as a fairly continuous body saturating 

all rocks down to an indefinite depth. "The 

upper limit of the body pf ground water is 

known as the water table; it follows in a g^- 

eral way the configuration of the surface T^ufc 

ha arid regions may He at a depth of several 

hundred feet. Although this conception is 

valuable in a broad study, investigation shows 

that the water table is generally irregular ivad 

that numerous local accumulations of ground 

water, known as perched water tables, oc-w 

above it. Furthermore, although all the strata 

below the main water table are believed to be 

saturated with water the facts that the head of 

water varies in different strata and that circulation is confined largely to certain beds are of 

course of great practical importance. ""Tie 

layers in which the water will circulate are determined by a variety of factors, most of which, 

though generally tinknown in advance of drilling, are well understood. There is no intrinsic 

difference between a water sand and any other 

sand.

WATER SANDS.

As water flows most readily through rock^ of 

uniformly coarse grain it tends to circulate 

chiefly in the sandy layers or " water sands."
OCCURRENCE OF THE OIL-FIELD WATERS. 47

The amount and pressure of the water in a sand 

depend largely on local conditions, but if these 

were uniform water would normally be found 

in greater available quantity and under higher 

head in coarse sand than in tight sand or sandy 

shale. Moreover, as few beds of sand are entirely uniform in grain the water is generally 

concentrated to some extent in the coarser 

layers, which are analogous to the "paystreaks" 

in an oil sand. In some sands the coarser portions are not true layers extending across the 

sand body but are simply streaks or channels 

having a comparatively small width. Hence, 

of several neighboring wells penetrating the 

same sand, one may encounter an unusually 

open or porous streak which yields a large flow, 

whereas the others may penetrate the tighter 

portion of the sand and obtain a much smaller 

volume of water, perhaps so small that the 

driller fails to recognize the bed as a water sand 

at all. 

Although the grain of the rocks is important

in determining which beds the drainage f

an equally effective factor in lenticuU

terial is the freedom of inlet and outlet

lens itself. It is evident that water w

circulate' in a bed unless the water entei

the outcrop can escape at the lower end

lens, either into another lens or througl

practicable channel. If the upper end i

and the lower end sealed, water will accui

only up to the absorptive ca

and if the hydrostatic head

trapped is not great enough

movement will cease until tl

by the drill. The structure

exercise an entirely similar €

circulation, so that water m

syncline or a basin. If a

sealed on all sides, there cai

even when it is penetrated

the rock pores are partly fil

under pressure; under such

pansion of the gases may di

water.

Although water sands are

they are the principal ehann<

must not be supposed tjia

rocks are dry. Coarse, op

which flow is most rapid, ha

space or absorptive capacit

cent : unsorted or tighter s

aacity of th«

of the wate

to force an

e pocket is c

of the rock

feet in prev

ay be trappe

lens is effe<

i be no mov

in drilling,

ed with air

conditions t

splace some

so termed b

Is of circulai

> the surroi

en sand, tl

s an averag

p- of 32 to

tnd, 38 to

Hows,

r maof the

1 not

ing at

of the

some

open

aulate

sand,

r thus

outlet

>ened

a may

enting

d in a

bually

ement

unless

or gas

le exof the

jcause

ion, it

nding

rough

i pore

7 per

2 per

cent; and clay, 44 to 47 per cent.1 Clay may 

thus contain nearly half as much water again as 

sand, though the important practical consideration is that sand yields its water readily because more fluid can easily take its place, 

whereas movement is slower in clay and much 

of the water it contains is probably held by 

capillary attraction. A sandy shale or a tight 

sand may also contain considerable water that 

will not be apparent in drilling because it escapes too slowly from the bed. If the strata 

penetrated by an ordinary oil well could be 

carefully examined, however, all those below 

the ground-water level probably would be 

found to contain more or less water.

It is thought by some drillers that water 

sands have a peculiar texture by which they 

may be distinguished from oil sands. It is variously held that the grains are sharper or more 

angular, or that they are smaller, or that water 

sand contains grains of mica, whereas oil sand 

does not. Any of these distinctions may be 

valuable locally, and some sands may be traced 

for a considerable distance by their texture and 

mineral character, but to assume that water 

sands and oil sands are essentially different in 

grain or mineral composition is- to overlook 

entirely the principles that govern the movement of water and oil.

DRY SANDS.

In most well logs an attempt is made to 

differentiate water sands and "dry" sands, 

the dry sands being those which yield no 

water or which, on the contrary, absorb it. 

The distinction is valuable in so far as it 

records the horizons at which the greatest volumes of water were encountered, though none 

of the beds below the ground-water level are 

actually dry. A so-called dry sand may contain a large proportion of water under low 

hydrostatic head which it may yield under 

favorable conditions. Emphasis on this point 

is. by np means academic. In the early history of an oil field water under low hydrostatic head may be unimportant, but at a 

later period, after the gas pressure has diminished and a considerable portion of the oil has 

been removed, the oil sands constitute a con1 King, F. H., Principles and conditions of the movements of ground 

water: U. S. Geol. Survey Nineteenth Ann. Kept., pt, 2, pp. 209-215, 

1899.
48 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PABT II.

venient reservoir, and such water may enter 

them and do considerable damage. The facility with which water under low head may 

enter practically exhausted oil sands has been 

strikingly exemplified in parts of the SunsetMidway and Coalinga fields.

In the standard or cable-tool method of 

drilling it is customary to maintain a certain 

depth of water in the drill hole. If the water 

level rises when a sand is encountered the bed 

is logged as a water sand, and if it remains 

stationary or falls the sand is logged as dry. 

However, a column of drilling water 1,000 feet 

high exerts a pressure of 434 pounds to the 

square inch at the bottom of the hole, and if 

the hydrostatic pressure in the sand is lower 

than the weight of the column of drilling 

water the water level will sink and most of 

the water may be absorbed. Thus, sands that 

rapidly absorb the drilling water and are therefore logged as dry sands might yield considerable water if the drill hole were dry. In the 

rotary method of drilling mud is continually 

pumped into the hole under considerable pressure and it is even more difficult to estimate 

the water-yielding capacity of a sand. If the 

bed is pervious and carries water under a low 

head its presence is easily recognized by the 

fact that the pump pressure necessary to force 

the mud into the hole is suddenly decreased. 

If, however, the sand contains water under a 

high head the difference between its upward 

pressure and the downward pressure of the 

column of drilling mud may be so small that 

it is not shown by the pump gage, and the 

sands that contain the most water may thus 

be missed.

HEAD OR PRESSXJEE.

The head or pressure of the water is different 

hi different sands, owing chiefly to variations 

in porosity and in freedom of circulation. As 

a general rule, however, it increases with depth; 

and similarly in any one sand it is generally 

greater farther down the dip. Many waters 

that flow at the surface have been encountered 

in the Sunset-Midway field, some above and 

others below the oil measures. The head in 

most of the sands reported by drillers as water 

sands is more than 200 feet, and many sands 

that are reported as dry probably'carry water 

under a head of more than 50 feet.

The water pressure in the Sunset-Midday 

field is, in general, highest in Midway Valley 

and on Maricopa Flat. The pressure in most 

sands, however, is not constant and diminishes 

noticeably a short time after the sand is tapped. 

Waters that flow for months or years finally 

cease to flow, and the head of waters that rise 

but do not reach the surface is also knowr to 

decrease. The rate of decrease in any particular sand depends on local conditions and r^ ay 

differ widely among neighboring wells, but the 

general decrease in the field as a wholo is 

striking.

The fact that the water pressure increases 

roughly as the depth indicates that it is mainly 

hydrostatic in general character. Hydrostatic 

pressure is caused by the weight of the downward-bearing column of water, and its amount 

at any place is controlled by the differenc^ in 

elevation between that point and the point at 

which the water enters the bed, and by the 

fineness of the material through which the 

pressure is transmitted. There is a difference 

in elevation of 800 to 1,000 feet between the 

extreme western part of the field and Midway 

Valley, and although this head is largely destroyed by the friction incident to the passage 

of water through the sand in the 4 iriles 

between these points, enough head usually 

remains to raise the water almost to the surface hi Midway Valley and in some place^ to 

cause it to flow. So far as hydrologic conditions are concerned the Midway syncline constitutes an excellent artesian basin, though the 

rainfall is small and much of the head is lost 

because of the lenticularity of the sands.

The unusually low head of water hi the socalled dry sands may be due to a variety of 

conditions. If the sand is fine or irregular in 

grain, most of the normal head will be lost 

through friction and the movement of water 

through it will be very slow. Similarly, if the 

sand is in the form of a lens sealed on all sides 

by shale it can neither give nor take up water 

when penetrated by the drill. On the other 

hand, if the sand has a free intake above and a 

free outlet below and if it is coarse and open 

grained, so that the water percolates through 

it readily, only a small head is developed, for 

the water will follow the path of least resists nee. 

If the sand js sealed at the upper end but has a 

free outlet at the lower end, a negative head
OCCURRENCE OF THE OIL-FIELD WATERS. 49

or partial vacuum might conceivably be created, and such a sand might take up drilling 

water as fast as it could b0 poured into the 

well.

Another factor which is supposed by many 

to exert a notable influence on the movement 

of underground water is root: pressure. Rock 

pressure, strictly defined, is ;he weight of the 

overlying column of rock which exerts a compressive effect on the beds be:ieath it. During 

the deposition of the sediments the pressure 

of the upper layers undoubtedly leads to 

closer packing of the grains in the lower layers 

and to the expulsion of some of the connate 

water. Pressure due to strains produced during uplift and deformation, which may also 

be called rock pressure, is doubtless an important agent in forcing water oat of the beds or 

causing it to migrate to otlier parts of the 

formation or series.1 The past and present 

effects of rock pressure can not be disregarded, 

but their magnitude is generally an unknown 

quantity.

Although in the Sunset-Midway field the 

water pressure in many of the ^ands is probably 

wholly artesian, the influenc^ of gas must be 

taken into account, especially in considering 

the pressure in the lower sand^. In general the 

gas pressure in any sand is lesis than the weight 

of an overlying column of wa^er, but there are 

sands in which it is greater and in which, 

therefore, its influence must t e considered. If 

a sealed sand lens is filled partly with w.ater 

and partly with gas under pressure, the water 

may flow out under great apparent head when 

the sand is tapped. In addition to the pressure exerted by a body of gas, the influence of 

gas liberated from solution in causing water to 

flow is also important. Hydrocarbon gas is 

dissolved in some waters, and many others contain carbon dioxide and hydrogen sulphide. 

These gases are partly liberated at the foot of 

the well and act somewhat like an air lift in 

causing the water to flow, 

feeble compared with the propulsive effect of a 

body of compressed gas, bull it is doubtless 

more widespread and causes some waters to 

flow that might not otherwise reach the surface.

1 For an ingenious speculative discussion of this process, see Daly, 

M. R., The diastrophic theory: Am. Inst. Hin. Eng. Bull. 115, pp. 

1137-1157,1916.

110973°—19——4

TEMPERATURE.

The temperature of a few of the waters was 

measured by the writer and found to range 

between 84° and 131° F. The temperature of 

water from sands more than 1,200 feet deep is 

generally greater than 100°, but it is doubtful 

if any waters yet encountered in the field are 

much hotter than 131°, though reports to this 

effect are sometimes heard. The measurements 

arid a discussion of the factors that cause variation in temperature are given on pages 37-42.

Although variation in temperature is due to 

several causes, the gradient is usually fairly 

regular, so that the source of the water is indicated in a general way by its temperature. 

A sand that receives much surface drainage is 

generally abnormally cool, and several waters 

which seemed cool in proportion to their supposed depth were found by chemical analysis 

to be mixed with waters from higher levels. 

Similarly, a mixture of oil and bottom water is 

generally 5° to 10° hotter than clean oil produced from the same depth by neighboring 

wells, a fact which suggests that the water in 

migrating up from the lower water sand is carrying its original temperature with it. Whether 

edge water or top water close to the oil could 

be distinguished by their temperature is not 

known, for the measurements made by the 

writer are neither sufficiently numerous nor 

sufficiently precise to indicate the significance 

of slight variations in temperature. It is interesting to note, however, that in the Baku fields 

of Russia, where invasion of water into the oil 

sands has long been a source of great trouble 

and expense, an effort has been made to use 

temperature measurements in determining the 

bed or horizon from which the water comes. 

Goloubjatnikov, 2 who has made several hundred fairly precise measurements of the temperature of the oil and water in wells in the 

Bibi-Eibat and Sourakhany fields, states that 

the horizon of the water may be estimated 

rather closely from its temperature, and that 

observations of temperature are therefore of 

considerable practical value in determining the 

source of the water flooding a well.

2 Goloubjatnikov, D., Observations g&rthermiques a- Bibi-Eibat et 

Sourakhany [in Russian]: Com. g6ol. M6m.,nouv. ser., livr. 141, p. 32, 

1916.
50 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

RELATION TO THE OIL,.1

The Paso Robles and Etehegoin formations, 

which -overlie and include the productive oil 

measures in the Sunset-Midway field, contain 

a number of sands that carry water. Most of 

these sands are irregular and discontinuous 

and can be traced only within small areas. 

In some localities where an unusually extensive sand offers a favorable channel or reservoir for the water the circulation is localized, 

but in general there are many lenticular sands 

and all of them contain more or less water. 

The Maricopa shale, which unconformably 

underlies the oil measures, also includes a 

number of lenticular water sands. Some 

waters thus occur above the oil sands, others 

below, and still others in the same sands but 

farther down the dip, and it is customary to 

designate them top waters, bottom waters, and 

edge waters, respectively. It is natural for the 

driller who is interested primarily in the position 

of the oil itself to classify waters according 

to their position with regard to the oil, but 

his terminology is often ambiguous. The 

bottom water of an upper oil sand may be the 

top water of a lower sand. An edge water 

may be either top water or bottom water or 

both. These terms are too commonly used 

and too convenient to discard, but the term 

top water should be restricted to water above 

the highest producing oil sand, and bottom 

water to that below the lowest oil sand. The 

waters within the oil zones themselves may in 

general be regarded as edge waters.

As numerous factors influence the distribution of the water and the course of its circulation, it is impossible to predict in advance of 

drilling exactly where the largest flows will 

be found, though certain useful generalizations can easily be made. The general groundwater level in the field varies from place to 

place but is usually within 500 feet of the surface. Between this water table and the horizon of the oil from one to half a dozen or more 

top waters are found, the number depending 

chiefly on the depth of the oil zone. Along 

the hilly western portion of the field the groundwater level is of course particularly low and in 

some localities there is little water above the

1 The positions of the water sands in the various parts of the field 

have been described by Mr. Pack in Part I of this report (Prof. Paper 

116), and many of the statements in the following account are based on 

the details there given.

oil zone. In many of the wells within 1,000 

or 1,500 feet of the outcrop and also in those 

along the crests of several of the shallov anticlines no top water was found and only a single 

string of casing is set. Tar sands that occur 

above the productive oil measures, however, 

usually carry some water—commonly grjlphur 

water—and although this water is ger orally 

under low head it is likely to become troublesome after the gas pressure has decreased 

and the oil sands are partly exhaustec1 . In 

Midway Valley the ground-water level i^1 generally within 200 feet of the surface and a 

large number of top waters are encour tered. 

Some of the deeper waters flow at the surface 

and would yield large supplies if pumped. 

These waters are strongly saline and of little 

value, however, and as most of the wells in 

this district are drilled to a level near the oil 

horizon by the rotary method, no accurate record of the top waters is kept. Conditions in 

the Buena Vista Hills are similar, though the 

ground-water level there is of course somewhat 

deeper than in the valley. In general, top water 

may be expected to occur down within 100 or 

even 50 feet of the highest oil sand everywhere 

except along the western edge of the field, 

though in parts of the Buena Vista Hills no 

top water is definitely reported within 300 

feet of the oil.

The waters that have proved most troublesome are those occurring in or below tho productive oil measures. As shown in Part I 

(Prof. Paper 116), the plane of unconformity 

separating the Maricopa shale from the Etehegoin formation has greatly influenced the accumulation of the oil and has also indirectly 

affected the distribution of the water. In the 

extreme western part of the field, whe^e the 

Etehegoin formation is thin, the productive 

oil measures are comprised in zone A, but 

farther down the dip zone B appears and then 

zone C, the upper or western edges of these 

zones abutting against the irregular surface 

of the Maricopa shale. Near the line along 

which zone C becomes recognizable, however, 

zone A ceases to be productive, its sands being 

occupied by tar and water and farther down 

the dip by water alone. Similarly, water 

sands appear in zone B still farther dovn the 

dip, and near the axis of the Midway syncline 

practically all the sands in this zone are occupied by water, though on the flanks of the
Buena Vista anticline, to the east, zone B 

again becomes productive. Zone 0, in the 

lower part of the Midway Syncline, contains 

some water sands but is recognized as a productive oil zone across the i syncline i and becomes wholly occupied by \fater on y on the 

farther flank of the anticline to the east.

As zones A and B both b3come filed with 

water down the dip, it is evic ent thai; the belts 

or strips of territory in whch the transition 

takes place are likely to be c ritical vtith reference to water conditions. In these belts some 

operators are likely to attempt to produce 

from the upper zone, while others drill to the 

deeper sands and case off the less productive 

upper sands. The operators who produce 

from the upper zone thus have to contend not 

only with the water originally present there, 

but also with that let into the zone by the 

neighboring deeper wells. As pointed out by 

Mr. Pack in Part I of this report, water is likely 

to be very troublesome throughout these transition belts and as time passes wilj. become 

more so.

As shown on Plate III, Professional Paper

OF THE OIL-FIELD WATERS. 51

116, zone A is recognized only 11

localities in the western portion of

Near the outer or eastern edge of the

which this zone is shown

map water sands appes

area contoured the zc

entirely of water sands.

for this zone, which is fa

defined, thus surrounds t

zone is contoured. The

the same horizon farthe

true edge waters of zone

generally referred to as

zone B.

The transition belt in z

more poorly defined. "\

in this zone well up on

the west side of the field

carry oil far down the dij

syncline. In the northe:

zone B becomes filled wi

nonproductive within a

outcrop. In the southerr

area extends much fart

most of the deeper territo

one or more water sands

occur near the top of the 2

treated as top water and

by contou

r, and be;

ne consists

The transi

irly narrow

le area in v

waters occ

c down the

A, though

the top T?

one B is bro

Tater sands

i certain

the field.

areas for

rs on the

fond the

i almost

$ion belt

and well

rhich the

irring at

dip are

they are

Waters of

ader and

} appear

the structiire along

though some sands

toward the

•n part of

;h water an

few miles

L part its pi

ler east, t]

ry the zone

i Midway

the field

d wholly

of the

•oductive

lough in

includes

Where tile waters

;one they ar^ usually

cased off, aiid where

they occur well down in the zone they are 

usually regarded as bottom water. On Maricopa Flat, however, where all the productive 

measures are referred to zone B, there are 

several well-recognized water sands lying 

between productive oil sands, and this condition has rendered extraction of the oil with 

exclusion of water very difficult. Although 

on the southwestern limb of the Midway 

syncline water sands in zone B generally 

extend well up the slope, on the farther or 

northeastern limb the water, according to Mr. 

Pack, extends a much shorter distance, except 

in the northern part of the field. In the central and southern parts of the Buena Vista 

Hills zone B is productive in a broad strip and 

extends well down the farther flank of the anticline before again becoming filled with water.

Zone C in several parts of the field includes 

water sands, some of which occur at the base of 

the productive measures and may therefore 

properly be termed bottom waters. Thus in 

practically all the productive territory in T. 31 

S., R. 22 E., water occurs at or below the base 

of the oil zone, and this water sand, or series 

of sands, constitutes one of the most persistent 

water carriers in the field. Farther southeast, 

or along the syncline in T. 32 S., R. 23 E., water 

also occurs in the lower part of zone C or at its 

base. In some localities water sands also occur 

higher in zone C, a conspicuous example being 

the water closely underlying the gusher oil 

sand north of Fellows. In the northern part 

of the Buena Vista Hills the zone includes one 

or more water sands, and down on the northeastern limb of the Buena Vista anticline the 

zone finally becomes nonproductive.

In some parts of the field true bottom water 

is found only in the Maricopa shale. As t}ie 

bedding in this formation is unconfonnable 

with that in the overlying oil measures the 

water is not encountered at any special depth 

or horizon below the oil but occurs in sandy 

beds that are apparently lenticular. In the 

eastern part of the field the Maricopa shale 

has not been explored, but in the western 

part many wells have penetrated it and have 

found water at varying depths beneath its 

upper surface. Several wells along the western 

edge of the field obtain from this formation 

large quantities' of water, which is sold for 

boiler use.

In some localities water from the Maricopa 

shale has probably, according to Mr. Pack,
52 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PAKT II.

migrated up into the overlying oil measures. 

In the area northwest of Fellows and also on 

Twenty-five Hill the producing oil zone (A) 

rests directly on the Maricopa shale. In narrow belts in these localities a strong bottom 

water is encountered, apparently at the very 

base of the oil measures. This water is believed to have migrated up from a Maricopa 

water sand, truncated along the plane of unconformity that marks the top of that formation, or, in other words, to have followed the 

course originally taken by the oil. As the 

basal oil sands become exhausted this water 

may spread farther through them and thus become an edge water, working down the dip 

instead of following the oil up the slope in the 

normal way.

ANALYSIS OF WATER AND INTERPRETATION OF 

RESULTS.

MINERAL CONSTITUENTS IN WATER.

Natural waters are essentially solutions of 

mineral substances that have been derived 

from the rocks or other material with which 

the waters have come into contact. The 

amount and character of these substances vary 

greatly and depend on many factors, chief 

among which are the chemical character and 

physical condition of the materials encountered, the heat and pressure, the duration of 

the contact, and the amount and character of 

the substances previously dissolved. If two 

waters that carry different salts in solution 

come into contact a chemical reaction may take 

place and some of the dissolved material may 

be precipitated.

The common mineral constituents of natural 

waters may be divided into two groups—those 

which have definite chemical relations with 

some other constituent and those which are 

probably present as colloids. The colloid 

group comprises silica, iron oxide, and alumina. 

These substances, like those in the other group, 

may perhaps be held in solution in some waters, 

but ordinarily they are considered to be not in 

actual solution and are conventionally reported 

as the oxides silica (SiO2), ferric oxide (Fe^), 

and alumina (A12O3 ). The constituents of the 

other group are of two kinds—the positive 

radicles or bases, chiefly sodium, potassium, 

calcium, and magnesium, and the negative or 

acid radicles, chiefly sulphate, chloride, carbonate, and bicarbonate. The several constituents of each kind have different 'but 

definite capacities for reacting with or holding 

in solution constituents of the other kind. 

The two kinds of constituents in a water are 

always in chemical equilibrium—that is, the 

sum of the reaction capacities, or "reacting 

values," of the positive radicles is equal to the 

sum of the reacting values of the negative 

radicles. In addition to the colloidal material 

and the dissolved mineral solids most waters 

contain dissolved gases, chiefly nitrogen, oxygen, and carbon dioxide, and also carry clay 

and other material in suspension.

COLLECTION OF SAMPLES.

In most districts the collection of water samples for analysis is a simple matter, but in oil 

fields, where the universal aim is to shut the 

water out of the wells, it is often very diPcult. 

In wells used to supply water for industrial 

purposes the depth of the water sands if generally known and samples can of course be 

easily taken, but the waters that can be 

sampled in this way are few. Some of the oil 

wells produce water which is known to come 

from a certain depth, bu$ generally its exact 

source is unknown. In ,the Sunset-Midway 

field, where sharp variations in the character 

of the water may occur within short vertical 

distances, too much care can not be exercised 

in the collection of samples. After a sufF°ient 

number of authentic samples in any area have 

been collected and analyzed it will be possible, 

by comparison with these standards, to form 

an estimate of the probable source of any 

water found later in the same area.

tlsually authentic samples can be taken only 

while the well is being drilled or repaired. 

Flowing waters can of course be easily sampled, 

and the only precaution necessary is to let the 

water flow long enough before sampling to 

insure complete washing out of the drilling 

water from the hole. The collection of samples 

from a well that is being drilled by the standard 

method is not especially difficult, and samples 

uncontaminated by water from upper sands 

can generally be obtained after the drilling 

water has been bailed out. Under some conditions it is possible to obtain a fairly satisfactory 

sample merely by running the bailer to a point 

near that at which the water is entering the 

drill hole. When the circulating or the rotary 

system of drilling is used the proper collection
ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 53

of samples is often difficult or even impossible. 

Waters that flow when the pressure is released 

may be sampled at the expense of a little 

trouble, and if a string of casing is to be set 

within a short distance of a strong water sand, 

a sample of this water may be obtained while 

drilling is suspended. However, the rotary 

drill tends to mud up or plaster the walls of the 

hole and thus shut off flows of water, and if 

one of these flows breaks forth later the driller 

is likely to suppose that it comes from a deeper 

sand.

In view of these uncertainties it is evident 

that unless the location of the water can be 

positively determined its analysis should not 

bo used as a standard for exact comparison. 

For vhis reason it is the more desirable to collect samples carefully and label them accurately 

whenever good ones can be obtained, as when 

a flowing water is encountered.

CHEMICAL ANALYSIS. 

CONSTITUENTS TO BE DETERMINED.

The number of constituents to be determined in the analysis of water and the accuracy 

with which the work is done differ with the use 

to which the analysis is to be put, but in general the following determinations are desirable: 

Sodium (Na), potassium (K), calcium (Ca), 

magnesium (Mg), iron (Fe), aluminum (Al), 

sulphate radicle (SO4), chloride radicle (Cl), 

nitrate radicle (NO3), carbonate radicle (CO3), 

bicarbonate radicle (HCO3), silica (SiO2), and 

total solids at 180° C. It is well also to test 

waters from oil fields for sulphide (S) and for 

the gases hydrogen sulphide (H2S) and carbon 

dioxide (CO2). The quantity of suspended 

matter and the quantity of organic matter 

also are usually determined.

In industrial analyses, iron and aluminum 

are usually precipitated and weighed together 

and reported as the oxides (Fe2O3 +Al2O3), 

and carbonate and bicarbonate are often not 

distinguished from each other. The laborious 

determination and separation of sodium and 

potassium is omitted in many industrial analyses, and the content of these two substances 

together is calculated, after the acids and the 

other bases have been determined, by assuming the presence of sufficient sodium and potassium to complete the balance of reacting values 

between the bases and the acids. This practice

unfortunately conceals all analytical error 

and makes it impossible to ascertain the accuracy of the analysis from the reported 

figures.

STATEMENT OF ANALYSIS.

In analyzing a natural water the chemist can 

determine only the proportions of the mineral 

substances that it holds in solution. He can 

not determine what compounds have been dissolved, nor can he ascertain by the ordinary 

methods of analysis what compounds, if any, 

exist in the solution; his work is limited for 

the most part to the determination of the parts 

of compounds that are known as ions or radicles. Despite this limitation it is common 

practice to report not the radicles actually determined but the compounds of which they 

are thought to be a part, and these hypothetical combinations may be calculated by several 

methods, founded on different theories or devised from different points of view. As a 

result of this difference of opinion it is impossible to compare the results of one chemist with 

those of another until the analytical data have 

been reduced to a statement of all the radicles 

actually determined.

As there is no valid reason for reporting 

analyses in hypothetical combinations and as 

it is impossible to compare analyses so reported 

by different chemists, the analyses in this rep6rt have been calculated to the ionic form in 

order to show the amounts of the radicles 

actually found by the analyst. They have 

also been calculated to parts per million, the 

proportion most suitable for comparison, in 

order to avoid confusion due to the use of different units, such as grains per United States 

gallon, percentage, and parts per hundred 

thousand.1

REACTING VALUES.

The statement of a water analysis in ionic 

form in parts per million shows numerically 

the relative proportions of the several radicles 

by physical weight, in terms of gravity, and 

therefore is not a numerical representation of 

the water as a chemical reagent. A form of 

statement more convenient for study and comparison is that in reacting values, which shows 

numerically the relative proportions of the

1 The following factors are used in transforming results to parts per 

million: 1 grain per United States gallon=17.1 parts per million: one 

part per hundred thousand=10 parts per million; 1 gram per liter= 

1,000 parts per million; 1 per cent=10,000 parts per million.
54 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

radicles by chemical weight—in terms of reaction capacity. It is possible to calculate 

either form of statement from the other, because for each radicle there is a fixed ratio 

between physical weight and chemical reaction capacity, though the ratios for the several 

radicles are different and the relation between 

the two forms of statement is therefore complex. 

In order to translate an analysis from the 

ionic form into a form which expresses the 

chemical balance of the radicles, it is convenient to calculate the reacting values of the 

radicles. Stabler 1 has suggested that this be 

done by multiplying the weight of each radicle 

by its "reaction coefficient," which he defines 

as the chemical reacting power of a unit weight 

of the radicle. The reaction coefficient of a 

radicle in numerical value is the valence of the 

radicle divided by its weight on the atomic 

scale. 'The following table shows the reaction 

coefficients of the positive and negative radicles 

most commonly found in waters:

Reaction coefficients of radicles commonly found in waters.

Positive radicles. Negative radicles.

Sodium (Na)....... 0.0434

Potassium (K)..... . 0256

Calcium (Ca)...... .0499

Magnesium (Mg). .. .0821

Hydrogen (H)..... .992

Sulphate (SO4).... 0. 0208

Chloride (Cl)....... .0282

Nitrate (NO3)...... .0161

Carbonate (CO3).... . 0333

Bicarbonate (HCO3) . 0164 

Sulphide (S)....... .0622

The coefficients of silica, iron, and aluminum have been omitted from this table, as 

it is generally assumed that these substances 

are present as oxides in the colloidal state and 

therefore take no part in the chemical system 

of acids and bases. Stabler prefixes the letter 

r to the symbol of a radicle to designate its 

reacting value, and the same symbolization 

will be followed in this report.

When the weights of the radicles have been 

translated into their reacting values the chemical nature of the whole system becomes apparent. Comparison is further facilitated, 

however, if the reacting values are reduced to 

a percentage basis, and this computation has 

been applied to all the analyses here discussed. 

It will be observed that inasmuch as the sum 

of the positive radicles (bases) must be chemically equivalent to the sum of the negative

1 Stabler, Herman, The mineral analysis of water for industrial purposes and its interpretation by the engineer: Eng. News, vol. 60, p. 

365,1908; also chapter on the industrial application of water analyses 

in TJ. S. Geol. Survey Water-Supply Paper 274, pp. 165-181,1911.

radicles (acids), the reacting values of the two 

groups should be the same, each making- up 

50 per cent of the total.

As the figures representing the reacting 

values of the radicles have a greater chemical 

significance than those representing their 

weight, it is generally preferable to use the 

reacting values in comparing or studying analyses. Hence, statements in this report regarding the percentage of radicles present in 

waters refer to the percentage by reacting 

value, unless otherwise stated.

PROPERTIES OF REACTION.

Chase Palmer 2 has proposed a system for 

the classification and comparison of natural 

waters based on certain well-known properties 

of the solution as a whole, and his system is 

adopted in this report. The writer has fr'ind 

this mode of interpretation very valuable, for 

it sums up the detailed analytical statements 

in terms of a few properties, which furnish a 

convenient basis for the comparison of a large 

number of analyses. Although the properties 

are ordinarily calculated from the analytical 

statement, they may also be determined directly by testing the solution; hence they not 

only sum up the detailed analyses but also 

serve to bring out certain true chemical differences between waters which are fundamental 

in their geologic and industrial bearing;

When different salts are dissolved in water 

they impart different qualities to the solution. 

A simple solution of sodium carbonate, for 

example, is soft and alkaline; one of sodium 

chloride is neither alkaline nor acid, being 

neutral or saline; and one of calcium chloride 

is hard and saline. If the separate salt solutions are mixed the resulting solution still has 

definite properties acquired from those cf its 

constituents. In a mixed solution, however, 

it is no longer possible to state how much of 

each salt is present; reactions have taken 

place, and different combinations have resulted, and there is no possible way in which 

these combinations can be actually determined. The properties of the solution as a 

whole may be determined, however, or the 

amounts of the various radicles present may 

be determined by analysis and the properties

* Palmer, Chase, The geochemical interpretation of water analyses: 

U. S. Geol. Survey Bull. 479,1911. Rogers, G. S., The interpretation 

of water analyses by the geologist: Econ. Geology, vol. 12, pp. 56-88, 

1917.
ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 55

deduced from them. The reactive properties 

of the solution therefore depend essentially on 

the chemical balance existing between the 

radicles themselves.

In order to sum up the detailed analytical 

statement, radicles that are similar chemically 

and that impart similar properties to the solution are grouped together. Thus sodium and 

potassium fall in the alkali group, and calcium 

and magnesium in the group of alkaline earths. 

The common acid radicles are grouped as strong 

acids (chloride and sulphate) and weak acids 

(carbonate, bicarbonate, and sulphide). The 

balances that may exist between each two of 

these basic and acidic groups impart different 

properties to the solution. The presence of 

salts of the strong acids leads to salinity and 

that of salts of the weak acids to alkalinity. 

If the strong acids are in equilibrium with alkalies the salinity may be called primary salinity; 

if they are in balance with alkaline earths it 

may be called secondary salinity; similarly the 

balance between the radicles of the weak acids 

and the alkalies may be called primary alkalinity, and that between the radicles of the, weak 

acids and the alkaline earths secondary alkalinity. Most of these properties have long been 

recognized by water chemists; thus secondary 

salinity is. synonymous with permanent hardness, secondary alkalinity is practically equivalent to temporary hardness, and primary alkalinity has been called permanent negative 

hardness.

A water containing only one basic and one 

acidic group would evidently be characterized 

by only one property, but as most waters contain the members of all four groups, the' equilibria existing between them must be considered. Inasmuch as strong acids or bases 

"displace" weak acids or bases under ordinary 

conditions, the several groups may be balanced 

against one another in the order of their chemical strength or reactive power. In other 

words, the strong bases (alkalies) are balanced 

against the strong acids; the excess of either 

group is balanced against the weak bases or 

acids; and finally the remaining weak acids and 

bases are balanced together. 'A water containing members of all four groups will therefore be characterized by primary salinity and 

secondary alkalinity. If the strong bases exceed the strong acids and are therefore in equilibrium, with weak acids the water will have 

primary alkalinity; but if the reverse is true, 

the strong acids being in excess of the alkalies 

and therefore in equilibrium with alkaline 

earths, the water will have secondary salinity. 

These two properties are therefore incompatible; nearly all waters are characterized by 

one or the other, but no water can exhibit both.

The grouping of all waters as those having 

primary alkalinity (softness) or secondary salinity (permanent hardness) is one of the most 

valuable features of Palmer's system. This 

distinction is important in the study of the 

industrial value of waters and is also of geologic 

significance. The surface waters and the shallow ground waters in the Sunset-Midway field 

contain little carbonate but a high proportion 

of sulphate, balanced against roughly equal 

values of alkalies and alkaline earths, and they 

therefore invariably show secondary salinity. 

The waters associated with the oil in the western part of the field contain no sulphate but a 

high proportion of carbonate and of alkalies 

and are waters of primary alkalinity. The 

deeper waters in the central and western parts 

of the field contain no sulphate but are higher 

in alkaline earths and very low in carbonate 

and are waters of secondary salinity. By a 

study of the properties of the waters all the 

stages in their alteration and mixing can be 

traced and distinctions become apparent that 

do not suggest themselves in a study of the 

detailed analyses.

In addition to the three properties of reaction 

two other criteria for comparison are available. 

One of them is the ratio of the chloride to the 

sulphate radicles, for in Palmer's system these 

radicles are classed together as strong acids. 

As the strong acids give rise to salinity, chloride 

salinity and sulphate salinity may be distinguished, and these properties may conveniently 

be expressed as percentages of the total 

salinity. The other criterion is the concentration of the solution, or the total amount of dissolved solids. In general, the concentration 

of oil-field waters of any one type is fairly constant, but it may vary widely and therefore 

should not be lost sight of. For some waters 

it may also be desirable to determine the ratio 

of sulphate to carbonate, though in general 

this ratio is adequately expressed by the proportions of the properties of reaction.
56 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

SOURCE OF ANALYSES IN THIS REPORT.

In the tables given in the following pages the 

analyses of 74 waters from the Sunset-Midway 

region are given. These include all that the 

writer has been able to collect with the exception of a few that are duplicates or are obviously incorrect.

Of the 74 analyses given 29 were made by 

the Geological Survey, 27 by the Standard Oil 

Co. and the Kern Trading & Oil Co., and 18 

by industrial chemists. In most of those made 

by the Survey all the reported constituents 

were determined and the percentage of error 

may be computed. The others are partial 

analyses, the alkalies having been calculated 

by difference. The analyses made by the 

Standard Oil Co. and the Kern Trading & Oil 

Co. may be accepted as reliable and accurate 

within close limits. The remaining analyses 

are believed to be reliable, but they were 

doubtless made according to different standards 

of accuracy. They afford a good idea of the 

general character of the water, and in most of 

them the error is probably less than 5 per cent.

TYPES OF OIL-FIELD WATEKS.

CRITERIA FOR COMPARISON.

The chemical character of the substances 

dissolved in natural waters differs widely and 

several different types of water may be found 

in nearly every region. Owing to this wide 

variation in character it is often difficult to 

distinguish, without careful study, the significant differences from those that are more 

or less fortuitous, or more properly the differences that are due to determinable and fixed 

conditions from those which result from changing or indeterminable conditions. Moreover, 

waters may be classified from several different 

points of view, and in each classification the 

significance of different constituents may be 

emphasized.

Although the chemical character of oil-field 

waters has, in general, received little attention, 

several investigators in the Sunset-Midway and 

other fields have studied the waters and have 

attempted to classify them. E. A. Starke, of 

the Standard Oil Co., who has made the most 

comprehensive study, recognized several years 

ago that waters associated with the oil contain 

no sulphate and are likely to be high in carbonate. Other investigators have used as criteria for comparison such features as the concentration of the waters, the proportion of 

chloride, the ratio of calcium to magneHum, 

and the presence or absence of rarer inineral 

constituents, or of constituents derived from 

the petroleum itself, such as naphthenic acid. 

Some of these features are obviously poor 

criteria for scientific comparison, for they are 

controlled by factors that are indeterminable 

and that have no apparent relation to the 

presence of oil; others may in the future prove 

of value, but the data at hand are not sufficient to permit an estimate of their reliability. 

The carbonate and sulphate values used by 

Starve furnish a rational basis for the classification of the oil-field waters and at present 

constitute the most trustworthy indexes of 

their position with regard to the oil.

It should be emphasized, however, thr.t no 

single isolated constituent or ratio affords a 

sufficient basis for studying and comparing the 

oil-field waters; rational conclusions murt be 

based on a study of the complete analysis. 

The distribution and significance of all. the 

common constituents of the oil-field waters are 

accordingly outlined in the following section.

DISTRIBUTION AND SIGNIFICANCE OF THE 

CONSTITUENTS.

Alkalies.—The alkalies (sodium and potassium) are by far the most abundant bas°,s in 

the oil-field waters, and in the deeper waters 

from the west side of the field they and their 

equivalent acidic radicles constitute over 95 

per cent of the total mineral content. In the 

deeper waters from the Midway synclino the 

alkalies are somewhat less prominent. They 

usually predominate over' the alkaline earths 

in all waters from depths of more than 300 

feet, though in most surface waters the alkaline 

earths are present in slight excess.

Alkaline earths.—In many of the* surface 

waters and some of the shallow ground waters 

of the Sunset-Midway field the alkaline earths 

(calcium and magnesium) exceed the alkalies, 

but in all the deeper waters their relative proportion is low, not only because of the high 

concentration of the alkalies, as already explained, but also because the alkaline earths 

themselves are generally present only in rmall 

actual amounts. Large amounts of the earths 

can not be retained in waters in which more 

than a certain proportion of carbonate or bi-
TYPES OF OIL-HELD WATERS. 57

carbonate is present, and if this proportion is 

exceeded alkaline-earth carbonates are precipitated from the solution. In most of the 

shallower waters sulphate is high and carbonate 

low, and alkaline earths are therefore abundant 

constituents, but in the waters near the oil 

zone carbonate is high and the earths are 

accordingly low.

Sulphate.—In the normal ground waters 

everywhere on the west side of San Joaquin 

Valley sulphate is the predominating acid 

radicle, especially near the surface. In some 

of the shallow waters from the Sunset-Midway 

field sulphates constitute over 70 per cent of the 

total mineral content. Outside of the oil field 

most of the deeper ground waters also show a 

high concentration of sulphate, though the 

amount bears no constant relation to depth. 

Within the field, however, sulphate decreases 

with increasing depth and practically disappears at a certain distance above the oil zone. 

Many of the waters associated with the oil do 

not contain even a trace of sulphate, and most 

of them carry less than 0.2 per cent. The 

tables of analyses in this report show the ratio of sulphate to sulphate plus chloride by 

reacting value in all the waters discussed and 

also the ratio of sulphate to carbonate hi many 

of these waters.

The decrease of sulphate in the waters near 

the oil measures and its absence from the 

waters most closely associated with the oil are 

believed to be the result of chemical reaction 

with constituents of the oil or gas. The sulphate is probably reduced to sulphide or 

hydrogen sulphide, which may either escape 

as gas or undergo oxidation to free sulphur and 

so be lost by precipitation. The reduction of 

the sulphate is presumably attended by the 

oxidation of an equivalent portion of the hydrocarbon material to carbonate or carbon dioxide. 

These reactions are discussed in more detail on 

pages-60-61.

Chloride.—Chloride is a widespread constituent of terrestrial waters, but its concentration 

varies greatly. As the chlorides of all the common bases are highly soluble in water they are 

not important as rock-forming constituents and 

are concentrated chiefly in the ocean. A high 

concentration of chloride in ground water usually indicates that the water is partly of oceanic 

origin or that it has leached saline deposits.

The chloride in the Sunset-Midway waters is 

believed to be of oceanic origin, and its concentration depends on the extent to which the connate sea water has been admixed with meteoric 

water carrying sulphate or carbonate. This 

admixture is controlled largely by the freedom 

of the circulation. In the Midway syncline, 

where the geologic structure impedes circulation, the deeper waters are very salty. Near 

the surface, however, and on the west side of 

the field, near the outcrop of the beds, the connate water has been largely replaced by meteoric water and the concentration of chloride is 

therefore much lower.

Carbonate and bicarbonate.—In most nidustrial analyses no distinction is made between 

carbonate and bicarbonate, the two being 

grouped under the head of carbonate. Under 

ordinary conditions the two are more or less 

interchangeable; carbonate may be regarded as 

the primary radicle from, which, hi the presence 

of carbon dioxide, bicarbonate is derived. If a 

sufficient amount of carbon dioxide is present 

all of the carbonate radicle may be converted to 

bicarbonate, but a slight increase hi temperature or decrease hi pressure may drive part of 

the carbon dioxide from the solution, and thus 

cause a reversion to carbonate. A solution of 

calcium bicarbonate, for example, yields calcium carbonate on boiling. The bicarbonatesof 

calcium and magnesium are relatively soluble in 

water, whereas the normal carbonates are almost insoluble; hence, when the bicarbonate 

solutions are boiled and, by release of carbon 

dioxide, normal carbonate is formed, most of 

the normal carbonate is thrown out as a precipitate or "scale." As most surface waters 

can dissolve enough carbon dioxide from the 

air to form bicarbonate exclusively, it is generally assumed that practically all the carbonate reported hi analyses of surface water 

and shallow ground water represents bicarbonate in the solution.

Carbonate and bicarbonate are subordinate 

in amount to sulphate in most of the surface 

water on the west side of San Joaquin Valley 

and are generally present hi minor amount in 

the normal ground water. In the waters associated with the oil, however, they are generally 

more abundant, and when chloride is low carbonate and bicarbonate constitute the chief, 

acidic radicles.
58 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

Bromine and iodine.—Bromine and iodine 

have been detected in some of the oil-field 

brines, and iodine was determined quantitatively in one sample (analysis 9, p. 65) and 

found to amount to 29 parts per million. 

Many years ago Watts * reported 19.8 parts 

per million of iodine in water from one of the 

old Jewett & Blodgett wells in the Sunset 

field and stated that water from several other 

wells gave a "strong reaction" for iodine.

The presence of iodine and bromine in salty 

oil-field waters is usuaUy regarded as an indication that the waters have been derived from 

sea water. Ordinary sea water, however, contains 1,880 parts per million of bromine and 

only 2 to 2.4 parts per million of iodine, so 

that the proportion of the iodine in the oilfield waters has evidently been considerably 

raised. Mrazec,2 the foremost authority on 

the Rumanian oil fields, finds that all the waters 

in those fields contain appreciable amounts of 

iodine, whereas salty waters from nonoil-bearing regions carry bromine but little or no 

iodine. This relation appears to hold so 

widely in the Rumanian and neighboring oil 

fields that Mrazec regards the presence of 

iodine in water as an indication of the presence 

of oil. He explains the high concentration of 

iodine in oil-field water as compared with 

ordinary sea water on the ground that the 

sea water in which the petroliferous sediments 

were laid down must have been rich in certain 

organisms that are known to extract iodine 

from sea water and thus cause a local concentration. It is unfortunate that more attention has not been paid to the iodine and bromine in the Sunset-Midway waters, for if 

these constituents have a more or less definite 

relation to the oil a study of their distribution 

should be of direct economic value.

Sulphide.—Sulphide occurs in small amounts 

in many of the waters above the oil zone, and 

the presence of hydrogen sulphide has long 

been recognized by drillers as indicating a top 

water. The manner in which the sulphide is 

held in solution is usually not determined, but 

it is highly probable that in primary alkaline 

waters some of the sulphide is held in equilibrium by alkalies and perhaps by alkaline

1 Watts, W. L., The gas and petroleum yielding formations of the 

San Joaquin Valley of California: California State Min. Bur. Bull. 3, 

pp. 90-91,1894.

2 Mrazec, L., L'industrie du petrole en Boumanie, p. 20, Bucharest, 

1910.

earths. In some waters the acid sulphide 

(bisulphide) radicle (HS) is doubtless present. 

Both the normal and acid sulphide, however, 

tend to form the gas hydrogen sulphide (H2S), 

which is easily recognized by its odor and to 

which directly the term sulphur water is d'le.

Sulphide in the oil-field waters of S'an 

Joaquin Valley is probably formed by the 

reduction of sulphate. This reaction generally 

takes place a short distance above the main 

oil zone, and whether the sulphide radicle is 

first formed or not it is certain that hydrogen 

sulphide is produced in notable amounts. As 

hydrogen sulphide is a gas, it tends to rise to 

higher waters or to the surface, if it is free to 

migrate at ah1 , and the current belief that 

"sulphur waters" are top waters is therefore 

well founded. Like most generalizations, however, it must be applied with discretion, for 

when sulphate encounters smah1 amounts of oil 

or gas the sulphate may be partly reduced to 

sulphide and a sulphur water thus formed far 

below the oil zone.

Minor mineral constituents.—Iron and aluminum differ from the constituents already discussed in that they occur in most waters simply 

as hydrated oxides, which are supposed to be 

in the colloidal state rather than in true solution. They are rarely present in large amounts 

and generaUy do not affect the chemical aspects 

of the water.

Silicon is nearly always present as the colloidal oxide (silica) and may therefore be 

disregarded in a study of the reactive properties of the water. In waters of primary 

alkalinity it may enter the solution as silicate 

but probably soon breaks down into the colloidal form (SiO2). It varies greatly in amoTint 

in the oil-field waters but averages higher in 

waters showing primary alkalinity than hi 

brine.

Small amounts of several other constituents 

such as nitrate, phosphate, boron, and lithium 

are probably present in some of the waters, 

but they do not materially affect the character 

of the water and their determination is not 

essential to a study of the relations of the 

water to petroleum. Twenty-nine of the sr.mples whose analyses appear in Tables 14 to 

27 were tested for nitrate, but only six, of 

which four were surface waters, were found to 

contain it. A small quantity of boron was 

found in the only sample tested for it.
TYPES OF OIL-FIELD WATEBS. 59

Total mineral solids.—The total mineral 

solids present in a given quantity of water, or 

the concentration of the solution, varies widely 

in the different waters. Most of the surface 

waters in the vicinity of the field contain at 

least 1,000 parts per million, and most of the 

shallower ground water contains between 

1,000 and 3,000 parts. The concentration in 

general increases with depth but is governed 

to a considerable extent by the freedom of 

circulation. As the distribution of chloride is 

also affected by this condition marked variation in the total concentration of the deeper 

waters is usually associated with variation in 

the proportion of chloride. Thus the waters 

along the western edge of the field, where 

chloride is lowest, contain an average of about 

10,000 parts per million of total mineral solids, 

whereas the waters of the Midway syncline, 

which are high in chloride, average about 

30,000 parts. Although the concentration of 

the different types of water is fairly regular, 

individual samples may show considerable 

variation.

In the tables of analyses given in this paper the concentration is represented simply 

by the totals of the constituents reported except where bicarbonate is shown. Bicarbonate is unstable and tends to break down 

into carbonate when the solution is evaporated 

to dryness; hence, in accordance with convention, the bicarbonate radicle is not given 

its full value in the total but appears as 

carbonate.

Petroleum constituents.—In most industrial 

analyses petroleum constituents are not determined, but under the heading "Organic 

and volatile matter" is given the loss in weight 

when the solid matter obtained on evaporation of the water is heated to redness. The 

material thus lost includes whatever organic 

or hydrocarbon matter was present in the 

water but generally consists chiefly of carbon 

dioxide.

Certain minor constituents of petroleum or 

natural gas are soluble in water and have been 

observed in oil-field waters from several 

regions. Aside from the scientific interest 

that attaches to these substances they may in 

some places be of practical use, for their 

presence in a water has been taken by some to 

indicate that the water has been closely associated with oil or gas. The petroleum constituents soluble in water are of two kinds— 

simple light hydrocarbons, such as methane, 

and complex hydrocarbon derivatives, such as 

the naphthenic acids.

Methane and ethane are the predominating 

constituents of most natural gas, and water 

that has been in contact with gas is therefore 

likely to contain these hydrocarbons in solution. Their presence in water that is flooding 

an oil well is of little value in detennining the 

source of the water, as they are apparently 

rapidly soluble and may be taken up by the 

water while it is being raised to the surface. 

Their presence in the water from a wildcat 

well in which no oil or gas has yet been found 

might be taken as a suggestion of the proximity of petroleum but certainly could not be 

considered conclusive evidence.

The more complex hydrocarbon derivatives 

that are soluble in water are chiefly compounds containing oxygen, the commonest of 

which are probably the naphthenic acids. 

These compounds are the oxygen derivatives 

of the naphthenes (polymethylenes) and have 

the general formula CnH-jn-gO.}. In alkaline 

waters these acids are doubtless present as 

alkali salts rather than as free acids.

So far as the writer is aware no attempt has 

been made to study the petroleum acids in 

California oil-field waters, although W. E. 

Perdew, formerly with the Kern Trading & 

Oil Co., and others have detected them in 

certain waters from the Sunset-Midway and 

Coalinga fields. The answer to the question 

whether the presence or absence of these substances in a water may serve to determine the 

position of the water with respect to the oil 

zone obviously depends on the ease and rapidity 

with which water can dissolve the acids from 

the petroleum. If top water leaking down 

behind the casing and mixing with the oil can 

dissolve petroleum acids before it is pumped 

out such a distinction would be entirely misleading. It is probable that the chemical 

character of the water has much to do with 

its ability to dissolve the acids. As the alkali. 

salts of the naphthenic acids are readily soluble 

in water, it may be inferred that alkali carbonate water of the type associated with the 

oil in the western part of the Sunse1>-Midway 

field is readily able to dissolve the acids when 

brought into contact with oil containing them. 

The acids are practically insoluble, however,
60 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PAKT II.

in strong solutions of sodium sulphate, and 

therefore they are probably much less readily 

soluble in the strongly sulphate top waters. 

Until the rapidity with which naphthenic 

acids are extracted by different types of water 

is investigated their value as indicators of the 

original position of a water with respect to 

the oil is open to question.

The water to be tested is first acidulated with hydrochloric acid and well shaken with benzine, which extracts 

all organic acids, leaving all the sulphur behind. The 

benzine solution is then separated, repeatedly washed 

with warm water, and filtered. To the filtrate is added a 

few cubic centimeters of a solution of copper sulphate and 

three or four drops of piridine or of a strong ammoniac 

solution, and the mixture is well shaken. A green coloration of the benzine on top of the testing tube showr the

Concentration (total solids) 

in parts per million

X Less than 3.000

0 3,000 to 20,000

 More than 20,000

Numbers refer to analyses 

in Tables 14 to Z~l

a represents position of

Nos. 16,38,41,42,43, and ^6 

b, Nos. 5.16, and 47 

C, Nos. 9,18,45, and 48

FIGUBE 4.—Diagram showing proportions of sulphate (SO4 ), carbonate and bicarbonate (CO3+HCOS), and chloride (CI) in the oil-field waters. 

The proportions of each constituent are plotted in percentage reacting values and therefore aggregate 50 per cent.

presence of petroleum acid in the tested water, anc1 the 

degree of coloration allows to judge of its quantity.

The presence of organic acids in alkaline 

waters may be determined by acidulating the 

water. Organic acids, if present in moderate 

amounts, appear as a milky precipitate, but in 

some waters they are so abundant that they 

separate out in large oily globules. Many of 

the waters near the oil measures respond to 

this reaction. The following more conclusive 

test, devised by Kharitschoff,1 may be of value 

to those who desire to examine oil-field waters 

for petroleum acids:

1 Kharitschoff, K. V., Petroleum acids in boring waters: Petroleum 

Kev., vol. 28, p. 380,1913.

GENERAL CLASSIFICATION.

As all natural waters are mixtures, it is impossible to classify them rigorously, and any 

system of classification is a matter of convenience rather than of fixed principles. It 

is evident that for practical convenience oilfield waters should be classified as far as possible according to their position in relation to 

the oil. As the surface or shallow gronnd 

waters, together with the deeper ground waters
TYPES OF OIL-FIELD WATERS. 61

outside the oil fields, are high, in sulphate, 

whereas waters close to the oil are practically 

free from sulphate, the proportion of sulphate 

furnishes the most rational single basis for classification. On this basis waters high in sulphate 

and evidently unaffected by contact with oil 

may be called normal waters and those free from 

sulphate may be called altered waters. It is 

convenient also to recognize an intermediate 

group which may be called modified waters.

When sulphate is removed from a water 

through reaction with oil carbonate is apparently introduced, and if the waters contained 

only these two acid radicles the ratio between the 

two would furnish an adequate basis for classification. As most oil-field waters, however, 

contain large amounts of chloride the proportion of this constituent must generally be taken 

into account. Figure 4 shows the proportions 

of sulphate, carbonate (and bicarbonate), and 

chloride in all the'waters whose analyses are 

given in this report. This three-cornered diagram is based on the fact that as sulphate, 

chloride, and carbonate constitute the only 

acid radicles in most waters their reacting 

values must equal the sum of the reacting values 

of the basic radicles.1 A water consisting entirely of sulphates would fall at the upper apex 

of the triangle; one consisting entirely of carbonates and bicarbonates would fall at the 

lower left-hand apex, and one consisting of 

sulphates, carbonates (or bicarbonates), and 

chlorides in equal proportions would fall at 

the center of th,e triangle. All the surface and 

shallower ground waters in the Sunset-Midway 

field and the deeper ground waters outside of 

the field therefore fall in the upper or central 

part of the triangle, whereas the altered waters 

that contain no sulphate fall on the base line. 

It is evident that chloride is the predominating 

constituent in most of the altered waters and 

that it can not properly be ignored in classifying 

them.

Although the three-cornered diagram affords 

a convenient means of comparing the proportions of the three acidic radicles in waters, a 

more complete classification may be made on 

the basis of the properties of reaction. Practically all the waters high in sulphate are low in 

carbonate and high in alkaline earths and are

i This type of diagram has been used by W. H. Emmons in discussing 

mine waters. (The enrichment of ore deposits: TJ. S. Geol. Survey 

Bull. 625, pp. 83-86, 1917.)

therefore characterized by secondary salinity. 

As the sulphate diminishes and the carbonate 

increases the secondary salinity decreases to 

zero and primary alkalinity appears. Normal 

waters therefore have secondary salinity, 

whereas modified and altered waters may have 

either primary alkalinity or secondary salinity, 

their character depending on the proportions of 

carbonate and chloride. All the waters containing more than 8 per cent of carbonates (see 

fig. 4) have primary alkalinity, whereas those 

consisting almost entirely of chlorides have secondary salinity. Without considering for the 

present the conditions that govern the respective proportions, of carbonate and chloride, the 

altered waters containing no sulphate may be 

divided into two groups—the brine, which is 

high in chloride and shows secondary salinity, 

and the mixed waters, which contain less chloride and show primary alkalinity. The chemical characteristics of representative waters of 

these classes are considered in the following 

section.

WATERS OF THE NORMAL TYPE.

To the normal type belong the surface waters 

and the shallow ground waters of the SunsetMidway field and the deeper ground waters 

outside the field. As the chief criterion of a 

normal water is by definition a high content of 

sulphate, it is apparent that waters of more or 

less diverse composition in other respects may 

be grouped under this head. Within the field, 

however, the type is very distinct. Normal 

waters are characterized by the presence of 

secondary salinity; by a high percentage of 

sulphate, with carbonate and chloride generally 

subordinate; by alkaline earths about equal to 

or predominating over the alkalies; and generally by a concentration of less than 3,COO 

parts per million.

Analyses 1 and 2, Table 14 (p. 63), are representative waters of the normal type; Analysis 1 represents spring, water issuing from the 

Maricopa shale in the hills a short distance west 

of the field. The sulphate salinity, or the percentage of rSO4 in rSO4 +rCl is very high, and 

the ratio of carbonate to sulphate is very low. 

The water shows very strong secondary salinity 

and has a fairly high proportion of secondary 

alkalinity—in other words, the strong acids 

(SO4 and Cl) exceed the weak acids (CO3) in
62 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

reacting value, and the alkaline earths exceed 

the alkalies. The concentration of this water, 

2,334 parts per million, is very high for surface 

waters in most regions but is not much higher 

than the average in the Sunset-Midway field. 

Other analyses of this type of water are shown 

in Table 18 (p. 81).

Analysis 2 represents water from a shallowwater well at the east end of the Buena Vista 

Hills. The carbonate-sulphate ratio is even 

lower than in the spring water represented by 

analysis 1, being only 0.09. The sulphate salinity is also slightly lower, but this is due to the 

increase of chloride rather than to decrease of 

sulphate. As the concentration is about double 

that of the shallower water the actual amounts 

of most of the constituents are higher, but the 

most marked rise is in the chloride. The alkaline earths are lower in relative proportion, and 

the alkalies are correspondingly higher. These 

variations are summed up in the properties of 

reaction. The primary salinity in analysis 2 is 

considerably higher than in analysis 1 owing to 

the increase of chloride and the alkalies; the 

secondary salinity is somewhat lower, and the 

secondary alkalinity is very much lower owing 

to the decrease in carbonate and alkaline earths. 

Other analyses of this type of water are shown 

in Tables 15 (p. 65) and 19 (p. 82).

WATERS OF THE MODIFIED TYPE.

The modified type includes the waters lying 

below those of the normal type and above those 

of the altered type, or, in general, the waters 

several hundred feet or more away from the oil 

measures. The type is characterized by low 

secondary salinity or by primary alkalinity; 

by a lower ratio between sulphate and both 

carbonate and chloride than in the normal type^ 

and by the predominance of alkalies over alkaline earths.

Analysis 3, Table 14, represents a slightly 

modified water. The sulphate salinity is much 

lower than in the normal waters, being only 

30.6 per cent, and hydrogen sulpliide, which 

indicates alteration, is present. The secondary salinity of this water is very low in comparison with that of the normal waters; in 

other words, the water is characterized by 

lower sulphate and alkaline earths and by 

higher chloride and alkalies. As the water is

derived from a depth of 1,090 feet the increase 

in chloride is to be expected, though the total 

concentration of the water is unusually low.

Analysis 4 represents a very strongly modified water that is more typical of the modif sd 

group. This water is still lower in sulphate a nd 

is higher in carbonate, the sulphate salinity 

being only 10.3 per cent and the carbonatesulphate ratio being 4.2. This water, like Fo. 

3, contains hydrogen sulphide. The alkaline 

earths are much lower than in the shallower 

waters, and the alkalies are much higher. These 

changes are summed up in the properties of 

alteration; the water is one of primary alhalinity and not of secondary salinity like those 

discussed above and is characterized by moderate primary salinity and low secondary all'alinity. The concentration of this water, 7,040 

parts, is about the average for a water of this 

type. Analyses of other modified waters are 

given in Table 20 (p. 83).

WATEES OF THE ALTERED TYPE.

All the waters occurring in or vertically 

below the oil measures belong to the altered 

group, and the waters for some distance above 

the oil are usually also altered. The distance 

to which the zone of alteration extends above 

the oil depends largely on the local geolojry. 

Waters occurring a short distance above oil 

zone A are in general strongly modified but are 

not completely altered. The waters occurring 

in zone A (edge waters) are of the altered tyne, 

however, and as these waters replace the oil 

entirely down the dip they become the top 

waters of zone B. Similarly, the edge waters' of 

zone B may, farther down the dip, become the 

top waters of zone C. It is evident, therefore, 

that waters several' hundred feet above the 

producing zone in the central part of the fnld 

may in reality be edge waters of a higher oil 

zone and therefore just as completely altered 

as if they occurred in or below the producing 

zone itself. Hence along the western edge of 

the field, where the zone of alteration extends 

only a short distance above the oil sands, top 

waters may readily be identified by their 

chemical character, but in the central pr,rt, 

where the zone of alteration extends much 

higher, only those top waters occurring 700 

feet or so above the oil can be so identified.
TYPES OF OIL-FIELD WATERS. 

TABLE 14.—Types of ground water from Sunset-Midway field.

63

PROPERTIES OF REACTION IN PER CENT

Primary salinity. ....................

Secondary salinity. ....................

Per cent of rS04 in rS04+rCl. .........

Ratio of rC03+rHC03 to rSO4 . .........

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na) .........................

Potassium (K). . ......................

Calcium (Ca). ........................

Iron oxide (Fe2O3 ) and alumina (A12O3) . 

Sulphate (SO4). ......................

Chloride (01).... ......................

Nitrate (N03) ........................

Bicarbonate (HCO,) ..................

Silica (Si02)............ ...............

REACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths: 

Calcium (rCa) ....................

Magnesium (rMg) .................

Strong acids: 

Sulphate (rS04). .................

Chloride (rCl)....... ..............

Nitrate (rN08).....................

Weak acids: 

Carbonate (rC03) ..................

Bicarbonate (rHC03)...............

Normal.

- 1

14.4 

70.4 

0 

15.2

94.9 

.19

} 117

444 

107

1,393 

50 

8 

0 

335 

50

2,3340 •

| 7.2

30.7 

12.1

40.2 

2.1 

.1

0

7.6

o

54.0 

40.4 

0 

5.6

70.8 

.09

« 867

404 

144 

22 

2,205 

671 

60 

*> 116

4,489 

0

&27.0

14.5 

8.5

32.9 

13.6

.7

&2.8

Modified.

3;

90.2 

3.4 

0

6.4

30.6 

.22

( 911 

1 8.4 

23 

39

605 

1,013

0

175 

32

2, 717. 4 

Present.

( 44.7 

I -4

1.3 

3.6

14.3 

32.5

0 

3.2

4

70.2 

0

27.2 

2.6

10.3

4.2

a 2, 710

40 

15

420 

2,660

b 1,100

90

7,040 

Present.

I a 48. 7

.8 

.4

3.6 

31.5

&15

Altered.

5

86.6 

12.2 

0 

1.2

0

00

11, 160 

124

848 

425

0 

20,694

48 

359 

102

33, 578 

0

/ 43.0 

I -3

3.7 

3.0

0 

49.4

.1

.5

G

65.0 

0 

32.2 

2.8

0.3 

17.5

3,747 

99 

40 

35 

11 

22 

3,924

0

3,672 

122

9,807 

0

47.8 

.8

.6 

.8

.1 

32.4

0 

17.5

7

22.4 

0 

60.4 

17.2

Trace. 

8

« 1, Oil

56

77

Trace. 

421

b 1,236

Trace.

2,800 

Present.

(• o 41. 4

2.6 

6.0

11.2

Z>38.8

o Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

1. Crocker Spring, Bee. 18, T. 31 S., R. 22 E. Spring issues from Maricopa shale. Sampled by G. S. Rogers, 

September, 1915. Analyst, S. C. Dinsmore.

2. Pyramid Oil Co., water well, 80 feet deep, in sec. 18, T. 32 S., R. 25 E. Analyst, Kern Trading & Oil Co.

3. August Water Co., California Amalgamated well 2, sec. 35, T. 32 S., R. 23 E. Sulphur water from depth of 

1,090 feet in Maricopa shale and therefore below oil measures. Sampled by G. S. Rogers, July, 1914. Analyst, 

Chase Palmer.

4. Ida May water well, SW. f sec. 2, T. 11 N., R. 24 W. Sulphur water chiefly from depth of about 1,500 feet 

(in Maricopa shale) but probably in part from depth of about 500 feet, or above highest oil sand. Analyst, F. T, 

Green, August 27, 1912. Authority, Ida May Oil Co.

5. Mays Consolidated Oil Co., well 6, sec. 28, T. 31 S., R. 23 E. Flowing water from depth of 3,000 feet, or a 

short distance beneath oil sand in upper part of zone C. Sampled by G. S. Rogers, September, 1915. Afaalyst, S. C. 

Dinsmore.

6. Tamalpais Oil Co., well 3, sec. 25, T. 32 S., R. 23 E. Water pumped with oil; probably edge water in upper 

part of zone A (1,223 feet). Sampled by G. S. Rogers, August, 1914. Analyst, S. C. Dinsmore.

7. Potter Oil Co., well 2, sec. 15, T. 31 S., R. 22 E. Water from lower part of tar sand zone. Analyst, Smith, 

Emery & Co., May, 1915. Authority, Potter Oil Co.
64 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

Analyses 5, 6, and 7, Table 14, represent 

waters of the altered type. These waters differ 

in many respects from one another, but their 

common and most striking characteristic is the 

practical absence of sulphate.

Analysis 5 represents a brine of the type 

associated with the oil throughout the central 

and eastern parts of the field. This water is 

very different from those already described, 

having a very high content of chloride and 

alkalies. Alkaline earths are fairly high, and 

carbonate is very low. The water is therefore 

characterized by secondary salinity, with high 

primary salinity and very low secondary alkalinity. The concentration of waters of this 

type usually ranges between 30,000 and 40,000 

parts per million. Other analyses of such 

waters are given in Tables 21, 22, and 23 (pp. 

84-86).

Analyses 6 and 7 represent altered waters of 

the mixed type. These waters are much less 

concentrated than the brine and show proportionately lower chloride and alkaline earths and 

much higher carbonate. They are, therefore, 

waters of primary alkalinity. No. 6 is a good 

example of the type of water associated with 

the oil along the western edge of the field; No. 

7 has more pronounced primary alkalinity and 

has been recognized only in the northern part 

of this belt. Many other analyses of waters of 

the mixed type are given in Tables 24 to 27 

(pp. 88-91).

ORIGIN AND RELATIONS OF THE TYPES. 

ORIGIN OF THE ALTERED (STTLPHATE-FREE) WATER.

Inasmuch as the normal ground waters everywhere on the west side of San Joaquin Valley 

show a high content of sulphate and the only 

known waters containing no sulphate are those 

associated with the oil, it is reasonable to suppose that the sulphate-free waters have been 

derived from the others through chemical 

reaction with the oil. The reactions that may 

take place and the corroborative evidence 

afforded by a study of the changes in the character of the oil itself have been discussed on 

pages 26-32. The sulphate is supposed to be 

reduced to sulphide by certain constituents of 

the oil, which are themselves simultaneously 

oxidized to products that eventually yield 

carbonate. The action of oil upon water may 

therefore be considered roughly as resulting in 

the substitution of carbonate for sulphate.

Although no suites of analyses showing the 

complete alteration of waters are availal lo-, 

analyses of water from different depths in three 

wells are given in Table 15. Nos. 8 and 9 f nd 

Nos. 10 and 11 represent waters from different 

depths in two oil wells, and Nos. 12 and 13 

represent waters from a well outside the oil 

field and therefore show the normal change in 

depth in waters unaffected by oil or gas. 

Analysis 8 represents water occurring between 

350 and 790 feet, and analysis 9 the water 

occurring at 2,505 feet, or below the top oil 

sand, in the same well. No. 8 is an ordinary 

water of the normal type, having sulphate considerably in excess of chloride and greatly in 

excess of carbonate. As the alkaline earths' in 

this water are unusually low, the water shows a 

slight degree of primary alkalinity. No. 9 is an 

ordinary altered brine of the type associated 

with the oil everywhere in the central and eastern parts of the field. Its concentration is 

about 15 times as great as that of the up^er 

water, and all the constituents are present in 

correspondingly greater amount, except nilphate, which is completely lacking, and carbonate, which has about the same value. 

These two wa'ters, which are vertically about 

2,000 feet apart, thus represent the extremes, 

and analyses of the modified waters that undoubtedly occur at the intermediate levels are 

unfortunately not available.

Analyses 10 and 11 represent waters,of the 

mixed type found along the western edge of 

the field. No. 10 is a modified water occurring 

below tar sands but 600 feet above the highest 

oil sand; No. 11 is an altered water occurring: 30 

feet above the highest oil sand, or 570 feet vertically below No. 10. As would be expected, 

the differences between these waters are much 

less marked than those between Nos. 8 and 9, 

which occur 2,000 feet apart, though the 

character of the changes is the same. The per 

cent of sulphate decreases from 0.8 in the 

upper water to 0.1 in the lower, the sulphate 

salinity decreases from 2.3 to 0.2, and the ratio 

of carbonate to sulphate increases from 20 to 

165. The properties of reaction show only a 

slight change, though the concentration of the 

lower water is more than double that of the 

upper. Water from beds below the lowest oil 

sand in the section to the west is practically 

identical with No. 11, except that sulphate is 

completely lacking and that the total concentration may be higher. (See Tables 25 and 26, 

pp. 89-90.)
TYPES OF OIL-FIELD WATERS. 65

TABLE 15.—Analyses of ground water from different depths, showing change in character as oil is approached, and normal

change with depth.

PROPERTIES OF REACTION IN PER CENT.

Primary salinity. ...............................

Secondary alkalinity. ............................

Per cent of rSO4 in rSO4 -j-rCl. ...................

Ratio of rCO3+rHCO3 to rSO4 .. ...................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na) ....................................

Iron (Fe). .......................................

Sulphate (SOJ..... - ............................

Chloride (01)............... ........ .'.............

Iodide (I). .....................................

Nitrate (NO3).. . ................................

Carbonate (CO3). . ................................

Bicarbonate (HCOg ).. . ..........................

Silica (SiO2)....... . ............................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa).. . ............................

Potassium (rK). . ............................

Alkaline earths: 

Calcium (rCa). . .............................

Strong acids: 

Sulphate (rSO4)... . .........................

Chloride (rCl)...... ..........................

Nitrate (rNO3). . ............................

Weak acids: 

Carbonate (rCO3) .............................

Bicarbonate (rHCO3 ). . ......................

Wells in oil field.

8

87.4 

0 

3.4 

9.2

60.2 

.29

719 

9.5 

39

22

879 

429

32 

170 

44

2, 257. 5

45.0

.4

2.8 

2.6

26.3

17.4

1.5

4

9

83.6 

16.0 

0

.4

0

11, 176 

86 

1,100 

503

0

20,421 

29 

45 

0 

162

33,440

41.6 

.2

4.7 

3.5

0 

49.7 

.1

0 

.2

10

68.6 

0

28.6 

2.8

2.3 

. 20

« 1, 059

11 

9.6 

1.7 

38 

1,125

&443

12

2, 699. 3

«48.6

.6 

.8

.8 

33.5

&15.7

11

67.0 

0

31.8 

1.2

0.2

165

a 2, 809

26 

2.9

8.7 

2,920

& 1, 226

17

7, 009. 6

a 49. 4

.5 

.1

.1 

33.4

&16.5

Well in which no oil 

or gas has been found.

12

64.6 

24.0 

0 

11.4

80.0 

.16

«544

124 

82

1,243 

232

&i25

57

2,407

« 32. 3

8.5 

9.2

35.3 

9.0

&5.7

13

91.2- 

0 

6.6 

2.2

76.0 

.13

a 3, 000

28 

19 

Trace. 

4,421 

1,040

6355

29

8,892

a 48. 9

.5 

.6

34.6 

11.0

&4.4

a Reported and calculated as sodium but includes potassium.

& Reported and calculated as carbonate but probably in part bicarbonate.

8, 9. Mid-way Northern Oil Co. well in sec. 32, T. 12 N., R. 23 W. Sampled by G. S. Rogers, August, 1914. 

Analyst, Chase Palmer. 8, Water from sands between 350 and 790 feet; 9, water from sand at depth of 2,505 feet, 

or below top oil sand and about 100 feet above second oil sand.

10,11. Standard Oil Co. well in sec. 30, T. 32 S., R. 24 E. Sampled while drilling and analyzed by Standard 

Oil Co. 10, Water from depth of 1,380 feet, or below tar sands of zone A and 600 feet above top of highest oil sand 

in zone B; 11, water from depth of 1,947 feet, or SO feet above top of highest oil sand in zone B and 120 feet above 

top of main producing oil sand.

12, 13. Standard Oil Co. well Domengine No. 1, several miles north of the Coalinga oil field. No. 12 represents 

water from depth of 370 feet; No. 13, water from depth of 3,700 feets at which no oil or gas had been encountered. 

These analyses probably represent the normal changes that occur with increasing depth in waters unaltered by oil. 

Analyst, Standard Oil Co.

110973°—19——5
66 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PAKT II.

Analyses 12 and 13 represent waters encountered at 370 and 3,700 feet, respectively, 

in a well drilled several miles north of the 

Coalinga oil field. No oil or gas was encountered in the well, which was drilled to a depth 

several hundred feet below the level of the 

lower water. Both waters are unaffected by 

hydrocarbons, and their analyses may therefore be considered as showing the normal 

changes that take place with increasing depth. 

It will be noted that although the concentration of the lower water is nearly four times 

that of the upper, the proportion of sulphate 

is almost exactly the same; the sulphate 

salinity of the upper water is 80 per cent and 

that of the lower 76 per cent, and the carbonate-sulphate ratio in the upper water is 0.16 

and in the lower 0.13. There is a slight difference in the properties of reaction, owing to 

the fact that the alkaline earths are lower in 

the deeper water, but the similarity in sulphate content despite the great change in 

concentration is striking.

Analyses of water from other deep wells 

outside the oil fields are not available, but 

Dole,1 after a careful chemical study of the 

waters of San Joaquin Valley, finds that 

although the proportion of sulphate bears no 

constant relation to depth, the deep as well as 

the shallow waters on the west side of the valley are invariably high in sulphate.

ORIGIN OF THE BRINE.

Owing to the fact that underground waters 

in a region of sedimentary rocks tend to follow 

the bedding planes, the structure of the rocks 

has a considerable effect on the freedom of the 

circulation, which in turn influences the 

chemical character of the waters themselves. 

If salt water, for example, is present in the 

strata before they are folded, some of it may 

be trapped hi structural troughs or basins and 

held there indefinitely. Although all the 

water in the Sunset-Midway field is more or 

less salty, the very salty water belonging to 

the well-defined chemical type here called 

brine occurs only in the Midway syncline or 

on the anticline to the east—localities in 

which the circulation is naturally restricted.

1 For a complete account of the underground waters of San Joaquin 

Valley, see Mendenhall, "W. C., Dole, E. B., and Stabler, Herman, 

Ground water in San Joaquin Valley, Calif.: U. S. Geol. Survey WaterSupply Paper 398,1916.

This water may be regarded as fossil sea vater, 

entrapped in the sediments when they were 

laid down and only slightly altered by contact 

with the surrounding rocks.

When sediment is deposited on the flcor of 

the sea it is saturated with sea water, which 

remains in the pores until it is elevated to 

form land. The compacting of the material 

necessarily forces out a large quantity of ibis 

water, but that remaining ordinarily filh the 

pore spaces of the rocks after they have assumed their normal bulk. Uplift, however, 

causes circulation of the water to commence, 

and meteoric or rain water falling or the 

newly elevated land surface enters the beds 

and tends to dilute and force out the connate 

water—the sea water entrapped in the sediments. This replacement takes place with 

considerable rapidity under some conditions, 

but under others the connate water may 

remain trapped for long periods of time. The 

freedom of the outlet by which the salt water 

may escape is the chief factor, for water 

trapped in a lens of sand entirely inclosed 

by shale might remain there indefinitely. 

Similarly, as circulation follows bedding planes, 

if the strata are folded into a closed basin or 

trough, some of the water will accumulate in 

its deepest portion and remain there. YHiere 

the outlet is not entirely closed but is merely 

restricted other conditions have an influence, 

such as the volume and the head of the meteoric waters that are tending to drive out the 

connate water, the porosity of the materials 

through which the waters must pass, and the 

dip of the rocks and the distance from their 

outcrop. Even where all the conditions are 

favorable to the retention of the salt water it 

is evident that some of it near the surface will 

be leached out and that, other things being 

equal, the largest proportion will be retained 

at the greatest depths. In a region of lenticulaf beds, however, irregularities are to be 

expected, for the freedom of circulation differs 

from bed to bed and therefore some sands will 

retain their salt water much longer than others.

It has already been pointed out that in a 

hydrologic sense the most important structural 

feature of the Sunset-Midway field is the Midway syncline, which with the Buena Vistr. and 

associated anticlines to the east forms a deep 

wrinkle or crenulation in the general mono-
TYPES OF OIL-FIELD WATEES.

clinal slope of the west side of San Joaquin 

Valley. If the valley is regarded as a great 

open trough with these folds perched high on 

its western rim, it becomes evident that the 

syncline constitutes a trap which acts not 

only to pond water within itself but also to 

impede circulation across the anticline to the 

east. As the Maricopa and Etchegein formations were laid down in salt water and were 

thoroughly saturated with it when they were 

elevated above the sea, it is entirely reasonable 

to suppose that some of this water would be 

trapped in the syncline when the beds were 

folded and would remain there indefinitely. 

Rain water falling in the western part of the 

field and entering the beds has naturally 

driven out most of the salt water in the belt 

along the outcrop and has mingled with and 

partly replaced the salt water in the belt still 

farther from the outcrop, but it has apparently 

never penetrated to the deeper portion of the 

trough. A large volume of rain water acting 

through a long period of time might eventually 

replace the connate water entirely, but it must 

be remembered that the region is arid and that 

the beds are geologically young.

As water in contact with rock tends to 

change in character, it can not be expected 

that fossil sea water will long retain exactly its 

original composition. Water entrapped in the 

older rocks, such as the Paleozoic strata of the 

Appalachian oil fields, may have changed so 

materially that its origin, so far as chemical 

evidence goes, may be in doubt, but the salt 

water in the Midway syncline is so similar to 

sea water that there can be little doubt that it 

is fossil sea water. The principal differences in 

composition are due entirely to the removal of 

the sulphate through the action of oil.

The reaction between sulphate-bearing water 

and petroleum results essentially in the substitution of carbonate for sulphate, and although 

the exact proportion between the sulphate removed and the carbonate introduced is not 

known, it may be assumed for the present that 

the values are equivalent. In unaltered sea 

water sulphate and chloride exceed the alkalies 

in reacting value and are therefore partly in 

equilibrium with the alkaline earths; hence if 

carbonate is substituted for the sulphate the 

alkaline earths will be partly in equilibrium 

with carbonate. Only a small amount of 

earths and carbonate can be retained in solution, even in the presence of an excess of 

carbon dioxide, and if this amount is exceeded 

alkaline-earth carbonates will be formed and 

then lost through precipitation. In a concentrated solution like sea water the maximum of alkaline earths balanced by carbonate 

that can be retained represents only a very 

small percentage of the total concentration, 

and if the sulphate is entirely replaced by 

carbonate a large proportion of this carbonate, 

with an equivalent value of earths, will be precipitated. 1 The effect on the properties of reaction of this substitution and consequent loss 

therefore consists in a decrease in secondary 

salinity and an increase in secondary alkalinity 

limited by the solubility of the alkaline-earth, 

carbonates. Sea water has 21.1 per cent of 

secondary salinity, of which 9.3 per cent is contributed by sulphate; hence the removal of the 

sulphate will effect a substantial reduction in 

the secondary salinity. The increase" "in secondary alkalinity, however, will be slig^ so 

that if the properties are expressed in percentages the primary salinity will be raised. If it is 

assumed, first, that the sulphate in sea water 

is entirely removed and an equal proportion of 

carbonate introduced, and second, that 8.0 per 

cent, or 2,800 parts per million, of alkalineearth carbonates is lost through precipitation, 

the properties will change as follows:

Changes in properties of sea water through substitution of 

carbonate for sulphate.

Normal sea water (see analysis 19, Table 16)..........

Sea water in which all SO4 

is calculated as CO3 ........

Same after precipitation of 

assumed excess of alkalinePrimary salinity {per 

cent).

78. 6 

78. 6

85.4

Secondary salinity (per 

cent).

21.1 

11.8

12. 8

Secondary alkalinity 

(per 

cent).

0.3 

9.6

1.8

Concentration 

(parts 

per 

mfflion).

35,000 

35, 000

32,200

The similarity between the properties of the 

altered sea water, as thus deduced, and those 

of the oil-field brines leaves little doubt that 

the brines are simply fossil sea water modified 

chiefly through the removal of sulphate and 

the accompanying precipitation of alkaline1 Murray, John, and Irvine, Robert, On the chemical chtoges which 

take place in the composition of the sea water associated with blue 

muds on the floor of the ocean: Roy. Soc. Edinburgh Traus., vol. 37, 

p. 481, 1893.
68 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

earth carbonates. The properties of some of 

the brine samples analyzed check almost exactly with those of the altered sea water. (See 

analysis 5, p. 63.) Most of the samples, however, show 1 or 2 per cent more secondary 

salinity than simple altered sea water, an 

excess which may indicate that the value of 

the carbonate introduced is not quite equivalent to that of the sulphate removed. Any 

attempt to reduce these reactions to exact 

figures, however, is admittedly speculative. 

It would be strange indeed if the properties of the brines were identical with those 

of altered sea water, as calculated above, for 

the figures used represent the average composition of sea water from all parts of the world. 

The waters of a deep embaynaent, such as the 

San Joaquin Valley was during the middle 

Tertiary time, are almost certain to depart 

somewhat from this average. If the region is 

arid the waters may become more concentrated through evaporation and may deposit 

calcium carbonate and gypsum, whereas if 

many rivers empty into the basin, its waters 

may become more dilute and may be locally 

modified in composition by admixture with 

the river water.

There are two minor differences in composition between the brines and sea water, which are 

not explained by the removal of the sulphate, 

namely, the deficiency in the brines of potassium 

and magnesium, as compared with sodium and 

calcium, respectively. The average ratio by reacting value of sodium to potassium in sea water 

is 48, whereas in the oil-field brines it is about 

165. The deficiency of potassium in the brine 

is accounted for by the fact that clays and' 

silts extract potassium from water by a process of absorption, whereas they have little 

effect on sodium. The ratio of magnesium to 

calcium in normal sea water is about 5, but in 

the oil-field brines it averages less than 1, and 

this discrepancy can not be so easily explained. 

At moderately high temperatures magnesium 

is rapidly deposited from solution as basic carbonate or hydrate,1 and it is possible that the 

temperatures of 100° to 130° F., which prevail 

at depths of 1,000 to 4,000 feet, have had some 

effect in lowering the concentration of the mag1 Davis, W. A., Studies of basic carbonates: Soc. Chem. Industry 

Jour., vol. 25, p. 796,1906.

nesium. It is also possible that magnesium is 

removed under some conditions as magnesium 

silicate. Kharitschoff 2 in his experiments on 

the reduction of sulphates by petroleum found 

that magnesium sulphate apparently underwent somewhat more reduction than sod'nm 

sulphate, and if this observation is well four ded 

it may also partly account for the deficiency of 

magnesium in the oil-field waters.

RELATIONS OF THE MIXED TYPE. 

VARIATION IN CHLORIDE.

No matter how effectively fossil sea water 

may be trapped in a structural trough, such as 

the Midway syncline, it is evident that near the 

surface of the ground and also around the edges 

of the trough, where the rocks crop out, there 

will be a certain admixture of meteoric or 

rain water, which is constantly tending to 

drive out and replace the connate wr.ter. 

The extent to which this replacement of salt 

water by fresh has progressed may be studied 

by observing the increase of chloride with 

depth beneath the surface and with distance 

from the outcrop. Chloride forms a good 

index of the extent of the replacement, for it 

is not removed through reaction with the rocks 

or with petroleum, nor are there any salt 

deposits known which could increase the concentration of chloride in the waters near ttem.

The increase of chloride with depth beneath 

the surface has already been illustrated by 

the analyses in Table 15 and need not be considered further. Practically all the o+her 

analyses given also show a similar and ffirly 

regular increase in the chloride with de^th, 

the extremes being represented by the surface 

waters, which carry less than 300 parts per 

million, and the brines in the deeper part of 

the Midway syncline, which carry about 20,000 

parts.

The increase in chloride with distance from 

the outcrop is also fairly regular, within certain limits, throughout the field. In order to 

illustrate this increase four sets of analyse^ of 

waters occurring at different distances from 

the outcrop have been plotted in the four diagrams in figure 5. In these diagrams the 1 ori2 Kharitschofi, K. V., The waters in petroleum wells: Petroleum 

Rev., vol. 29, p. 368,1913.
TYPES OF OIL-FIELD WATERS.

DISTANCE FROM OUTCROP IN FEET

6,000 8.OOO 12,000

Well 73 WftH57 Well 23. 

1 ————— American Oilfields Co.

.Well 7

-Associated Oil Co.-

Well 3

2,000

DISTANCE FROM OUTCROP IN FEET 

6.000 8,000

Mascot Oil Co. Standard Oil Co. well 17 well 3

8,000

DISTANCE FROM OUTCROP IN FEET 

IE.OOO 16.000 30,000 2«,OOO

Traders 011 Co. well 71

Well 2,5ec.i4 Well I,sec.l2 Well 7, sec.12. -Standard Oil Co.———————————'

69

I4.OOO + r

JB'

C.C.M.O.Co. 

well 7

28,000 fj'

D

20,000

o

3 15,000

I

«• 10,000

5,000

'tflOO 8,000

DISTANCE FROM OUTCROP IN FEET 

I2,OOO 16,000 20,000 24,000 28,000 J)*

__ Carbonat

August WaterCo. 

well 3

Well Monarch F Well MJ6 

Standard Oil Co. — > ———

K.T.&O.Co. wells in sec-31

FlGUBE 5.- -Diagrams showing increase in chloride and decrease in carbonate in waters with distance from the outcrop. For location of

sections see Hate II.
70 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PAET II.

zontal scale represents the distance from the 

outcrop of the well from which the samples 

were taken, and the vertical scale the concentration of chloride and other constituents. 

The first three diagrams represent waters 

along lines about parallel to the dip of the 

rocks, but the line of the fourth is from east 

to west and therefore oblique to the dip. (See 

PI. II.) All four diagrams, however, bring 

out the decrease in chloride with increasing 

proximity to the outcrop, and if analyses of 

waters obtained still nearer the outcrop could 

be added they would doubtless show still less 

chloride. The first, third, and fourth diagrams show the gradation from waters low in 

chloride and evidently largely of meteoric 

origin to the very salty brines of the Midway 

synclines. As these brines have about the 

composition and density of ocean water, 

analyses of water still farther from the outcrop would show no further increase in chloride. 

In the second diagram, however, all three 

waters represented are of the mixed type, the 

zone of brines not being reached in the distance plotted.

Although all the waters plotted in figure 5 

are of the type of altered waters more or less 

closely associated with the oil, they are not 

all exactly from the same bed or horizon, a 

fact which is suggested by the slight irregularities in the curves. As already explained, 

the oil zone in the Midway syncline is several 

hundred feet stratigraphically lower than the 

oil zone in the western part of the field and also, 

because of the dip, is much deeper beneath the 

surface. Thus of the waters represented in 

diagrams AA' and BB' those nearest the outcrop are probably 500 feet or so stratigraphically higher than those farthest from the outcrop. The same is true of the waters represented in diagram CO', except that the third 

water from the outcrop occurs 1,500 feet 

above the horizon of the productive zone 

and is therefore as high as the waters nearest 

the outcrop, if not higher. Of the water represented in diagram DD', however, the first two 

occur in the Maricopa shale several hundred 

feet below the oil measures, whereas the three 

farthest from the outcrop are either in or 

slightly above zone B. (See Table 16, p. 72.) 

The fact that the gradation shown by this diagram is similar to that shown by the others

indicates that the exact vertical or stratigraphic position of the water is of little significance and that the gradation is essentially 

horizontal and is controlled by distance from 

the outcrop.

VARIATION IH THE PROPERTIES OP REACTIOF.

Besides causing a simple variation in the 

chloride content the mingling of connate salt 

water and meteoric rain water leads to a 

series of reactions between the other constituents and produces corresponding changes 

in the properties of the waters. The fact 

that the water along the western edge of the 

field is of the chloride-carbonate type wl ^reas 

that farthest east is a brine showing secondary 

salinity is due to the entrance of meteoric 

water at the outcrop, and the gradations that 

may be traced between this mixed type and 

the brine afford an interesting study cf the 

mixing of meteoric and connate waters.

It has already been shown that the f.etion 

of oil upon a sulphate-bearing water results in 

the removal of the sulphate and the sub^titution of carbonate and that when sea water 

undergoes this alteration alkaline-earth carbonates are formed and precipitated. As a 

result the reactive properties of the sea water 

become almost identical with those of the oilfield brines—that is, the sea water loses its 

secondary salinity, gains in primary salinity, 

and gains in secondary alkalinity only slightly 

because of the small solubility of the alkalineearth, carbonates. If the normal surface waters 

of the region, consisting almost entire^ of 

sulphates, are subjected to this change it is 

evident that they will become practically pure 

carbonate waters. As a result of this change a 

considerable proportion of alkaline-eartt carbonates will be lost through precipitation, but 

as these waters are generally not very highly 

concentrated, a considerable proportion will be 

retained. The alteration of such waters, therefore, results in a change from primary and 

secondary salinity to primary and secondary 

alkalinity, though the percentage of the last 

property is only moderate.

If the changes induced in the propert: 9s of 

waters by the substitution of carbonate for 

sulphate and the consequent precipitation of 

alkaline earths are understood, the relations of 

the chloride-carbonate type of water become
TT. S. GEOLOGICAL SURVEY PROFESSIONAL PAPER 117 PLATE II

Sulphate-free(altered) waters associated 

with the oil

_4._r.« - Axiscfamajor Normal or modi- Mixed type Brine ..__.„....._ 

partofMaricppa anticline. Show- fied ground (chloride-carbonate (chiefly chlorides; boundary be 

shale-Heavy line ing also direc- water or water) resembles sea tweenmiW 

npresent^apprpx-t.on of pitch-, surface water ware r> ^TM\ sea type "^

brine

Numbers refer to analyses, Tables 14-27. Letters refer to 

assays. Table 28

See figs. 5 and 6 for gradation in character of water on lines A A?,EB',CC. an

MAP OF SUNSET-MIDWAY FIELD SHOWING LOCATION OF WATER SAMPLES ANALYZED AND AREAL DISTRIBUTION OF THE BRINE AND MIXED TYPES OF WATER.
TYPES OP OIL-FIELD WATEES. 71

clear. This type is derived through, the mixing 

of the altered meteoric waters, which show 

strong primary alkalinity and contain chiefly 

sodium carbonate, with the brine or altered sea 

water, which still shows some degree of secondary salinity. The reaction that ensues 

when the two are mixed may be written thus:

CaCl2 + Na2CO3

Secondary primary

salinity alkalinity

2NaCl + CaCO3

primary secondary

salinity alkalinity

The addition of a water that has primary 

alkalinity to a brine increases the alkalies without corresponding increase in strong acids and

pending on the proportions of the mixture. If 

the brine component predominates primary 

salinity and the concentration will be high and 

primary alkalinity low, as in analysis 58 (p. 88), 

but as more and more of the meteoric water is 

added primary alkalinity will increase and 

primary salinity and concentration will decrease, as in analysis 53 (p. 88).

The transition from brine to the mixed type 

is shown in figure 6, in which are plotted the 

reaction properties of the waters from five 

wells. Complete analyses of the waters are 

given in Table 16, and the simple variation hi 

chloride and carbonate is shown in figure 5.

—I—10,000 ——,—— 12,000 —I—14.000

DISTANCE FROM OUTCROP IN FEET

——I—————I————I—— 16.000 18,000 20,000 22,000 24,000 26,000

salini

80

60

20

Secondary

Toialfor

»rtr»<

ty

isand__ __ — —— —• —

Secondary^ajmj*.£___ -( .-.

80

60

40

20

Analysis 15 Analysis 16 Analysis 17 -IS 

Analysis^

FIQUSE 6.—Diagram showing change in properties of waters with distance from the outcrop along line D-D', Plate II. (See Table 16, p. 72.) 

Analyses 14 and 15 represent waters of the mixed type; analyses 16,17, and 18 represent brines.

therefore reduces the secondary salinity of the 

brine. It is evident that if a sufncient amount 

of sodium carbonate water is added all the 

secondary salinity will be destroyed and the 

water will then be characterized by only two 

properties, primary salinity and secondary alkalinity. Any further increment of sodium 

carbonate water will then introduce primary 

alkalinity, which will continue to increase as 

more of the carbonate water is added. The 

average concentration of most of the brines is 

about 35,000 parts, whereas that of the altered 

surface waters is only about 2,000 parts; hence 

the concentration of the mixed water will be 

represented by some intermediate figure, deAs shown in figure 6, the waters of the two 

wells near the outcrop are primary alkaline, 

whereas those farther east are brines. With 

increasing distance from the outcrop there is a 

marked decrease in primary alkalinity, which if 

continued would lead to the total disappearance 

of this property at some point between the 

second and third wells. In the same direction 

there is a corresponding rise in primary salinity 

indicating that at some point the water is 

characterized by only two properties. East of 

this point primary salinity decreases and secondary salinity appears, rising to 16.2 per 

cent in the water farthest from the outcrop. 

The concentration curve shows a steady rise
72 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

TABLE 16.—Analyses showing gradation from the high carbonate water (mixed type) occurring along the western side of the 

field to the brine occurring in Midway syncline, and the similarity of the brine to ocean water.

[See fig. 5, D-Di, and fig. 6.]

PROPERTIES OF REACTION IN PER CENT.

Primary salinity. ............................

Secondary salinity. ...........................

Primary alkalinity- .........................

Per cent of rS04 in rS04+rCl ................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na)..... ..........................

Potassium (K). .............................

Calcium (Ca)............. ..................

Magnesium (Mg). . ..........................

Iron (Fe). ..................................

Aluminum (Al). ...........................

Sulphate (S04)... . .........................

Chloride (Cl)............. ...................

Carbonate (CO,) .............................

Bicarbonate (HC03 )....... .................

Silicia (Si02) ...............................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa)... . ......................

Potassium (rK) .........................

Alkaline earths: 

Calcium (rCa).... . .....................

Magnesium (rMg). ......................

Strong acids: 

Sulphate (rS04>... . ....................

Chloride (rCl)........... ................

Weak acids: 

Carbonate (rC03)...... ..................

Bicarbonate (rHCO3) ...................

14

69.0 

0 

29.2 

1.8

.1

4,188 

52 

31 

21 

Trace. 

5.2 

11 

4,593 

108 

3,477 

125

10, 846. 2

48.8 

.3

.4 

.5

.1 

34.4

.9 

14.6

15

82.0 

0 

13.8 

4.2

Trace.

} 8,437

163 

94

3 

11, 123 

0

4,270 

108

22, 031

| 47.9

1.1 

1.0

Trace. 

41.0

0 

9.0

16

84.6 

13.8 

0 

1.6

.20

/ 10, 548 

\ 72 

772 

570 

.1 

8.4 

34 

19, 624 

0 

573 

43

31, 953. 5

f 42.1 

1 -2

3.5 

4.2

.1 

49.1

0

.8

17

84,0 

15.2 

0 

.8

0

j«ll,955

1,391 

320 

& 63

Trace. 

21,646 

cl48

26

35,549

| 042.0

6.0 

2.0

49.6 

c.4

18

83.4 

16.2 

0 

1.4

Trace.

« 11, 656

1,281 

443

4.3 

21, 415 

c90

39

34, 928. 3

«41. 7

5.3 

3.0

49.8 

«. 2

19

7f. 6 

2L1 

0 

.3

f.

f 10, 710 

\ 390 

420 

1,300

2,700 

19, 410 

c70

35,000

f 38.5 

I -8

1.8 

8.9

4.6 

45.2

c. 2

a, Reported and calculated as sodium but includes potassium.

6 FejOs+Al-jOj.

c Reported and calculated as carbonate but probably in part bicarbonate.

14. August Water Co. well 3, sec. 31, T. 32 S., R. 24 E. Water from sands between 1,334 and 1,609 feet, or more 

than 200 feet below top of Maricopa shale. Sampled by G. S. Rogers, July, 1914. Analyst, S. C. Dinsmore.

15. Standard Oil Co. well Monarch F, sec. 26, T. 12 N., R. 24 W. Flowing water from depth of 2,540 to 2,560 

feet, or about 650 feet below top of Maricopa shale. Sampled by G. S. Rogers, July, 1914. Analyst, S. C. Dinsmcre. J

16. Standard Oil Co. well M. J. 6, sec. 36, T. 12 N., R. 24 W. Flowing water from depth of 2,270 feet, or about 

250 feet below top of zone B and 250 feet above top of Maricopa shale. Sampled by G. S. Rogers, June, 1914. Analyst, S. C. Dinsmore.

17. Kern Trading & Oil Co. well in NE. 1 sec. 31, T. 12 N., R. 23 W. Flowing water from depth of 2,990 feot, 

or 450 feet below top of zone B and 200 feet above main producing oil sand. Analyst, Kern Trading & Oil Co.

18. Kern Trading & Oil Co. well in NE. £ sec. 31, T. 12 N., R. 23 W. Flowing water from depth of 2,924 fe«^t, 

or about 350 feet below top of zone B and 125 feet above main producmgoil sand. Analyst, Kern Trading & Oil Co.

19. Ocean water. Interpretation of the mean of 77 analyses by W. Dittmar of sea water collected by the 

Challenger expedition (Challenger Rept., Physics and chemistry, vol. 1, p. 203, 1884).
TYPES OF OIL-FIELD WATERS. 73

with increasing distance from the outcrop, and 

in the distance covered by the figure it more 

than trebles. It will be noted that there is 

much less difference between the waters of the 

three wells farthest from the outcrop than between those of the two wells nearest, indicating 

that beyond a certain point the infiltration 

of meteoric water is negligible. Beyond the 

farthest well the brine shows no further 

changes and is fairly uniform in composition, 

but between the first well and the outcrop the 

water probably increases rapidly in primary 

alkalinity.

CMDMPABATIVE VALUE OF THE TYPES FOB INDUSTRIAL AND TECHNOLOGIC PURPOSES.

SOURCES OF WATER SUPPLY.

As the Sunset-Midway field is in an arid 

region in which there are no perennial streams, 

the problem of developing an adequate water 

supply has always been pressing. The ground 

waters of the region are in general so highly 

mineralized as to be entirely unfit for domestic 

purposes and unsuited even for making steam, 

yet because of the lack of better supplies these 

waters have been widely used. In the early 

days drinking water was hauled into the field in 

tank wagons, and later it was brought in by 

railroad from the east side of San Joaquin Valley. During this period most of the boiler 

water used was of the highly mineralized type 

supplied by wells along the western edge of the 

field, and it was not until the Western Water 

Co. completed its system that water suitable 

for boilers became cheap enough for general use. 

Owing to the increasing use of electricity and of 

natural gas in pumping wells, the demand for 

steam has decreased somewhat in the last few 

years, though it will doubtless always be strong.

At present the bulk of the water used in the 

field, both for domestic purposes and for use in 

boilers, is supplied by the shallow wells of the 

Western Water Co. near the north end of Buena 

Vista Lake. This is a rather hard water containing about 900 parts per million of mineral 

solids, of which over 600 parts are sodium and 

chloride. (See analyses 29 and 30, p. 82.) 

Several of the larger oil companies have developed better water supplies of their own, using 

either spring or lake water or water from shallow wells. The Western Minerals Co., in the

southern part of the Sunset field, is supplied by 

springs which issue close to a fault contact 

between the sedimentary rocks and granite. 

This water, as shown by analysis 24 (p. 81), 

contains only about 300 parts per million of 

mineral solids and although somewhat hard 

makes an excellent boiler water. The Honolulu Consolidated Oil Co. uses the water of 

Buena Vista Lake, which resembles} the water 

of Kern River but is somewhat more concentrated. According to analysis 2!! the lake 

water contains 309 parts of mineral solids and, 

unlike the other surface waters on tl te west side 

of San Joaquin Valley, is not characterized by 

permanent hardness (secondary salinity). The 

Standard Oil Co. pipes water for its own use 

from the east side of San Joaquin ' /"alley, and 

this water is doubtless one of prinary alkalinity and contains an even smaller amount of 

mineral solids than the lake 'water. The 

Chanslor-Canfield Midway Oil Co, uses the 

water furnished by shallow wells in the Santa 

Maria Valley, southwest of McKittrick. This 

is a hard water containing a high proportion of 

sulphate, though its total concentn ,tion is but 

526 parts per million. (See analyst 27, p. 82.) 

Other companies have drilled shallow wells in 

various parts of the field but have found only 

moderate supplies of the hard nnd highly 

mineralized water which constitutes the normal 

ground water of the region. Thus analysis 2, 

representing water from a well 80 feet deep, 

shows 4,489 parts per million of t)tal solids; 

analysis 8, from a well 790 feet < eep, 2,575 

parts; and analysis 31, from a we 1 170 feet 

deep, 4,534 parts.

In the early days, when water o: any kind 

was scarce, a few fairly deep water wells were 

drilled at or beyond the western edge of the 

field and a number of unsuccessfil oil wells 

were also converted to produce water. The 

wells drilled primarily for water produce a 

modified water high in mineral con )ent. (See 

analyses 3 and 35, pp. 63, 83.) The converted oil wells produce an altered v ater of the 

mixed (chloride-carbonate) type, wl ich is even 

higher in mineral solids but which '. las the advantage of showing only temporary hardness. 

(See Tables 23 to 28.) Waters of 1 hese types 

were widely used in boilers for a number of 

years and are still used to a consk erable extent. The highly concentrated brines as"so-
74 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

elated with the oil in the central part of the 

field are so undesirable that they have apparently never been used in boilers, though abundant supplies could be obtained.

FACTORS DETERMINING VALUE FOR MAKING STEAM 

AND FOR DOMESTIC TTSE.

Mineral content.—Although some constituents are much more objectionable than others 

in water for either domestic or industrial use, 

a rough index of the value of a water is afforded 

by its concentration, or content of mineral 

solids. This is particularly true if, as in the 

Sunset-Midway field, all the waters belong to 

several well-defined chemical types. No rigid 

classification can be made on the basis of mineral content, however, for waters that would in 

the humid parts of the country be considered 

unfit even for making steam, are commonly 

used for domestic purposes in the more arid 

regions. Although 250 parts per million of 

chloride makes a water "salty," waters containing 1,500 parts of chloride and 2,000 parts 

of other constituents have been used for domestic purposes in San Joaquin Valley. Dole,1 

in discussing the ground waters of this region, 

classifies waters containing less than 150 parts 

of total solids as low in mineral matter, those 

containing 150 to 500 parts as moderate, those 

containing 500 to 2,000 parts as high, and those 

carrying more than 2,000 parts as very high. 

According to this classification the waters used 

by several of the larger oil companies mentioned above would be characterized as having 

a moderate content of mineral matter, the ordinary water supply of the field as high, and the 

normal ground water of the region as very high.

Hardness.—Calcium and magnesium are the 

chief constituents that cause hardness in waters, 

but the kind of hardness depends on the proportions of the other radicles. Waters in 

which the alkalies exceed the strong acids have 

only temporary hardness, or hardness which is 

mostly removed by boiling. In such waters 

the calcium and magnesium must be held in 

equilibrium by the weak acids, carbonate and 

bicarbonate, and the hardness is therefore 

equivalent to the property of secondary alkalinity. When the solution is boiled the bicarbonate is converted into carbonate, and as only 

a small quantity of calcium and magnesium can

1 Dole, K. B., Ground water in San Joaquin Valley, Calif.: U. S. Geol. 

Survey Water-Supply Paper 398, p. 82,1916.

be retained in solution in the presence of carbonate the excess is thrown down as a precipitate or scale and most of the hardness is tl us 

removed. Waters in which the strong acids 

exceed the alkalies, however, have permanent 

hardness. This property, which is synonymous 

with secondary salinity, is due to the balance 

between the alkaline earths and strong acids 

and can be removed only by the addition of a 

precipitating agent, such as sodium carbonate 

or lime.

Hard water is objectionable for domestic use 

and for making steam, because it consuxies 

soap and deposits scale in kettles and in boilers. 

The hardness of a water may be measured directly by its soap-consuming power or may be 

calculated from the complete analysis. It may 

be calculated in percentage as secondary salinity and secondary alkalinity, as already explained, but is usually expressed in parts per 

mi Hi on as total hardness in terms of CaC03 , 

and may be derived by the following formula:

Total hardness as CaCO3 = 2.5 Ca+4.1 Mg

According to Whipple 2 1 pound of ordinary 

soap is consumed or wasted in softening about 

25 gallons of water having a total hardness- of 

200 parts per million. As shown in Table 17 

(p. 78), the best waters obtainable for domestic 

use in the Sunset-Midway field range in hardness between 110 and 383 parts, for although 

some of the deeper waters are less hard they 

have other qualities that are still more objectionable.

Formation of scale.—The readiness with 

which water deposits scale when heated in a 

boiler is determined to some extent by its 

hardness, for waters that have a high percentage of temporary hardness deposit a large 

amount of scale. However, when the wate1* is 

heated to a high temperature in a boiler p,nd 

concentrated, some of the mineral solids not 

involved in hardness are also precipitated and 

most of the suspended and colloidal matte" is 

deposited. These deposits increase the consumption of fuel and, as they have to be removed, increase the cost of repairs; if they are 

allowed to accumulate the boiler capacity is 

decreased, the boiler shell is likely to become 

blistered, and a disastrous explosion may 

occur.

* WMpple, G. C., The value of pure water, p. 26, New York, 1907.
TYPES OF OIL-FIELD WATERS. 75

The scale or incrustation formed includes 

practically all of the suspended matter or mud; 

also the silica, which is precipitated as SiO3 ; the 

iron and alumina, which appear as Fe2O3 and 

AlgOg; the magnesium, which appears chiefly 

as MgO; and the calcium, which appears as 

CaCO3 and CaSO4 . As calcium and magnesium 

are usually present in much greater amounts 

than the other scale-forming constituents their 

compounds generally constitute over 90 per 

cent of the deposit. A water high in calcium 

and carbonate is likely to yield a. rather 

powdery scale, which is not difficult to remove, 

whereas one high in magnesium and sulphate 

may yield a hard, cement-like deposit.

Stabler* has devised a series of convenient 

formulas for estimating the action of waters 

under boiler conditions. The formulas, as 

modified by Dole 2 for estimating in parts per 

million the scale-forming ingredients and the 

probable hardness of the scale formed, are as 

follows:

(1) s = Sin+Cm+2.95 Ca + 1.66Mg

(2) h = SiO2 +1.66 Mg + (1.92 Cl +1.42 SO4 - 

2.95 Na)

In formula 1 s = scale-forming ingredients, 

Sm = suspended matter, and Cm = colloidal 

matter. In most of the waters under consideration Sm may be neglected and Cm (chiefly 

SiO2 , Fe2O3 , and A12O3) may be assumed to be 

about 30 in the shallower waters unless actual 

determination shows a higher figure. Formula 

2 is designated for calculating the quantity of 

hard-scale ingredients, the most abundant of 

which appear as silica, magnesia, and calcium 

sulphate. Hence if the value in the parentheses 

in this formula exceeds 1.42 SO4 or 3.4 Ca, it 

should be reduced to the smaller of the two, 

and if it is a minus quantity, as in some of the 

deeper waters, it should be neglected. If the 

ratio of h, as thus estimated, to s is greater 

than 0.5 the scale formed may be considered 

hard, and if it is less than 0.25 it may be called 

soft. These values have been computed for 

some of the waters here discussed and are 

shown in Table 17 (p. 78).

1 Stabler, Herman, Some stream waters of the western United States, 

with chapter on sediment carried by the Rio Grande and the industrial 

application of water analyses: U. S. Geol. Survey Water-Supply Paper 

274, p. 165,1911. See also Eng. News, vol. 60, p. 355,1908.

2Mendenhall, W. C., Dole, R. B., and Stabler, Herman, Ground 

water in San Joaquin Valley, Calif.: II. 8. Geol. Survey Water-Supply 

Paper 398, p. 65,1916.

Foaming.—Foaming, or the formation of 

bubbles upon and above the surface of the 

water, is one of the least understood of boiler 

phenomena. It is usually ascribed to the 

existence of dissolved matter, which increases 

the surface tension of the liquid and impedes 

the breaking of the steam bubbles and thus 

under certain conditions causes the water to 

pass from the boiler with the steam. As the 

chief constituents remaining dissolved in water 

under boiler conditions are the alkalies, and 

as the concentration of these constituents 

constantly increases as fresh water is added 

and converted into steam, the foaming tendency of a water is usually measured by its 

content of alkali salts. The presence of suspended matter and of organic matter also 

increases the tendency to foam, and some of 

the precipitated matter or scale probably has 

a similar effect. It is recognized, however, 

that the most potent factor in foaming consists 

in the design of the boiler, its condition, and 

the method of handling it, and in comparison 

with this factor the effects of any of the constituents of the water, except the alkalies, are 

probably very small. Accordingly, the foaming tendency of a water may be derived from 

the following simple equation: 3

f=2.7Na

As shown by Table 17 (p. 78) the value of 

f is moderate in only three of the waters commonly used in the field, arid it is exceedingly 

high in all the deeper waters. The excessive 

tendency to foam of the chloride-carbonate 

water associated with the oil in the western 

part of the field is its only really bad quality 

for boilers, but unfortunately the foaming 

tendency can not be overcome by chemical 

treatment.

Corrosion.—The corrosion of metal by water 

is caused chiefly by the solvent action of acids, 

which may be originally present in the water 

or may be formed in a boiler. Acid waters are, 

generally speaking, not common, but many of 

the deeper oil-field waters contain naphthenic 

and other organic acids that may become 

corrosive under some conditions. Other waters contain the gas hydrogen sulphide, which 

oxidizes readily to sulphurous acid or sulphuric acid, both powerful corroding agents.

* As devised by Stabler (op. cit.) and modified by Dole (op. cit.).
76 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PART II.

Sulpnur waters are probably active in the 

corrosion of casing in oil wells, but when sulphur water is introduced into a boiler most of 

the hydrogen sulphide gas probably escapes 

before it is oxidized to acid and its action is 

generally not pronounced. Similarly the dissolved gases, oxygen and carbon dioxide, promote corrosion, but they are generally soon 

driven from the water.

Under boiler conditions, however, a neutral 

or alkaline water may become acid and corrosive. As already stated, magnesium, iron, 

and aluminum are deposited as scale and 

appear as hydrates or oxides; consequently 

the acidic radicles with which these bases had 

previously been in equilibrium are left to 

become free acids. If these bases had been 

held in balance by the carbonate radicle, 

carbonic acid would be liberated and would 

pass off as water and carbon dioxide, but if 

they had been in equilibrium with sulphate, 

for example, sulphuric acid would be formed. 

If calcium in the water were being deposited 

as calcium carbonate, the acid would doubtless attack it first, forming calcium sulphate 

and carbonic acid, but if an excess of sulphuric acid were set free it would attack the 

boiler. These relations are expressed by Stabler in the following formula:1

C = 1.008 (rH+rAl+rFe+rMg— rCO3 - rHCOg) 

which may in general be simplified as follows:

C=rMg-rCO3 -rHCO3, or

C=0.0821 Mg-0.0333 CO3 -0.0164 HCO3

If c is positive the water will certainly corrode the boiler. If c+rCa (or c +0.0499 Ca) 

is negative the mineral constituents of the 

water will not cause corrosion, but whether 

organic matter or irregularities will cause it is 

uncertain. If c is negative but c+rCa is positive corrosion may or may not occur. The 

probability of corrosive action of some of tho 

representative waters is shown in the table on 

page 78.

WATER SOFTENING.

Hard waters, which are objectionable both 

for domestic use and in boilers, may be softened 

and improved in several ways. Waters that

i Stabler, Herman, op. cit.

have temporary hardness (secondary all-alinity) may be improved simply by heating, 

and if they do not have permanent hardness 

(secondary salinity) also most of the hardness 

can thus be removed. The heating simply 

decomposes the bicarbonate radicle and p^*ecipitates calcium carbonate and magnesium 

carbonate, basic carbonate, or hydrate up to 

the limit of solubility of these salts. It is 

generally accomplished in water for boiler use 

by means of preheaters, which utilize exhaust 

steam or flue gases to heat the water before it 

is fed into the boiler. The extent to which 

the oil-field waters can be improved by p^eheating is indicated roughly by the percentage 

of secondary alkalinity and the total concentration, both of which are given in the anal;rtical tables.

Waters that have permanent hardness (secondary salinity) must be chemically treated 

in order to soften them and remove the scaleforming ingredients, and as the elimination of 

temporary hardness is hastened by the addition 

of a precipitant, the two processes are often 

effected together. As secondary salinity is 

caused by an excess of strong acids (SO4 

and Cl) over alkalies, it may be removed by 

the addition of a weak acid salt, such as sodium 

carbonate (soda ash). It is thus converted 

into secondary alkalinity, and calcium and 

magnesium carbonates are precipitated. If 

lime in the hydrated form (Ca(OH)2) is also 

added, practically complete elimination of the 

magnesium as magnesium hydroxide is effected, 

but at the same time it may be necessary to 

add an excess of sodium carbonate hi order to 

precipitate the extra calcium thus introduced. 

Stabler employs the following formulas to determine the weight in pounds of 90 per ce^it 

lime (CaO) and 95 per cent soda ash (NagCOa) 

that must be added to soften 1,000 gallons .of 

water:

Lime required = 0.26 (rFe+ rAl +rMg+ rH + 

rHC03 + 0.0454CO2) = 0.00931Fe + 0.0288A1 + 

0.0214Mg + 0.258H+0.00426HCO3 + 0.0118CO2.

Soda ash required = 0.465 (rFe + rAl + rCa + 

rMg + rH - rCO3 -rHCO3) =0.0167Fe + O.OS15 

Al + 0.0232Ca + 0.0382Mg + 0.462H - 0.0155 

CO3 -0.00763HCO3 .

The application of these formulas to analysis 

29 (p. 82), for example, indicates that 0.66
TYPES OF OIL-FIELD WATERS. 77

pound of lime and 0.84 pound of soda ash are 

required to soften 1,000 gallons of the water. 

The ordinary ground water, represented by 

analysis 2 (p. 63), requires 4.09 pounds of 

lime and 13.07 pounds of soda ash, whereas 

the primary alkaline water represented by 

analysis 54 (p. 88) requires 7.36 pounds of 

lime but no soda ash.

It is interesting to note that the addition of 

soda ash to a permanently hard water is entirely analogous to the mixing of waters that 

have primary alkalinity with waters that have 

secondary salinity, a process which has evidently occurred naturally in the western part 

of the field. (See p. 51.) It would therefore 

be entirely practicable to soften such waters 

as Nos. 1 and 2 (p. 63) by the addition of such 

water as No. 7 and thus save the cost of the 

soda ash. Most of the waters that have primary alkalinity are much more concentrated 

than No. 2, however, and although mixing 

them with the ordinary dilute surface waters 

would remove the permanent hardness of the 

surface waters, the resulting mixture might 

be so concentrated that the undertaking would 

prove unprofitable. On the other hand, highly 

concentrated waters that have primary alkalinity are commonly used in the field for 

making steam and they would be diluted and 

thus improved by being mixed with a less 

concentrated but permanently hard water, 

which could not be used alone without chemical treatment. Under certain conditions this 

method might prove economically successful.

The soda-lime method of softening water 

removes the chief scale-forming ingredients, 

calcium and magnesium, and the chief constituent involved in corrosion, magnesium, 

but on the other hand it increases the chief 

foaming ingredient, sodium. The addition of 

soda ash may therefore simply convert a scaleforming and corrosive water into a foaming 

water, and there is no way in which the foaming tendency may be reduced.

The softening of water may also be accomplished by other chemicals, but none has 

proved more efficient or economical than soda 

and lime. Substances of another class, mostly' 

organic, are occasionally used, not to prevent 

the formation of scale but to soften it and 

render it easily removable. Most of the boiler 

compounds on the market consist chiefly of 

soda ash and of organic substances, and their 

chief function is to prevent corrosion and to 

facilitate removal of the scale. In general it 

is far better to have the water analyzed and to 

treat it with a calculated amount of well-known 

chemicals, such as soda ash and lime, before 

it is fed. into the boiler, than to experiment 

with expensive boiler compounds of unknown 

composition.

COMPARISON OF REPRESENTATIVE WATERS.

The accompanying table gives the main 

factors in the industrial values of a few representative waters. All these waters, with the 

probable exception of Nos. 5 and 12 are used 

in boilers.

The first four waters are used also for domestic purposes and are commonly regarded 

as the best waters obtainable in the field. If 

suspended and organic matter is ignored, the 

Buena Vista Lake water is evidently the best. 

Nos. 2, 3, and 4 are all permanently hard 

waters, deposit a considerable amount of 

medium or hard scale, and are semicorrosive. 

The normal ground water of the field, represented by No. 5, is evidently undesirable in 

every respect, and the brine, No. 12, shows the 

same bad qualities in much greater proportion.

The waters of primary alkalinity, represented by Nos. 7 to 11, are not permanently 

hard or corrosive, their chief undesirable 

quality being the large proportion of foaming 

ingredients. As this proportion can not be 

reduced by chemical treatment, such waters 

can be improved only by mixing them with the 

more dilute shallow waters.
78 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PAKT II.

TABLE 17.—Industrial values of representative waters from the Sunset-Midway field, 

[Parts per million except as otherwise designated.]

Surface and shallow waters used for domestic and industrial purposes:

1. Buena Vista Lake. . .............

2. Kern County Land Co.'s spring. .

3. Chanslor-Canfield Midway Oil

Co.'s water wells.

4. Western Water Co. 's water wells . .

Normal ground water:

5. Pyramid Oil Co. 'swell, depth 80

feet.

Modified ground water used for making

steam:

6. August Water Co.'s California

Amalgamated well, depth 1,090

feet.

7. Stratton Water Co.'s well, depth

915 feet.

Water associated with the oil, used for

making steam:

8. General Petroleum Co. 's Carnegie

well, depth 3,880 feet.

9. Associated Oil Co.'s well, depth

1,727 feet.

10. August Water Co.'s well, depth

1,609 feet.

11. Northern Oil Co.'s water well,

depth 1,423 feet.

Brine associated with the oil:

12. Mays Consolidated Oil Co. 's well,

depth 3,000 feet.

Analysis No.

22

24

27

29

2

3

35

53

54

14

73

5

Mineral 

content.

309

314

526

899

4,489

2,717

1,959

5,179

7,940

10, 846

9,602

33, 578

Total 

hardness 

as CaCOg.

no ny

206

383

177

1,611

684

262

93

38

164

289

3,862

Scaleforming 

ingredients (s).

145

248

367

216

1,454

165

284

149

73

246

308

3,307

Character of 

scale.

Soft......

Medium .

Hard ....

...do.....

...do.....

...do.....

...do.....

...do.....

...do.....

...do.....

Medium.

Soft

Foaming 

ingredients (f).

178

62

49

686

2,343

2,485

1,760

5,562

8,543

11, 450

10, 236

30, 467

Probability of corrosion

(c).

Noncoirosive .

Uncertain.

Probably corrosive.

Uncertain.

Corrosive.

Do.

Noncorrosive.

Do.

Do.

Do.

Do.

Corrosive.

ACTION OF OIL-FIELD WATERS ON CEMENT. '•

Because of the extent to which cement is 

used as a means of excluding water from the 

wells, any action that the various types of 

water may have on cement is of considerable 

importance. The process of placing or pumping the cement into the well and forcing it 

through the lower end of the casing and up 

around its outer side is a difficult one, in which 

failures are not uncommon, and these failures 

are often ascribed to the chemical action of 

the mineralized waters, especially sulphate or 

" alkali" waters. The action of various types 

of water on cement has not been extensively 

investigated and, being purely a technologic 

problem, falls outside the scope of this report; 

but it may be helpful at least to point out the 

chemical character of the waters to which the 

cement is likely to be exposed. It is assumed 

that the cement is mixed with fresh water low 

in mineral content and that the hole is flushed 

with similar water before the cement is introduced.

The deeper wells in the field are now finished with at least two and generally three or

four strings of casing, and some operators 

cement not only the water string—the lin^ of 

casing landed as close as possible above the oil 

sand—but also one or more of the outer strings. 

Even where this is done, however, the principal effective shut-off is the one at the end of 

the water string, for this directly protects the 

oil sand. Under especially favorable conditions the cement may be forced up on the 

outside of the casing for as much as 1,000 feet, 

but in the majority of the wells little of the 

cement reaches more than 300 or 400 feet f"om 

the top of the uppermost producing oil snnd. 

As already pointed out, the waters within this 

distance of the top of the oil measures in the 

Sunset-Midway field contain practically no 

sulphate, and if they affect the setting of the 

cement their action must be ascribed to some 

other constituent. Moreover, Oatman 1 has 

shown that solutions containing even 5 per 

cent of sodium sulphate do not affect the setting of cement, though they may cause disintegration after a period of months or years,

i Oatman, F. "W., Water intrusion and methods of prevent'on in 

California oil fields: Am. Inst. Min. Eng. Trans., vol. 48, p. 527,1914.
TYPES OF OIL-FIELD WATERS. 79

In the central and eastern parts of the field 

cement placed near the oil measures is exposed 

to the action of a brine which, except for its 

lack of sulphate, closely resembles sea water 

in both strength and composition. (See Table 

22, p. 85.) In the same area the waters for 

1,500 feet above the oil measures are very 

similar in character except that they contain 

a little sulphate, but none of them more than 

sea water. (See analysis 33, p. 83.) In a 

recent investigation* by the Bureau of Standards it was found that sea water has no appreciable effect on a good cement, provided that 

the cement is properly handled and placed 

and that it is not exposed to successive wetting 

and drying. The action of many other solutions on cement was also studied and it was 

found that although nearly all of them attack 

ground cement in the laboratory, their action 

on masses of cement in the field is practically 

negligible, probably because of the early formation of a lime coating which prevents further 

reaction. Cement in oil wells several thousand 

feet deep is of course exposed to considerable 

hydrostatic pressure, which would tend to 

force the water into its pores, but as the pressure is not differential and the water is not 

actually moving through the pores, its effect is 

doubtless of little importance.

In the western part of the field cement 

placed near the oil measures is exposed to a 

less concentrated water containing, roughly, 

7,000 parts per million of sodium chloride and 

3,000 parts of sodium carbonate. (See Table 

25, p. 89.) Water of this type extends at 

least as far above the producing oil sands as 

the tar-sand zone, though waters above this 

zone usually contain considerable proportions 

of sulphate. Sodium carbonate waters are 

active in the solution of silica, and in the 

laboratory they rapidly remove lime from 

ground cement. Water of this type thus has 

a somewhat more injurious effect than the 

brine, though to judge from the field studies 

of the Bureau of Standards its action is 

probably not serious.

The oil-field waters to which cement is 

chiefly exposed are therefore not of such a 

character as to interfere with the setting of 

cement or to cause rapid disintegration after-

> Bates, E. H., Phillips, A. J., and Wig, R. J., Action of the salts in 

alkali water and sea water on cements: Bar. Standards Tech. Paper 

12,1913.

ward. Cement, in fact, is more resistant to 

the action of the oil-field waters than the casing 

itself and forms an excellent protective covering for it. A factor more important than 

chemical character is the temperature of the 

waters, for increase in temperature hastens the 

time of setting. According to Oatman,2 a 

temperature of 110° F. decreases the normal 

time of setting by about one-third; and as 

already shown, the temperature of the oil-field 

waters is generally at least 100° and may reach 

130°. Another important geologic factor is the 

presence of gas. Escaping gas may keep the 

cement mixture agitated and so prevent its 

setting; and as gas occurs at many localities 

above the oil measures it has probably been 

the cause of failures in cementing water strings. 

Oil is of less importance, for although it retards 

the time of setting considerably it does not 

seem to affect the strength of cement.3 It is 

highly probable, however, N that a great majority of the failures in cementing are due to 

faulty technologic methods rather than to any 

of the geologic factors discussed above.4

CORROSION OF WELL CASING BY WATERS

It is now well recognized that both iron and 

steel casing deteriorate when placed in the 

ground and after a varying period may become 

riddled with holes and thus useless as a means 

of excluding water. The life of the casing apparently depends on many conditions; in some 

wells or fields the casing is strong enough to be 

withdrawn from the ground after 10 or* 15 

years, whereas in others it may become extensively corroded within a year. The photographs reproduced in Plate XLV, A, B, of Part 

I (Professional Paper 116) show the corrosion 

of casing that had been in the ground for about 

four years in a well in the Buena Vista Hills. 

This corrosion is supposed to have been caused 

by a water which occurs between 1,700 and 

1,900 feet and which is probably similar in 

character to the waters whose analyses appear 

in Table 22 (p. 85). -

The causes of the corrosion of casing are 

difficult to study and are not thoroughly understood. Acid waters are of course strongly

2Oatman, F. W., op. cit.

* Page, L. W., Oil-mixed Portland cement, mortar, and concrete: Min. 

and Sci. Press, vol. 103, Nov. 4,1911, p. 580.

4 Arnold, Ralph, and Garfias, V. R., The cementing process of 

excluding water from oil wells as practiced in California: Bur. Mines 

Tech. Paper 32,1913.
80 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PABT II.

corrosive, but waters containing free mineral 

acids are not encountered in the Sunset-Midway 

field, and whether the weaker organic acids 

that some waters contain cause corrosion is conjectural. When water is heated in a boiler certain mineral salts, especially magnesium salts, 

hydrolyze and liberate free acid, and although 

little hydrolysis takes place in a cold solution, 

it is possible that sufficient takes place at 

temperatures of 100° or so to cause perceptible 

corrosion. Corrosion due to the hydrolysis 

of magnesium salts would occur only in the 

central and eastern parts of the field, where the 

water is a brine carrying considerable quantities 

of magnesium and chloride. Dissolved gases 

are generally thought to be the chief agency of 

corrosion by nonacid waters. Hydrogen sulphide, though in itself a reducing agent, is regarded as especially harmful because of its 

tendency to oxidize to sulphurous or sulphuric 

acid. Carbon dioxide, or carbonic acid, is also 

corrosive, and its activity is usually accounted 

for by the theory that electrolytic action takes 

place and that the hydrogen ions formed are 

easily replaced by the iron. The iron goes into 

solution as ferrous carbonate, but if oxygen is 

present it is oxidized and precipitated as ferric 

hydroxide, thus releasing the carbon dioxide 

again to attack fresh iron. Oxygen is probably 

not abundant in the deeper oil-field waters, 

however, and in the absence of oxygen the 

corrosive action of carbon dioxide is not so 

pronounced.

A probable factor in the corrosion of oil-well 

casing which is often overlooked is electrolysis 

due to stray electric currents. The electrolytic corrosion of gas mains and similar pipes 

buried at shallow depth has long been recognized, and with the increasing use of electricity 

as a source of power in oil-field operations the 

possibility of the action of stray currents following the casing has become too great to be 

ignored. The corrosion would occur at the 

point at which the low-density stray current 

leaves the casing, which in oil wells would 

generally be at the point of contact with a 

water-bearing sand. The- presence of any 

dissolved salts in the water would increase 

the electrolytic action, and the strong brines 

in the central and eastern parts of the field 

would be especially favorable as electrolytes.1

iMcColIum, B., and Logan, K. H., Electrolytic corrosion of iron in 

soils: Bur. Standards Tech. Paper 25,1913.

Another well-recognized cause of corrosion is 

the presence of impurities or inclusions, such 

as slag, cinders, or sulphides in the casing 

itself, which probably set up local galvanic 

action.

ANALYSES OF OIL-FIELD WATERS.

GENERAL STATEMENT.

In the following pages are given a number of 

other analyses of water from different parts of 

the field. These waters are all members of the 

several classes already defined and differ f~om 

the types shown in Table 14 only in detail. As 

the origin and relations of these types 1 ave 

already been discussed and as the location of 

the water sands from which the samples were 

taken have been described in Part I of this 

report, no further comments on the particular 

analyses will be necessary.

Tables 18 and 19 contain'analyses of surface 

waters and shallow ground waters, Table 20 

analyses of modified waters, Tables 21, 22, and 

23 analyses of altered brine, and Tables 24 to 

27 analyses of altered waters of the mixed type. 

Within each group the samples analyzed are 

arranged in order, according to their location 

from north to south. Table 28 contains a few 

miscellaneous assays or partial analyses which 

were made with a reasonable degree of accuracy 

and which afford a general indication of the type 

of water represented. The locations of the veils 

from which most of the samples were taker are 

shown on Plate II.

The analyses should be of value to those who 

desire to study the chemical character of the 

waters in connection with the horizon at which 

they occur and to utilize the data thus obtained 

in determining the source of the water flooding 

a well. The analyses given are sufficient to 

establish the principles that control the character of the water, to permit the recognition of 

all the main types, and to establish the drtribution of these types, though for detailed v^ork 

in any particular section many more analyses 

would have to be made. The waters from any 

one sand or zone seem to be unusually uniform 

and constant in composition, but few sands can 

be definitely traced very far, and a single a nalysis can not be used as a standard for comparison except within a small area
ANALYSES OF OIL-FIELD WATERS. 81

SURFACE WATERS AND SHALLOW GROUND 

WATERS.

Table 18 contains analyses of six surface 

waters and spring waters from the SunsetMidway district. All these waters except 

No. 22 show strong secondary salinity and all 

contain a high proportion of sulphate. No. 22, 

the water of Buena Vista Lake, resembles the 

waters of the east side of San Joaquin Valley, 

as would be expected from the fact that the 

lake water is derived largely from the overflow 

of Kern River. No. 23, the water of Bitterwater Creek, is by far the most concentrated of

those shown in the table, though No. 25, which 

represents the water of San Emigdio Creek, 

also contains a very high proportion of solids. 

Table 19 contains analys3s of water from 

shallow water wells. Nos. 26, 31, and 32 represent the normal ground water of the region, 

which shows strong secondary salinity and is 

high in sulphate and highly concentrated. 

Analysis 2 (p. 63) and analyses 8 and 12 (p. 65) 

represent other waters of the same type. The 

remaining analyses in Table 19 represent waters 

that for one reason or another are more dilute 

than the average and better suited to commercial use.

TABLE 18.—Analyses of surface and spring icaterfrom, the Midway-Sunset region.

PROPERTIES OP REACTION IN PER CENT.

Primary salinity ................................

Secondary salinity ..............................

Primary alkalinity. ..............................

Secondary alkalinity. ............................

Per cent of rSO4 in rSO4+rCL. ...... .............

Ratio of rCO3+rHCO3 to rSO4 ...................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na) ....................................

Potassium (K). . .................................

Calcium (Caj). . ..................................

Magnesium (Mg) .................................

Iron oxide (Fe2O3). . .............................

Sulphate (SO4)-'-... . ............................

Chloride (Cl) ...................................

Nitrate (NO3 ). . .................................

Carbonate (CO3) ................................

Bicarbonate (HCO3 )... . .........................

Silica (SiOjj)— ... ...........................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa1! ...............................

Potassium (rK). . ............................

Alkaline earths:

Strong acids: 

Sulphate (rS04)... . .........................

Chloride (rCl) ..............................

Nitrate (rNO3). .............................

Weak acids: 

Carbonate (rCO3) ...........................

Bicarbonate (rHCO3 ). .......................

20

44.4 

22 

0 

33.6

86.1 

.59

1 216

92

87

580 

70 

Trace. 

0 

433 

87

1,345

| 22.2

10.9 

16.9

28.6 

4.6

0

16.8

21

15.6

23 

0 

61.4

85.5 

1.86

038

98 

48 

22

166 

21

6193

1

587

«7.8

23.4 

18.8

16.5 

2.8

30.7

22

54.6 

0 

0

45.4

68.1 

1.22

66

33 

9

94 

33

6 72

2

309

27.3

15.5

7.2

18.6 

8.7

»22.7

23

45.4 

48 

0 

6.6

93.4 

.08

1,409

630 

511

5, 638 

300 

Trace. 

30

475 

38

8,790

22.- 7

11.7 

15.6

43.6 

3.1

.4 

2.9

24

19.6 

18.8 

0 

61.6

66.1 

3.21

23

56 

16

47 

18 

30 

7.2 

178 

29

314.2

9.8

27.4 

12.8

9.6 

4.9

4.7

2.3 2as

25

28.4 

43.6 

0 

28.0

90.5 

.44

oll2

138 

66

} »538 

42

6144

12

1, 053. 9

014.2

20.1 

15.7

32.6 

3.4

6140

« Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

20. Frazers Spring, sec. 2, T. 30 S., R. 21 E. Spring is probably in Maricopa shale, but source of water may be 

affected by near-by fault. Sampled by G. S. Rogers, September, 1915. Analyst, S. C. Dinsmore.

21. California Standard Spring near McKittrick. Analyst, Smith, Emery & 'Co.

22. Buena Vista lake water. Analyst, Kern Trading & Oil Co.

23. < Bitterwater Creek, sec. 29, T. 11 N., R. 24 W. Sampled by G. S. Rogers, September, 1915. Analyst, 

S. C. Dinsmore.

24. Kern County Land Co. spring in west corner of San Emigdio land gjrant. Water issues close to a fault 

between granite and early Tertiary sedimentary rocks. Sampled from pipe line of Western Minerals Co. by G. S. 

Rogers, September, 1915. Analyst, S. C. Dinsmore.

25. San Emigdio Creek, San Emigdio land grant. Analyst, Standard Oil Co., June, 1910.

110973°—19——6
82

TABLB 19.—.

THE SUNSET-MIDWAY OIL FIELD, CALIF.——PAET II.

of water from shallow wells in the Sunset-Midway field and the district to the north. 

[See also analysis 2, Table 14, and analyses 8 and 12, Table 16.]

PROPERTIES OP REACTION IN PER CENT. 

Primary palinit.y

Secondary salinity. ....................

Primary alkalinity. ...................

Secondary alkalinity .......... .......

Per cent of rS04 in rS04+rCl ...........

Ratio of rC03+rHC03 to rS04 . .........

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na) .........................

Potassium (K) .................. ... . Calcium (Ca^ .........................

Iron oxide (Fe203 ). ...................

Alumina (ALO3 ). . .................... 

Sulphate (S04).. ......................

Chloride (Cl) .........................

Nitrate (NO,) ........................

Carbonate ( CO3 ) 6 ......................

Silica (Si02).........................

REACTION VALUES IN PER CENT.

Alkalies: 

Sodium (rNa) ....................

Potassium (rK) ...................

Alkaline earths: 

Calcium (rCa) ....................

Strong acids: 

Sulphate (rSOJ. ..................

Chloride (rCl). ...................

Nitrate (rNO3) ...................

Weak acids: 

Carbonate (rC03)&. ................

26

62.2 

32.8 

0 

5.0

48 

.11

| 869 '

280 

109

} •

1,329 

1,062

92 

31

3,781

| 31.1

11.5 

7.4

22.8 

24.7

2.5

27

9.2

52.6 

0 

38.2

89.3 

.70

ol8

89 

39

15

223 

20

97 

25

526

o4.6

26.3 

19.1

27.6 

3.3

19.1

28

57.2 

5.4 

0 

37.4

75.7 

.79

a 207

47 

53

4

358

85

176 

10

940

« 28. 6

7.5 

13.9

23.7 

7.6

18.7

29

76 

12.6 

0

11.4

26.6 

.57

254

61 

6

166 

335

51 

26

899

38

10.3 

1.7

11.8 

32.5

5.7

30

72.4 

16.0 

0 

11.6

25.3 

.52

273

77 

8

176 

383

57

974

36.2

11.8 

2.0

11.2 

33

5.8

31

43.6 

53.0 

0 

3.4

74.5 

.04

o697

647

84

2,375 

601 

43

72 

cl5

4,534

a21.8

23.3 

4.9

35.6 

12.2 

.5

1.7

32

51.6 

45.8 

0 

2.6

62.8 

.04

a 672

431 

70

41

1,66C

72g

4?

3,64£

a 2f . &

IP, 1 

5,1

30.6 

J8.1

1.3

Reported and calculated as sodium but includes potassium. Reported and calculated as carbonate but probably in part bicarbonate.

Includes

26. Standard Oil Co. well Cahn No. 2, sec. 4, T. 27 S., E. 21 E.; depth. 145 feet. Sample collected while dnlling and analyzed by Standard Oil Co., October, 1911.

27. Chanslor-Canfield. Midway Oil Co. water wells, Santa Maria Valley, about 3 miles southwest of McKittrck. 

Analyst, J. H. Parsons Chemical Co. Authority, Chanslor-Canfield Midway Oil Co.

28. Associated Oil Co. giant fresh-water well, sec. 11, T. 30 S., K. 21 E. Analysts, Smith, Emery & Co. 

Authority, Associated Oil Co.

29-30. Western Water Co. shallow wells on edge of Buena Vista Lake, sec. 5, T. 31 S., E. 25 E. Sample 29 was 

taken from the pipe line and represents water from several wells; sample 30 represents water produced by well 6. 

Sampled and analyzed by Kern Trading*& Oil Co.

31-32. Kern Trading & Oil Co. water well in sec. 35, T. 31 S., R. 24 E.; depth 170 feet. Sample 31 was taken 

in August, 1910, and sample 32 eight months later.
ANALYSES OF OIL-FIELD WATERS. 83

MODIFIED WATERS.

Table 20 contains analyses of a few waters of 

the modified type encountered in wells drilled 

originally for oil. Most of these waters have 

primary alkalinity and show lower sulphate 

salinity than the normal ground waters. No. 

34 is a remarkably dilute water, considering the 

depth from which it is supposed to have come

(2,980 feet), and it is possible that the sample 

analyzed .was mixed with drilling water. 

No. 35 is probably not a simple modified water 

but a mixture of normal and altered waters 

from strata above and below the oil zone. 

No. 36 is an almost completely altered water of 

the mixed type. Other analyses of modified 

waters ar^ Nos. 3 and 4 (p. 63) and No. 10 

(p. 65).

TABLE 20.—Analyses of modified ground water from the 

[See also analyses 3 and 4, Table 14,

Sunset- Midway field. 

and analysis 10, Table 15.]

PROPERTIES OF REACTION IN PER CENT.

Primary alkalinity. ....................................... . .

Per cent of rS04 in rS04+rCl. ................................

Ratio of rC08+rHCO8 to rSO4 ................................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na) .................................................

Calcium (Ca). . ...............................................

Iron (Fe). ....................................................

Aluminum (Al).. . ...........................................

Sulphate (SO4) ...............................................

Chloride (Cl).. ..............................................

Carbonate (CO,) .............................................

Bicarbonate (HCO8).... . .....................................

Silica (Si02)... . .............................................

Hydrogen sulphide (H2S) ....................................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa") ............................................

Potassium (rK) ...........................................

Alkaline earths:

Magnesium (rMg). . .......................................

Strong acids: 

Sulphate (rSO4).... . .....................................

Chloride (iCl)... .........................................

Weak acids: 

Carbonate (rC08) ........................................

33

9

« 8, 79

39 

6 

b

1,38 

13,30 

07

4

24,05

«M

4.0 

5.4 

0 

.6

7.0 

.08

1

7 

1 

2.4

1 

4 

1

5

5.4

7.0

„

.6

3.5 

46.2

...

34

56.6 

0 

11.0 

32.4

64 

1.2

« 93

26

8 

64.8

103 

43

077

9.6

364.4

a33.8

10.7 

5.5

18.1 

10.2

C21.7

35

44.6 

0 

39.0 

16.4

58.3 

2.1

618 

33 

31 

45 

Trace. 

3.1 

403 

210 

160 

693 

115

1, 959. 1

40.5 

1.3

2.4 

5.8

13.0 

9.3

8.3 

19.4

36

77.4 

0 

15.6 

7.0

1.2 

22.6

4,969 

102 

109 

144

109 

6,740 

0 

2,623 

67

14,025 

1.3

46.0 

.5

1.1

2.4

.5 

38.2

0 

11.3

a Reported and calculated as sodium but includes potassium.

Reported and calculated as carbonate but probably in part bicarbonate

33. Standard Oil Co. well 6, sec. 12, T. 32 S..R. 23 E. Water from depth of 670 to 730 feet, or about 2,500> 

feet above top of zone C. Analyst, Standard Oil Co., January, 1912.

34. Midway Basin Oil Co. well in sec. 28, T. 31 S., R. 24 E. Wate: 

tered, and if oil ispresent it is probably more than 1,500 feet deeper.

35. Stratton Water Co. well 3, sec. 7, T. 32 S., R. 23 E. Water f 

and 790 feet. Probably a mixture of water from beds just above the 

Sampled by G. S. Rogers, August, 1914. Analyst, S. C. Dinsmore.

36. Union Oil Co. water well, Diamond No. 2, sec. 13, T. 11 N., R. 

650 feet, or about 100 feet above the oil. Sampled by G. S. Rogers, September.

r from depth of 2,980 feet. No oil encounAnalyst, Standard Oil Co., November, 1910. 

m depth of 600 to 615 feet; oil between 600

oil measures and water from Maricopa shale.

from

24 W. Sulphur water from depth of about 

, 1915. Analyst, S. C. Dinsmore.
84 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PART II.

No. 33, which represents water encountered 

at a depth of 670 feet in Midway Valley, differs 

from the waters discussed above in its rather 

close resemblance to sea water. Its reactive 

properties are similar, its concentration is only 

slightly less, and it is clearly to be regarded 

as a slightly altered brine allied to those shown 

in Table 22. This is remarkable, for the water 

occurs in the upper part of the McKittrick 

group, or the Paso Robles (u Tulare ") formation, 

which consists of deposits laid down in fresh

water and which has probably never been 

submerged beneath the sea. This water, 

therefore, presumably represents sea ^ater 

that was originally entrapped in the marine 

strata below and that has since migrated to the 

higher beds. Such an ascent would imply 

that the escape of the deeper waters by lateral 

migration through the beds is practical^ cut 

off and throws light on the completeness with 

which the connate water is trapped in the Midway syncline.

TABLE 21.—Analyses of altered water (brine) from the northern part of Midway Valley and Buena Vista Hills.

PROPERTIES OP REACTION IN PER CENT.

Primary salinity ...............................

Primary alkalinity. .............................

Per cent of rSO4 in rSO4+rCl ...................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na).... . ..............................

Potassium (K). . ................................

Calcium (Ca). .................................

Sulphate (S'Ojl. !'.............. 1..". .7..........

Chloride (Cl). ...................................

Carbonate (CO3). . ...............................

Bicarbonate (HCO3). . ..........................

Silica (SiO2).... ......... '......................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa). . ............................

Potassium (rK). . ...........................

Alkaline earths:

Magnesium (rMg) ...........................

Strong acids: 

Sulphate (rSO4).. . .........................

Chloride (rCl).. .............................

Weak acids: 

Carbonate (rCO3). . ..........................

Bicarbonate (rHCO3). ......................

37

91.4 

5.4 

0 

3.2

Trace.

}l3,470

712 

239

.4 

21, 946 

124 

1,021

74

37, 075. 4

| 45.7

2.8 

1.5

48.4

.3 

1.3

38

75.9 

22.5 

0 

1.6

.01

o 10,522

2,894 

7.2 

35 

31 

20, 955 

6293

18

34, 755. 2

a 37. 95

12.00 

.05

.05 

49.15

6.80

39

83.2 

15.8 

0 

1.0

.4

a 10,559

1,411 

281 

51 

108 

19, 289 

6159

84

31, 942

a 41. 6

6.4 

2.0

.2 

49.3

& 5

40

88.6 

9.4 

0 

2.0

Trace.

11, 120

496

457

2.4 

18, 920 

90 

506 

106

31,440.4

44.3

2.3 

3.4

49.0

.3

.7

41

83.6 

14.4 

0 

2.0

0

13, 513

1,272 

643

0

24,398 

6429

41

40, 296

41.8

4.5 

3.7

49.0 

61.0

42

91.8 

6.6 

0 

1.6

0

10,704

284 

326

0 

17,631

6243

12

29.200

« 45. 9

1.4 

2.7

0

49.2

6.8

a Reported and calculated as sodium but includes potassium.

& Reported and calculated as carbonate but probably in part bicarbonate.

37. Caribou Oil Co. well 2, sec. 28, T, 31 S., R. 23 E. Water from depth of about 3,000 feet probably d?rived 

from water sand in upper part of zone C. Sampled by G. S. Rogers, September, 1915. Analyst, S. C. Dinsmore.

38. Standard Oil Co. well 6. sec. 22, T. 31 S., R. 23 E. Water from depth of 2,700 feet or near top of zone C. 

Analyst, Standard Oil Co., April, 1915.

39. Standard Oil Co. well 7, sec. 22, T. 31 S., R. 23 E. Water from depth of 2,740 to 2,855 feet, or abcut 150 

feet below top of zone C. Analyst, Standard Oil Co., April, 1915.

40. Brookshire Oil Co. well 5, sec. 24, T. 31 S., R. 22 E. Probably water from above zone C (edge water of zone B). 

Sampled by G. B. Rogers, September, 1915. Analyst, C. S. Dinsmore.

41. Associated Oil Co. well, Pioneer Midway No. 3, sec. 30, T. 31 S., R. 23 E. Water is either the edge water of 

zone B and therefore above the main oil sand or is in zone C and below this sand. Analysts, Smith, Emery & Co. 

Authority, Associated Oil Co.

42. Associated Oil Co. well, Pioneer Midway No. 7, sec 30, T. 31 S., R. 23 E. Water from depth of 2,840 to 2,885 

feet, or near base of zone C. Analysts, Smith, Emery & Co. Authority, Associated Oil Co.
ANALYSES OF OIL-FIELD WATERS. 85

WATERS ASSOCIATED WITH THE OIL.

BRINES IK THE CENTRAL AND EASTERN PARTS OF THE 

FIELD.

Analyses 37 to 52 (Tables 21, 22, and 23) 

represent the brine or altered fossil sea water 

associated with the oil in Midway Valley, the 

Buena Vista Hills, and Maricopa Flat. All 

these waters, like sea water, have secondary 

salinity, but none of them contain more than 

a few parts per million of sulphate, and many 

contain only a trace. All but two of the 

analyses represent waters closely associated 

with the oil, and there appears to be no general

TABLE 22. — Analyses of altered water (brine)

PROPERTIES OP REACTION IN PER CENT.

Secondary alkalinity. . ........................

Per cent of rS04 in rSO4 -frCl. ..................

CONSTITUENTS IN PARTS PER MILLION.

Sulphate (S04) ...............................

Chloride (Cl)... ...............................

Carbonate (COg)...................... .........

Bicarbonate (HC03). .........................

mc&(8iOJ.. ...............................

REACTING VALUES IN PER CENT.

Alkalies:

Potassium (rK). . .........................

Alkaline earths: 

Calcium (rCa) ............................

Magnesium (rMg). . .......................

Strong acids: 

Sulphate (rSO4).. . .......................

Chloride (rdl).. ...... .....................

Weak acids: 

Carbonate (rCO3) ..........................

Bicarbonate (rHCO3) .....................

43

82.6 

16.2 

0 

1.2

.6

«8, 119

' 787 

417

99 

14, 846 

6151

24

24, 443

«41.3

4.6 

4.1

.3 

49.1

6.6

difference 

and those 

which resei 

a horizon 

zone B, bu 

unusual oc 

water pro 

Analysis 5' 

erties to th 

feature wh 

fact that i 

several the 

than the ( 

ductive fie

from Midway

44

83.8 

13.4 

0

2.8

.06

al3, 253

l;089 

685 

11 

18 

23, 553 

6626

65

39,300

o4L9

4.0 

4.1

48.5 

61.5

"1

1

3

oetween the waters in oil zone B 

in zone C. In fact, analysis 45, 

ables the rest, represents water from 

learly 1,000 feet above the top of 

i this appears to be an isolated and 

currence, and in general modified 

>ably extends below this horizon. 

! represents a water similar in prope rest but very much more dilute, a 

ich is probably connected with the 

} occurs in the Vaqueros formation 

usand feet stratigraphically lower 

>ther waters and outside the prod.

Talley and Buena Vista Hills.

45

86.8 

12.8 

0 

. .4

.2

),502

983 

241

48 

5,473 

675

15

>,337

«43.4

1..... ..

4.7 

1.9

.1

49.7

6. 2

46

84.2 

14.6 

0 

1.2

.01

ol5, 015

1,895 

342 

11 

32 

27,102 

6275

60

44,732

«42.1

6.1

1.8

49.4 

6.6

47

82.0 

17.0 

0 

1.0

.01

11, Oil 

156 

1,188 

510

9 

18, 750 

0 

280 

123

31, 885

o40. £ 

.4

5.3 

3.7

Trace. 

49.5

0 

.5

48

73.6 

21.0 

0 

.4

.02

012, 734

886 

1,300 

6 

7 

24,864 

692

112

40,001

«39.3

3.1 

7.6

49.8 

6.2

a Reported and calculated as sodium but includes potassium.

& Reported and calculated as carbonate but probably in

43. Union Oil Co. well 1, sec. 34, T. 31 S., R. 23 E. Water from a short distance above the oil sand; probably 

edge water in zone B. Analysts, Smith, Emery & Co.

44. Associated Oil Co. well 2, sec. 32, T. 31 S., R. 23 E. Water from a short distance above 3,100 feet, or some 

225 feet above top of zone C; probably edge water in zone B. Analysts, Smith, Emery & Co. Authority, Associated 

Oil Co.

45. Standard Oil Co. well 1, sec. 12, T. 32 S., R. 23 E. Water from depth of 2,055 to 2,075 feet.' Top of zone C 

is at depth of about 3,500 feet, though well reached 3,827 feet without finding oil. Analyst, Standard Oil Co., May. 

1913.

46. Standard Oil Co. well 7, sec. 12, T. 32 S., R. 23 E. Water from iepth of 2,600 feet, or about 75 feet above 

top of zone C. Gas was encountered about 400 feet above the water. Analyst, Standard Oil Co., June, 1913.

47. Honolulu Oil Co. well 6, sec. 10, T. 32 S., R. 24 E. Water from depth of 2,755 feet, or 250 feet below top of 

zone B, about at top of zone C. Sampled by Paul Paine. Analyst, S. C. T""

48. Kern Trading & Oil Co. well in NW. \ sec. 13, T. 32 S., R. 23 E.

part bicarbonate.

water about 300 feet below top of. zone C. Analyst, Standard Oil Co., February, 1913.

Dinsmore. 

Water from depth of 3,455 feet, or bottom
86 . THE SUNSET-MIDWAY OIL FIELD, CALIF.—PABT II.

TABLE 23.—Analyses of altered water (brine) from the southern part of Midway Valley and from Maricopa Flit.

PROPERTIES OP REACTION IN PER CENT.

Primary salinity. ............................................

Per cent of SO4 in rSO4 -f rCl. .................................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na). . ...............................................

Calcium (Ca) .................................................

Iron oxide (FeoO3) and alumina (A12O3 ). . .....................

Sulphate (SO4)....... . .......................................

Chloride (Cl) ................................................

Carbonate (CO3) .............................................

Bicarbonate (HCO3).. . .......................................

Silica (SiO2). ........ . ................................

Carbon dioxide (CO2). . .......................................

REACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths:

Strong acids: 

Sulphate (rSO4) ..........................................

Chloride (rCl) ...........................................

Weak acids: 

Carbonate (rCO3) ........................................

Bicarbonate (rHCO3). . ...................................

49

48.6 

5.0 

0 

46.4

Trace.

« 1, 323

1,223

1.7 

3.6 

2,254 

& 1,645

4.1

6,454.4

«24. 3,

25.7

26.8 

&23.2

'50

84.0 

11.4 

0 

4.6

0

a9,855

1,064 

345 

5 

0 

17, 231 

& 692

10

29, 202

042. 0

5.2

2.8

47.7 

&2.3

51

87.4 

10.6 

0 

2.0

.2

aS, 026

222

474

54 , 

13, 800 

& 238

15

22,829

43.7

1.4 

4.9

.1 

48.9

&1.0

52

85.0 

12.6 

0 

2.4

.48

| 671

69 

21

7.8 

1,170 

0

48 

5

1, 967. 8 

F"?8ent.

\ 42.5

5.0 

2.5

.2

48.6

.0

1.2

« Reported and calculated as sodium, but includes potassium.

6 Reported and calculated as carbonate but probably to part bicarbonate.

49. Standard Oil Co. well 3, sec. 20, T. 32 S., R. 24 E. Water from depth of 3,250 feet, or 125 feet below top of 

zone B. Probably edge water in zone B. Analyst. Standard Oil Co., February, 1911.

50. Standard Oil Co. well 1, sec. 28, T. 32 S., R. 24 E. Water from depth of 2,390 feet, or about 400 feet above 

top of zone B. Analyst, Standard Oil Co., August, 1909.

51. Standard Oil Co. well 5, sec. 28, T. 32 S., R. 24 E. Bottom water from depth of 3,704 feet, or about 7'X) feet 

below top of zone B. Analyst, Standard Oil Co., March, 1915.

52. Sunset Security Oil Co. well 1, sec. 29, T. 11 N., R. 23 W. Flowing water, probably from depth between 

2,992 and 3,997 feet, or below several shows of oil, and in Vaqueros formation. Sampled by G. S. Rogers, September, 

1915. Analyst, S. C. Dinsmore.
ANALYSES OF OIL-FIELD W[ATERS.

The concentration of the brines ranges in 

general between 25,000 and 40,000 parts per 

million and averages about 35,000 parts. Most 

of the brines containing less than 35,000 parts 

occur along the western edge of the brine area, 

or near the belt in which the more dilute meteoric waters have penetrated and have formed 

waters of the mixed type. These more dilute 

brines are also lower in secondary salinity because of the admixture with meteoric water 

and constitute a gradation toward waters of 

the mixed type, which are arbitrarily defined 

as waters of primary alkalinity instead of secondary salinity. The line separating the brine 

area from that in which waters of the mixed 

type occur is shown on Plate II, and the chemical gradation across this line is shown graphically in figures 5 and 6.

WATERS OF THE MIXED TYPE IN THE WESTERN PART 

OF THE FIELD.

Analyses 53 to 75 (Tables 24 to 27) represent 

altered waters of the mixed type associated with 

the oil in the western part of the field, or the 

shallower territory near the outcrop. All of 

these waters show primary alkalinity and contain practically no sulphate. As already stated, 

they are believed to have originated through 

the mixing of altered meteoric waters, entering 

at the outcrop, with the altered fossil sea water 

trapped in the Midway syncline* The water 

occurring nearest the outcrop are therefore in 

general predominantly meteoric, being more 

dilute and showing stronger primary alkalinity 

than those nearer the boundary of the brine 

area. (See figs. 5 and 6.) It is noteworthy, 

however, that the two waters which are most 

strongly meteoric and contain the smallest proportion of chloride occur in the extreme northern part of the field, or in the shallow territory 

in which several of the southward-pitching folds 

that dominate the structure of the main field 

originate.. (See analyses 7, p. 63, and 53,

87

p. 88.) I It appears entirely probable that in 

such a locality meteoric waters would penetrate 

unusually far from the outcrop and drive down 

most of the salt water, though as both samples 

were taken near a fault, which may have disturbed the circulation within a limited area, it 

is impossible to say whether or not they are 

characteristic of the waters in the whole northern part of the field.

OU zone A is productive in much of the area 

in which waters of the mixed type occur, and 

many of the analyses listed represent waters 

associated with this zone. Similar waters extend above zone A as far as the tar-sand zone, 

the waters of which are modified but generally 

not completely altered. (Compare analyses 10, 

p. 65, and 36, p. 83.) In much of the belt in 

which waters of the mixed type occur zones 

B and C are also recognized, and there appears 

to be no essential difference between the water 

of zone A and those of the deeper zones. In 

fact, as shown by several of the analyses, waters 

occurring in the Maricopa shale many hundred 

feet below the productive oil measures are entirely similar to those associated with zone A.

Invasion of the oil sands by water has proved 

troublesome in parts of the Twenty-five Hill 

district near Taft, and as there has been some 

difference in opinion concerning the original 

source of the water, the analyses given in Table 

25 are Of interest. Mr. Pack, on the basis of 

stratigraphic studies, regards the water as derived v6ry largely from a bottom water sand 

occurring at the base of the oil measures, 

and the evidence afforded by analyses of the 

waters appears to be entirely concordant. Analysis 60 represents a sample of water from 

the bottom water sand, and No. 61 a sample 

from a veil near by producing water from an 

unknown source; the two waters are evidently 

the same. Analyses 63 and 62, representing 

respectively the bottom water and water from 

an unknown source, offer similar testimony.
88 THE SUNSET-MIDWAY OIL, FIELD, CALIF.——PART II. 

TABLE 24.—Analyses of altered water (mixed type) from the western part of the Midway field north of Twenty-five Hill.

PROPERTIES OF REACTION IN PER CENT.

Ratio of rSO4 to rSO4+rCl... . .........

CONSTITUENTS IN PARTS PER MILLION.

Sulphate (SO4) . . .....................

Chloride (Cl). ........................'.

Carbonate (CO3 )......... ..............

Silica (SiO2).. .......................

REACTING VALUES IN PER CENT.

Alkalies:

Potassium (rK). ..................

Alkaline earths:

Strong acids: 

Sulphate (rSO4) ..................

Chloride (rCl) ...................

Weak acids: 

Carbonate (rCO3). . ................

Bicarbonate (rHCO3) .............

53

40.2

0

57.8

2.0

1.5

2,052

9.7

19

11

5.9

28

1,293

342

2,372

72

5, 178. 6

48.9

.1

.5

.5

g

19.8

6.2

23.7

54

74.8

0

24.4

.8

0

3,140

24

9.3

3.6

0

3,662

219

1,708

40

7, 939. 9

49.4

.2

.2

.1

0

37.4

2.6

10.1

55

71.8

0

24.4

3.8

.02

«4, 110

55

55

2

4,723

61, 569

77

10, 591

a 48.1

.7

1.2

0

35.9

614.1

56

66.6

0

30

3.4

.13

«3,434

50

35

6.6

3,650

61,545

55

8, 775. 6

«48.3

.8

.9

33.3

616.7

57

70.3 1 0

26.3

3.4

.08

«3, 955

50

44

5.5

4,428

61,590

72

10, 144. 5

«48.3

.7

1.0

35.1

614.9

58

83.6

0

11.8

4.6

.01

«7,090

73

135

13

4.5

9,566

61, 588

44

18, 513. 5 

.0

047.7

.6

1.7

Trace

41.8

»8.2

59

77.2

0

21.6

1.2

.01

«5, 933

29

21

6

7,125

61,784

117

15,015

o49 4

.3

.3

Trace.

38 6

611.4

a Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

53. General Petroleum Co. Carnegie water well, sec. 9, T. 31 S., R. 22 E. Water from Maricopa shale at de-uh 

of 3,860 to 3,880 feet, or at least 3,000 feet below base of oil measures. Sampled by G. S. Rogers, July, 1914. Analyst, 

S. C. Dinsmore.

54. Associated Oil Co. well 1, sec. 35, T. 31 S., R. 22 E. Bottom water from depth of 1,495 to 1,727 feet, or ab^ut 

50 feet below top of zone C. Sampled by G. S. Rogers, July, 1914. Analyst, Chase Palmer.

55-£8. North American Oil Consolidated Co. wells in sec. 16, T. 32 S., R. 23 E. Analysts, Smith, Emery & Co. 

Authority, North American Oil Consolidated Co. 55, Well 1, bottom water from sands between 1,675 and 1,840 feet, 

or about 325 feet below top of zone A; 56, well 16, bottom water probably from 1,150 feet, or about 300 feet below top 

of zone A; 57, well 21, water apparently from sands between 1,151 and 1,345 feet, or in zone A; 58, well 71, bottom 

water probably from about 3,200 feet, or about 1,200 feet below top of zone B and presumably in Maricopa shale.

59. Standard Oil Co. well 2, sec. 14, T. 32 S., R. 23 E. Top water from depth of 2,000 feet, or above top of z-^ne 

B. Analyst, Standard Oil Co., July, 1909.
ANALYSES OF OIL-FIELD WATEBS. 89 

TABLE 25.—Analyses of altered water (mixed type) from Twenty-five Hill area (southwestern part of T. 32 S., R. 23 E.\

PROPERTIES OP REACTION IN PEE CENT.

Secondary alkalinity. .................

Ratio of rSO4 to rSO4+rd. ............

CONSTITUENTS IN PAKTS PER MILLION.

Sodium (Na) .........................

Calcium (Ca). . .......................

Magnesium (Mg). . ....................

Iron (Fe).. ...........................

Aluminum (Al) ......................

Sulphate (SO4) .......................

Chloride (Cl). ........................

Carbonate (CO,).......................

Bicarbonate (HCCO ..................

Silica (SiO2)..... ....................

KEACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths: 

Calcium (rCa) ....................

Magnesium (rMg) .................

Strong acids: 

Sulphate (rSO4).. ..................

Chloride (rCl)....... ..............

Weak acids: 

Carbonate (rCO3) ..................

60

64.0

0

33.2

2.*

Trapp

| 3, 921

07

41

TVopp

i

3,977

0

3

QKC

136

10, Oil

| 48.6

.5

.9

Trace.

32

0

18.0

61

65.4

0

32.8

1.8

.01

(o 7fiQ

1 ^ifi

20

24

ftO

4.7

4

3,924

000

3,184

118

9, 706. 72

f 48.7

I -4

.3

.6

oo 7

2.2

15.1

62

60.8

0

07 ft

9 9

.1

3

0 Cft

47

98

24

ftO

4.2

11

3

070

48

q RQA

197

8, 724. 22

48.5

.4

.5

.6

.1

oft q

.5

19.1

63

62.6

0

35.4

2.0

0.2

3,627

30

41

17

0.3

6.6

14

3,608

0

q 7Qq

122

9, 333. 9

48.8

.2

.6

.4

.1

31.2

.0

18.7

64

80.0

0

^ 14.8

5.2

Trapp

4 QIC;

93

55

107

8.8

6,336

108

2,281

83

12, 827. 8

46.9

.5

.6

2.0

Trace.

40.0

.8

9.2

65

76.0

0

20.2

3.8

.01

«3, 595

50

48

| ol.7

3.2

4,370

cl, 172

117

15, 015

«49.4

.3

.3

Trace.

38.6

ell. 4

66

65.4

0

31.2

3.4

.02

«2, 828

35

30

68

40

2,917

cl,320

39

7,217

048.3

.7

LO

.3

32.4

C17.3

o Reported and calculated as sodium but includes potassium.

6Fe2O3+Al2O3 .

c Reported and calculated as carbonate but probably in part bicarbonate.

60. General Petroleum Co. well 2, sec. 15. Bottom water from depth of 1,7 

below top of zone B. (See PI. XXXVIII of Part I, Prof. Paper 116.) Sampled by 

S. C. Dinsmore.

61. Traders Oil Co. well 71, sec. 23. Water produced with oil from sands of zone A 

1,200 and 1,300 feet. Note similarity to 60. Sampled by G. S. Rogers, July, 1914

62. Mascot Oil Co. well 17, sec. 26. Thought to be bottom water produced 

feet, or about 500 feet below top of zone A. (See PI. XXXVIII of Part I, Prof. 

Sampled by G. S. Rogers, July, 1914. Analyst, S. C. Dinsmore.

63. Crescius Oil Co. well 6, sec. 25. Bottom water from depth of 1,460 feet, or 

(See PI. XXXVIII of Part I, Prof. Paper 116.) Sampled by G. S. Rogers, June,

5 to 1,820 feet, or about 150 feet 

i. S. Rogers, July, 1914. Analyst,

, probably from depth between 

Analyst, S. C. Dinsmore. 

i sand at depth of about 1,500 

Paper 116;) Note similarity to 63.

f'om

/bout 475 feet below toj> of zone A. 

14. Analyst, S. C. Dinsmore. 

: about 3,000 feet; apparently in

1914

64. Chanslor-Canfield Midway Oil Co. well 7, sec. 24. Water from depth o 

zone C. Sampled by G. S. Rogers, September, 1915. Analyst, S. C. Dinsmore.

65. Standard Oil Co. well 3, sec. 24. Water from depth of 1,505 feet; edge water of zone A and about 75 feet 

above top of zone B. Analyst, Standard Oil Co., April, 1909.

66. B. H. & C. Oil Co., sec. 25. Water produced with oil from several wells, 

same sand as sample 63. Analysts, Smith, Emery & Co. Authority, Section Tweaty-fh

Probably derived chiefly from 

/-five Oil Co.
90 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II. 

TABLE 26.—Analyses of altered water (mixed type) from area southeast of Twenty-five Hill.

PROPERTIES OF REACTION IN PER CENT.

Secondary salinity. .........................................

Primary alkalinity.......... .................................

Secondary alkalinity. ........................................

Per cent of rSO4 in rSO4+rCl ..................................

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na). ...............................................

Potassium (K). . .............................................

Calcium (Ca). . ..............................................

Iron (Fe).. ..................................................

Aluminum (Al). . ...........................................

Sulphate (SO4)........... ...................................

Chloride (Cl).... .............................................

Carbonate (CO,)................. .............................

Bicarbonate (HCO3 ) .........................................

Silica (SiO2)... . ............................................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa). . .........................................

Potassium (rK) - - * -, -

Alkaline earths: 

Calcium (rCa). . .........................................

Magnesium (rMg). . ......................................

Strong acids: 

Sulphate (rSO4)..... . ...................................

Chloride (rCl). ...........................................

Weak acids: 

Carbonate (rCOg). . .......................................

Bicarbonate (rHCO3). . ..................................

67

70.4

0

25.9

3.7

.53

o4,442

37

67

612

37

4,970

el, 784

119

11,468

«48. 1

.5

1.4

.2

35.0

cl4. 8

68

70.4

0

27.2

2.4

.57

o4, 413

18

45

69

4

4,872

cl, 748

104

11, 250

048.8

.2

.9

.2

35.0

cl4. 9

69

76

0

20.8

3.2

.32

03, 971

43

43

87

4,726

cl, 284

10,154

«48.4

.6

1.0

.5

37.5

cl2.0

70

74.0

0

23.2

2.8

.4

5,019

22

79

26

.02

4.2

5, 913

0

3,721

P4

13, 012. 22

48.5

.1

.9

.5

.2

ft 8

0

33.0

a Reported and calculated as sodium but includes potassium.

6 FejOa + A1SO3 .

c Reported and calculated as carbonate but probably in part bicarbonate.

67. Section Twenty-five Oil Co. well 7, sec. 25, T. 32 S., R. 23 E. Water produced with oil: probably derved 

from bottom-water sand at base of zone A. Analysts, Smith, Emery & Co. Authority, Section Twenty-five OL Co.

68. Section Twenty-five Oil Co. well 11, sec. 25, T. 32 S., R. 23 E. Water produced with oil: probably derved 

from bottom-water sand at base of zone A. Analysts, Smith, Emery& Co. Authority, Section Twenty-five Oil Co.

69. Standard Oil Co. well Monarch C, sec. 26, T. 12 N., R. 24 W. Water from depth of 2,156 to 2,182 feet, or 

about 600 feet below top of zone B and about 450 feet below top of Maricopa shale. Analyst, Bird-Archer Co., 

December, 1913.

70. Standard Oil Co. well M. & M. 7, sec. 36, T. 12 N., R. 24 W. Water from depth of 2,385 to 2,870 fee*,, or 

about 1,400 feet below top of zone B and about 1,250 feet below top of Maricopa shale. Sampled by G. S. Ropers, 

August, 1914. Analyst, S. C. Dinsmore.
ANALYSES OF OIL-FIELD WATEES, 

TABLE 27.—Analyses of altered water (mixed type) from the western

PROPEBTIES OF BEACTION IN PEB CENT.

Secondary salinity. .....................................

Primary alkalinity. ....................................

Secondary alkalinity. ..................................

Per cent of rS04 in rSO4+rCl ...........................

CONSTITUENTS IN PABTS PEB MILLION.

Sodium (Na) ............................................

Potassium (K) .........................................

Calcium (Ca). .........................................

Iron (Fe). . ............................................

Sulphate (SO4). . ......................................

Chloride (Cl). ..........................................

Carbonate (COa) ........................................

Bicarbonate (HCO3) .....................................

Silica (SiO2).. ..........................................

BEACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa). . .....................................

Potassium (rK). ...................................

Alakline earths:

Strong acids: 

Sulphate (rSO4)... ..................................

Chloride (rCl)..... .................................

Weak acids: 

Carbonate (rCCV).. ........ .........................

Bicarbonate (rHCO3) ...............................

71

70

0 .

28.3

1.7

0

«4, 478

13

33

4,903

cl, 780

11, 207

a49.1

.2

.7

35.0

<15.0

72

82.6

0

14.6

2.8

.04

a6,440

71

59

&.34

5

8,418

0

3,074

89

16, 595. 34

a48.6

.6

.8

41.3

0

8.7

73

62.8

0

33.6

3.6

.09

03, 737

65

38

5

3,754

cl,880

123

9,602

"48.2

.9

.9

31.4

cl8. 6

74

74.2

0

23.0

2.8

.4

3,649

24

57

23

.3

4.5

27

4,364

0

2,818

98

9, 633. 8

48.4

.2

.8

.6

.2

36.9

0

12.9

75

66.8

0

30.2

3.0

.2

4,104

60

65

28

.14

4.6

27

4,435

0

3,965

125

10, 799. 74

48.1

.4

.9

.6

.1

33.3

16.6

91

of the Sunset field.

Reported and calculated as sodium but includes potassium.

FesOs+AlsOj.

Reported and calculated as carbonate but probably in part bicarbonate.

71. Occidental Oil Co. well 4, sec. 2, T. 11 N., R. 24 W. Bottom water from depth of 

feet below top of zone A, in Maricopa shale. Analysts, Straus & Co. March, 1910.

72. Adeline Consolidated Oil Co. water well 31; sec. 2, T. 11 N., R. 24 W. 

to 1,875 feet, or 1,400 feet below top of zone A, in Maricopa shale. Sampled 

Analyst, S. C. Dinsmore,

73. Northern Oil Co. water well, sec. 12, T. 11 N., R. 24 W. Water from ss,nd at depth of 1,423 feet, or about 

150 feet below top of zbne B. Analyst, Standard Oil Co., August, 1909.

74. Good Roads Oil Co. well 14, sec. 12, T. 11 N., R. 24 W. Flowing water froi 

about 2,350 feet below top of zone B and 2,000 feet below top of Maricopa shale 

1914. Analyst, S. C. Dinamore.

75. Mancopa Producers Oil Co. well 1, sec. 8, T. 11 N., R. 23 W. Flowina 

about 200 feet below top of zone B. Sampled by G. S. Rogers, July, 1914. Analyst,

-icywji u* 1,505 to 1,556 feet, or 1,100 

Authority, Sunset Monarch Oil Co. 

Bottom water from depth of 1,828 

by G. S. Rogers, September, 1915.

om depth of 3,550 to 3,700 feet, or 

Sampled by G. S. Rogers, July,

2; water from depth of 2,165 feet, or 

* ',, S. C. Dinsmore.
92 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

TABLE 28.—Assays (partial analyses) of waters from the Sunset-Midivay field.

[Parts per million.]

Designation.

A 

B

- C

D

E

F 

G 

H 

I 

J 

K 

L

M

N 

O

Lease.

Toronto Midwav. .......

.....do..................

.....do..................

Chanslor-Canfield Midway Oil. 

American Oilfields. ....

.....do..................

American Oilfields. ....

EthelD. ...............

Jewett & Blodgett .....

.....do..................

" Flowing; brine well " . . Well at Salt Marsh. .....

Spring. .............. t .

Well

No.

1 

76 

92 

73 

12

57 

23 

14 

6 

21 

3 

2

Location.

Sec.

18 

36 

36 

36 

36

36 

36 

32 

32 

36 

28 

28

13 

11 

13

T.

31 S. 

31 S. 

31 S. 

31 S. 

31 S.

31 S. 

31 S. 

32 S. 

12 N. 

12 N. 

UN. UN.

11 N. UN.

UN.

R.

23 E. 

22 E. 

22 E. 

22 E. 

22 E.

22 E. 

22 E. 

24 E. 

23 W. 

24 W. 

23 W. 

23 W.

24 W. 

24 W. 

24 W.

Insoluble 

solids.

......

200 

150

36, 

10,

Soluble 

solids.

33, 040 

8,010

6,630

8,660 

7,140

20, 720

26, 484 

27, 618 

72,930

678 

769

18, 945

11, 440

5,883

Calcium 

(Ca).

236 

1,709 

111

Magnesium 

(Mg).

180 

188 

465

Chlorine

(Cl).

17, 800 

3,420 

400

2,840 

3,280

7,720 

14, .840 

16,440 

30,800 

17,800 

22, 159 

10, 769

8,774 

5,995 

1,693

Interpretation of type of wate%

Brine (altered). 

Mixed type (altered). 

Mixed type (modified?) 

Mixed type (altered). 

Do.

Do. 

Brine (altered). 

Do. 

Do. 

Do. 

Do. 

Brine (modified), probfbly mixed with surface 

water. 

Mixed type? 

Do. 

Normal ground water.

A-J. Assays made and furnished by American Oilfields Co.

K-0. Partial analyses cited by Watts, W. L., The gas and petroleum yielding formations of California: California State Min. Bur. Bull. 3, pp. 91-92, 1894.

INVASION OF OIL SANDS BY WATER. 

GENERAL STATEMENT.

The problem of preventing the invasion of 

oil sands by water is recognized by California 

operators as one of the most important problems confronting the industry to-day. The 

disastrous results of such invasion have been 

only too well shown in parts of all the California 

fields, and during the past few years a considerable amount of study has been devoted not 

only to methods for the exclusion of the water 

while a well is being drilled, but also to methods of tracing the source of water that may 

appear in the well some time after its completion. The actual exclusion of water from the 

well is largely a technologic problem which 

falls outside the scope of this report, but the 

problem of tracing the migration of the water 

and of determining its source is largely geologic 

and will be briefly considered in the following 

pages.

The removal of oil and gas from an inclosed 

sand naturally results in a disturbance of the 

pressure equilibria that had previously existed, 

lowering the pressure in the sand and thus 

creating a tendency on the part of the fluids 

in neighboring beds to migrate toward the 

sand and into it. Water is, of course, the most 

abundant fluid in the surrounding beds, and 

its movement is facilitated by its low viscosity.

The bore hole itself affords an artificial line of 

communication between the beds, and thh 

channel, even when blocked and obstructed by 

every means at the driller's command, is prol - 

ably still more open than any natural crack or 

fissure would be. If there is water under hig^ 

head in a neighboring sand, the tendency cf 

this water to force its way past the barriers 

increases as more and more oil is removed frora 

the oil sand and as the pressure in the oil sand 

becomes correspondingly lower. It is chiefly 

for this reason that water troubles become 

more prevalent as the field grows older and 

also that the largest wells (those which have 

lowered the pressure most and have established 

drainage lines in the oil sand for a considerable 

distance around them) are especially liable to 

such troubles.

As the original gas pressure in many sands 

is somewhat greater than the hydrostatic 

pressure there is usually a brief early period 

during which invasion of the sand by water is 

impossible; and as more or less effective 

measures are taken to exclude the water, 

considerable time may elapse before the gas 

pressure is reduced sufficiently to enable th^ 

water to force its way past the barriers and 

enter the sands. Accordingly, in the earl" 

history of the field, when the gas pressure was 

high, little attention was paid to the exclusion 

of water, and when the pressure began to
INVASION

decrease and water began to appear in the 

wells it was generally thought that thj water 

and oil existed in the same sand and t lat the 

appearance of the water was therefore inevitable. When the damage became serious 

enough in several parts of the field to ( emand 

investigation and study, however, it was found 

that the water was extraneous and tint with 

proper precautions it might be excluced. It 

is interesting to note that not only the SunsetMidway field, but practically all other fields 

in California and the geologically similar fields 

in Russia, Rumania, and other countries, have 

had a similar history—an early period in 

which water was ignored, a second 

which its appearance was regarded ai 

table, and a third period characterized] 

investigation of the causes of water 

and an energetic campaign for their 

tion or removal. In the Sunset-Midwi 

much of the damage wrought by th 

wells has been repaired, and new w< 

being finished in such a way as to 

water almost perfectly. Nevertheless 

problem is by no means disposed of, 

time passes and the gas pressure becom 

the tendency of water to enter the 

become correspondingly greater.

On the assumption that it will cont 

be possible to exclude water from the o 

or to pump out such water as may ente 

it is evident that the time will 

come when the pressure in the inclose 

will be reduced practically to atmo 

pressure. Further extraction of the o 

perhaps be accomplished for a short 

vacuum pumps, but nothing like c 

extraction could be attained without 

another fluid to take the place of the 

gas removed. At this stage in the life 

field admission of compressed air or o 

to the oil sands would be beneficial ins 

disastrous, but this stage will eviden 

be reached for many years. Moreover 

or most of the oil sands themselves 

inclosed but become water-bearing 

dip, and as the oil is removed this wa 

naturally follow the oil up the slo 

replace it, thus maintaining a portion 

pressure. Proposals to deliberately 

water to enter the oil sands have alrea 

made, but for many years, at least, they (should 

not be considered.

even

OF OIL SANDS BY WATEB. 93

pejriod in 

ineviby an 

tjroubles 

piitigay field 

older 

11s are 

xclude 

i, the 

for as 

i lower 

sarlds will

nue to 

sands 

them, 

tually 

sands 

spheric 

could 

by

mplete 

admitting 

»il and 

of the 

water 

ead of 

ly not 

many 

,re not 

the

er will 

e and 

of the 

permit 

been

time

down

MANNER OF INVASION.

Extraneous water gains access to the oil 

sand either because the mechanical barriers 

placed to exclude it are inadequate or faulty, 

or because they are placed without proper 

regard for geologic conditions. The simplest 

example of invasion is the seepage of top 

water down the outside of the casing. This 

difficulty was common in the earlier days of 

the field but is now effectively overcome by 

forcing cement up around the end of the casing and into the space between it and the walls 

of the hole. Various mechanical conditions 

may of course impair or destroy the effectiveness of this shut-off; the cement may be 

improperly placed or may fail to set, or the 

casing may later collapse or may be corroded 

through by the chemical action of the water 

itself. Invasion by bottom water is also 

common and is caused by drilling the well 

either into a bottom-water sand or so close to 

it that when the gas pressure in the overlying 

oil sand is reduced and the fluid level in the 

well falls the bottom water bursts through, 

or the well "drills itself in." Bottom water 

is commonly under high head and may therefore be difficult to exclude..

Less obvious and less easily traceable difficulties are likely to be brought about by disregard of geologic conditions, for when water 

once gains access to a partly exhausted oil sand 

it may travel rapidly for considerable distances. 

One defective well may let enough water into 

the sand to flood it over many acres, thus causing a number of neighboring and properly 

finished wells to " go to water." Moreover, in 

a group of wells, each in itself properly finished, 

water troubles may arise through the location 

of the shut-off at different horizons. In well A, 

for example, the uppermost oil sands may be 

cased off witn the overlying water sands, 

whereas in the neighboring well B the shut-off 

may be placed above the uppermost oil sand. 

As this sand in well A is in free communication 

with the water sands it soon becomes flooded, 

and the water migrating through it will appear 

in well B. If more water enters well B in this 

manner than can be pumped out -the excess 

will pass into the lower or main producing oil 

sands and so may appear in well A and other 

neighboring wells. This condition has existed 

in several localities in the field, and when once
94 THE SUNSET-MIDWAY OIL FIELD, CALIF.——PART II.

permanently established it practically compels 

the abandonment of the upper sand in all the 

wells. As stated on page 51, this condition has 

been brought about especially in the "transition belts" (the belts in which the oil sands 

become water bearing) of oil zones A and B, 

for in these belts some of the operators are 

likely to case off the upper oil sands, whereas 

others attempt to obtain oil from them.

Wells drilled and abandoned in the early days 

of the field, before the geologic conditions were 

known, have proved a source of trouble in 

many localities, for it was formerly customary 

to pull the casing and abandon the hole without

that water containing sulphate or sulphide 

reacts with oil of the Sunset-Midway type, and 

that even a comparatively short period of 

association is likely to injure the quality of the 

oil. (See pp. 26-31.)

The chief result of water invasion is of course 

decrease in production. If the sand invaded 

is thin and carries light oil the gas pressure m ay 

be "killed" and a great decrease in production 

may immediately ensue. The effect on the 

production of such sands is too well known to 

operators to need description, but to those 

unfamiliar with the field figures 7 and 8, which 

represent typical instances of decrease in p"OPRODUCTION, BARRELS MONTHLY 

<> v<O ,0>C^P J» J* £foQQQooooocOr OQQOoOOO Doooooooo o c

\

\zv\ ?

\

\

>ERI

^.

ODC FIN

\

>

/ASI ON

X — — . — ^

OCT. NOV. DEC. JAN. FEB. MAR. APR. MAY JUNE JULY AUG. SEPT. OCT. NOV. DEC. JAN. FEB. MAR. APR. MAY 

1912 1913 191*

FIGUEE 7.—Diagram showing decrease in the production of an oil well in the northern part of the Midway field caused by the invasion of the

oil sand by water.

plugging it or otherwise destroying communication between the water and oil sands. So 

long as no oil was extracted from the oil sands 

no water could enter them, but when other 

wells were drilled and began to remove the oil, 

extensive invasion took place. One abandoned 

hole tapping a strong water sand may turn 

many hundred barrels of water a day into the 

oil measures, or more than a dozen neighboring 

wells can pump out.

EFFECTS OF INVASION.

The extent of tjie damage caused by the 

entrance of water into an oil sand depends on 

many factors, chief among which are the thickness, character, and stage of exhaustion of the 

oil sand, the volume and head of the water, and 

the chemical character of the water and oil. 

The importance of the last-named factor is 

conjectural, but there is reason to believe

duction through water invasion, may be of 

interest. In a thick oil sand carrying heavy 

oil with little gas the effects of invasion are bss 

noticeable, probably in part because the water 

collects at the bottom of the sand and does not 

interfere greatly with the removal of the oil 

above it, unless the well is pumped too rapidly. 

When a large amount of water enters the oil 

sand, however, it is likely to drive the oil br.ck 

and away from the well, and once the water has 

entered the sand it tends to cling in the interstices and prevent the flow of oil toward the 

well. When the amount of water entering the 

sand is so small that it may be pumped out 

with the oil, little or no permanent damage is 

done, though the process of raising the water 

to the surface and separating it from the oil of 

course involves considerable expense. The use 

of compressed-air lifts, capable of handling 

large volumes of fluid, may permit the removal
INVASION OP OIL SANDS BY WATEB. 95

of the water as fast as it enters the sand, though 

this process also is an expensive one.

A result of water invasion common in most 

of _ the California fields is the formation of a 

thick brown viscous liquid called emulsion,, 

consisting of an intimate mixture of oil and 

water. Emulsion is especially likely to form 

when water gains access to a flowing well or 

floods a sand containing light oil under considerable pressure, though it may also form in

15,000

In order to remove marketable oil from such 

refractory emulsions special treatment is required. Emulsions can be broken up by the 

addition of ether, which dissolves out the oil, or 

of salt, which is taken up by the water, but 

such methods are too expensive for commercial 

use. An old method consisted of heating the 

emulsion in open ditches lined with steam coils, 

but the heat attained was not high enough to 

break down a refractory emulsion and, on the

20,000r

2345678 9 10 II IE 13 14 15 16 17 18 

MONTHS

A.

7 & 9 10 II 

MONTHS

\Z 13 14 15 16 17 18

FIGURE 8.—Diagram showing in three ways the decrease in the preduction of oil caused by the invasion of the oil sand by water. 

A, barrels of oil, barrels of water, and percentage of water in total fluid plotted on natural stale; B, barrels o! oil and barrels of water 

plotted on logarithmic scale in order to magnify small variations in quantity of water and thus develop two easily comparable curves.

heavy .oil sands in which the pressure is comparatively low. Some emulsions separate out 

on standing a few days, but others remain stable 

for an indefinite period. The famous Lake view 

No. 1 gusher, which ceased flowing September 

9, 1911, produced considerable emulsion, some 

of which remained without separating in the 

bottom of a sump exposed to the airuntiljuly, 

1914. Emulsions are common in the Galician 

and Rumanian oil fields, and a thick viscous 

variety, known as marais, is so enduring that 

it is used to spread on roads, where it remains 

without change for as long as two years.1

1 Legrand, P., Sur les mouvements du p£trole et de 1'eau: 2d Cong. 

intemat. p6trole, LiSge, Compt. rend., 1905.

other hand, the more volatile'fractions of the 

oil were lost. Better results are obtained by 

"cooking" the emulsion in a boiler over a direct 

flame. At a temperature slightly above jbhe 

boiling point the water globules are converted 

into steam and condensed as free water, while 

the volatile fractions of the oil are condensed 

and saved.2 Several electrical processes have 

also been devised whereby the emulsion is subjected to the action of a high-tension current 

which punctures and agglomerates the globules 

of water and allows them to settle out.3

2 Hardlson, S. J., The dehydrating oil plant of the Nevada Petroleum 

Co., Ca'ifornia: Am. Inst. Min. Eng. Trans., vol. 51, p. 627,1915.

8 Beaz'.ey, A. T., Dehydration of crude petroleum: Oil Age, vol. 3, p. 2, 

Apr. 21, 1911. Harris, F. W., The Baney-Laird dehydrating system: 

Oil Age, vol. 11. D. 6. Januarv. 1915.
100 THE SUNSET-MIDWAY OIL FIELD, CALIF.—PART II.

analyses is a matter of simple comparison and 

depends only remotely on the principles involved in tlie variation in the water as it approaches the oil zone. In the Sunset-Midway 

field, where variations in the character of the 

water are not as marked as in other areas and 

where a slight difference in sulphate content 

may indicate a difference in position of several 

hundred feet, this method will probably be 

essential in the accumulation of an adequate 

amount of data regarding the character of the 

water in the 1,000 feet or so above the oil 

measures.

In comparing the analyses of two 'different 

waters all the mineral constituents must be 

taken into account and the presence or absence 

of petroleum acids should also be noted. The 

practice of attempting to estimate the horizon

of a water on the basis of a partial analysis is to 

be condemned. Some oil men have attempted 

to compare waters simply by tasting them, but 

it is evident that only the roughest distinctions 

can be made in this way, and the analyses 

given in this report suffice to show that the 

amount of salt a water contains is no indication 

of its horizon, except perhaps very locally. 

Others have used hydrogen sulphide f«* a 

means of identification, chiefly because it cam v. 

readily be detected by its odor, but as this con- „„, 

stituent is found only in the modified wr.ters 

its value as a criterion for comparison is limitedA complete analysis is always the most satisfactory, and several dozen such analyses cost 

less than the operation of bridging the well or 

attempting to determine the source of the water 

by other mechanical methods.
INDEX.

A. Page. 

Acids, organic, occurrence of..................................... 30

organic, test for... .....;..................................... 60

Acknowledgments for aid............ I.....'...................... 7

Alkalies, distribution of, in waters............................... 56

Alkaline earths, distribution of, in waters........................ 56-57

Alkalinity, primary and secondary, definition of................. 55

Altered waters, origin of.......................................... 64-66

position and examples of..................................... 62-64

(brines), analyses of....................................... 84,85-87

(mixed type), analyses of..................................... 87-91

Aluminum, occurrence of, in waters.............................. 58

Analyses of oil-field waters............................. 63,65,72,80-92

constituents to be determined In............................. 63

determination of source of flooding by........................ 99

method of stating............................................ 53

whence obtained............................................. 56

See also Assays of waters. 

Analysis of petroleum by distillation ............................. 10

elemental,indications from................................... 10

methods of................................................... 15-16

Anticlines. See Folds.

Aromatic hydrocarbons. See Benzene series.

Asphalt, formation of, at the outcrop of sands.................... 31

production of, by the action of oxygen........................ 29-31

by the action of sulphur................................ 29

Asphaltum, use of term.......................................... 22

Assays of waters................................................. 92

Associated Oil Co.'s well 1, water of, analysis of.................. 88

water of, character of......................................... 78

August Water Co.'s California Amalgamated well, water of,

analysis of........................................... 63

water of, character of......................................... 78

August Water Co.'s well 3, water of, analysis of.................. 72

water of, character of......................................... 78

B.

Bacteria. See Micro-organisms. 

Benzene series, presence of, in California petroleum............... 10,12

Bicarbonate. See Carbonate.

Bird-Archer Co., analysis by..................................... 90

Boiler compounds, ingredients of................................. 77

B oiler water, exampl es of........................................ 77-78

foaming in................................................... 75

mineral content allowable in................................. 74

objections to hardness in..................................... 74-75

sources of.................................................... 73-74

Boron, occurrence of, in waters................................... 58

Bottom water, invasion of oil sands by........................... 93

use of term................................................... 50

Brea, occurrence of............................................... 29

Brines, analyses of............................................ 84,85-87

areal distribution of, map showing........................... 70

mixing of fresh water with.................................... 68-70

changes in properties of reaction from.................... 70-73

origin of...................................................... 66-68

Bromine, distribution and 'significance of, in waters.............. 58

Buena Vista Lake, water of^ analysis of.......................... 78

water of, character of... «>.................................... 73,78

Burning point of petroleum; determination of.................... 16

Burning Springs, W. Va., petroleum from, analysis of............ 13

Burrel 1, G. A., analyses bj»....................................... 34,35

Butane, occurrence of, in natural gas............................. 33

• C.

Calcium, ratio of, to magnesium in oil-field brines................ 68

Calorific value of petroleum, determination of................... 16

Carbon dioxide, content of, in natural gas...................... 32,33-36

Carbonate, conversion of, to bicarbonate........................ 57

distribution of, in waters..................................... 57

Carbonate, increase of, in waters associated with petroleum...... 26-28

substitution of, for sulphate.................................. 67-68

Casing of wells, cementing of.................................... 78

corrosion of.................................................. 79-80

Cement, action of heat, gas, and oil on............................ 79

action of oil-field waters on................................... 78-79

Chanslor-Canfield Midway Oil Co.'s water wells, water of, analysis of................................................ 82

water of, character of......................................... 78

Chemical reactions, heating of petroleum by...................... 44

Cherryvale, Kans., petroleum from, analysis of................... 13

Chinoline, occurrence of, in California petroleum................. 14

Chloride, distribution and significance of, in waters............... 67

variation in, with depth and distance from outcrop...........' 68-70

Chloride-carbonate waters, origin of............................... 70-73

Classification of waters, methods of...................... 64-55,56,60-61

Collection of water samples, difficulties of........................ 52-53

Connate water. See Brines.

Corrosion by boiler water, acids causing.......................... 75-76

'estimation of.................................. 4.............. 76

Cracking, gasoline produced by.....

of petroleum tar.................

Cretaceous petroleum, -properties of.

D.

Dinsmore, S. C., analyses by ........ 63, 72, 81, 83, 8 1, 85, 86, 88, 89, 90, 91

Distillation of petroleum, isolation by.... ........................ 9-10

results from.. . ............................................... 10

Distribution of ground water. .................................... 46

Dittmar, W., analyses by.. ...................................... 72

Domestic waters, examples of .................................... 77-78

hardness allowable in ........................................ 74

mineral content allowable in. ................................ 74

objections to hardness in. .. .................................. 74

sources of .................................................... 73-74

Drainage of San Joaquin Valley. ................................. 45-46

Dyes, determination of the source of water by. ................... 98-99

E.

Edge water, influence of, on, the gravity of oils.................... 25,26

use of term............... .................................... 50

Emulsion, formation and treatment of.... ........................ 95-96

Bosin, use of, for coloring water .................................. 98

Etchegoin formation, water sands in..... . ........................ 50

Ethane, content of, in natural gas.. .............................. 32-35

significance of, in waters ..................................... 59

Evaporation, effect of, On the gravity of oils ...................... 25

Findlay, Ohio, petroleuta from, analysis of ...................... 13

Fissures, influence of, oi the gravity of oils. ...................... 25

Flash point of petroleum, determination of ....................... 15-16

Fluorescein, use of, for coloring water. ............................ 98

Foaming in boiler wateite, cause and estimation of... ...:... ...... 75

increase of, by soda used to remove hardness ................. 77

Folds, influence of, on the gravity of oils.. ........................ 25

Fractionation of petroleum, method of ........................... 16

results of..............**..*........... ................... 18,20,21

Fractures. See Fissures. ,M - G.

Gas, natural, action of, on cement.............!............ ...... 79

natural, analyses of..:.. ...................................... 33-35

character of, in relation to its geologic'occurrence ......... 36

commercial value of, constituents affording. ...:.......... 33

composition of. ^.. ....................................... 32-33

cooling of oil by expansion of. ............................ 42-43

heating value ofl... ...................................... 33-35

quantities of, made by oil wells.. ......................... 42-43

101
102 INDEX.

Gasoline, extraction of, from natural gas.......................... 33

production of, by cracking................................... 15

yield of, from California petroleum........................... 14-15

See also Motor fuel. 

General Petroleum Co.'s Carnegie -well, water of, analysis of...... 88

water of, character of.......................................... 78

Geothennic gradients, variation of...................... j... 36-37,41-42

Grain of rocks, influence of, on gravity of oils...................... 25

Gravity of petroleum, properties indicated by.................... 22

relation of sulphur to......................................... 31

variation of, with depth...................................... 23-25

Green, F. T., analysis by........................................ 63

H.

Hardness of water, cause and removal of....................... 74,76-77

Head of water, conditions governing............................. 48-49

Heat, action of, on cement....................................... 79

Hexane, presence of, in California petroleum...................... 12

Hydrocarbons, distribution and significance of, in water......... 59-60

modification of water by..................................... 26-29

series formulas of............................................. 9

Hydrochmolines, occurrence of, in California petroleum........... 14

Hydrogen sulphide, oxidation of................................. 28-29

oxidation of, heat produced by............................... 44

presence and genesis of,in oil-field waters................... 27,28

I.

Iodine, distribution and significance of, in waters................. 58

Iron, occurrence of, in waters..................................... 58

K.

Kern County Land Co.'s spring, water of, analysis of.............. 81

water of, character of......................................... 78

Kharitsehoff, K.V.,cited........................................ 60

experiments by, on the reduction of sulphates by hydrocarbons................................................. 28

on reduction of sulphates..................................... 68

L. 

Lamp oils, use of term........................................... 22

Lithium, occurrence of,in waters................................ 58

use of, for detecting the source of water....................... 98

Lubricants, use of term.......................................... 22

M.

Mabery, C. F., study of California petroleum by.................. 11-12

Magnesium, ratio of, to calcium in oil-field brines................. 68

Maricopa Flat, gravity of oils on............................. ^.... 24

Marlcopa shale, water sands in................................... 50-52

Mays Consolidated Oil Co.'s well 6, water of, analysis of.......... 63

waterof,eharacterof......................................... 78

Metamorphism, relation of petroleum to.......................... 15

Methane, content of, in natural gas............................... 32-35

inertness of................................................... 28

significance of, in waters...................................... 59

Microorganisms, reduction of sulphate by........................ 27-28

Migration of petroleum, change of properties during.........'..... 31-32

Mineral substances dissolved in water............................ 52

Mixed waters, analyses of........................................ 87-91

relations of................................................... 68-70

Modified waters, analyses of...................................... 83

characteristics and examples of............................... 62

Motor fuel, use of term........................................... 22

Movements, orogenic, temperature raised by..................... 43-44

N.

Naphthenes, presence of, m California petroleum................. 10,12

Napthenic acids, distribution and significance of................. 59-60

influence of, on the formation of emulsions................... 96

source and importance of..................................... 14

Nitrate, occurrence of, In waters.................................. 58

Nitrogen, content of, in California petroleum..................... 13,14

content of, in natural gas.................................. 32,33-35

origin of petroleum indicated by............................. 15

Normal waters, characteristics and examples of................... 61-62

Northern Oil Co.'s water well, water of, analysis of............... 91

water of, character of ......................................... 78

O. 

Oil sands, Invasion of, by water.................................. 45

Outcrop, changes In reaching values of waters with distance from. 66-67,

68-70,71-73 

decrease in gravity of petroleum with distance from.......... 23-25

Oxidation, heat produced by..................................... 44

Oxygen, action of, on petroleum.................................. 29-31

content of, In sea and In meteoric waters..................... 32

P. 

Palmer, Chase, analyses by................................... 6F, 65,88

classification of waters by.................................... 54-55

Paraffins, absent from California petroleum...................... 10,12

Paso Robles formation, water sands in........................... 60

Peckham, S. F., study of California oil by........................ 10-11

Perdew, W.E.,analysesby...................................... 34,35

Petroleum, California, action of, an cement....................... 79

California, chemical and physical properties of................ 9-32

constitution of, publications on........................... 11

distribution and significance of, In water................. 59-60

hydrocarbons in.......................................... 10,12

studies of................................................ 10-15

origin of.................................................. 31

relationship of............................................ 15

Phosphate, occurrence of, in waters.............................. 58

Physical conditions, influence of, on the properties of petroleum.. 23-25 

Polymerization, heat produced by............................... 44

Potassium, ratio of, to sodium In oil-field brines.................. 68

Pressure, lowering of, in oil sand................................. 92-93

See also Head of water. 

Propane, occurrence of, In natural gas............................ 33

Properties of petroleum.......................................... 9-32

relation of, to geologic occurrence............................. 23-31

Publications on the constitution of California petroleum, list of... 11 

Pyramid Oil Co.'s water well, water from, analysis of............ 63'

water from, character of...................................... 78

Pyridin, occurrence of, In California petroleum................... 14

R.

Radioactivity, possible heating by............................... 44

Rain water, replacement of brine by............................. 67

underground circulation of..... ——.......................... 46

Reacting values, calculation of................................... 54

modification of, In brines by admixture of rain water......... 70-73

use of, in stating analyses..................................... 53-54

Refining of California petroleum, difficulties of................... 14-15

Refining test of petroleum, method of............................ 16

S. 

Salinity, primary and secondary, definition at. ................... 55

Sampling of petroleum, method of................................ 15

Sampling of water, care required in............................... 52-53

Sands, dry, water under low head In............................. 47-48

water, movement of water in................................. 46-47

San Joaquin Valley, drainage of.................................. 45-46

Scale, formation of, formulas for estimating....................... 75

substances forming........................................... 74-75

Shale, separation of light and heavy oils by....................... 25

Shallow-well waters, analyses of.................................. 81,82

Shut-ofls for water, location of, at different horizons in different

wells................................................. 93

Silicon, occurrence of,in waters.................................. 68

Slichter method of tracing the flow of water, practicability of..... 98

Smith, Emery & Co., analyses by.............. 63,81,82,84,85,88 89,90

Sodium, ratio of, to potassium in oil-field brines.................. 68

Solids dissolved in waters, range of quantities of.................. 59

Specific gravity of petroleum.determuiatioii of................... 15

SiMndletop,Tex., petroleum from, analysis of.................... 13

Spring waters, analysis of......................................... 81

Stabler, Herman, formulas of, for estimating injurious qualities of

boiler water.......................................... 75,76

formulas of, for estimating materials needed to soften water.. 76 

Starke, Dr. E. A., acknowledgment to........................... 7

Stratton Water Co.'s well, water of, analysis of.................. 83

water of, character of.......................................... 78

Straus& Co., analysis by......................................... »l

Structural conditions, influence of, on the properties of petroleum. 23-25 

Sulphate, content of, in sea and in meteoric waters............... 32

decrease of, in waters associated with petroleum.............. 26-28
INDEX. 103

Sulphate, distribution and significance of, in waters.............. 57

injury of oil by............................................... 94

occurrence of, in waters of San Joaquin Valley, Calif......... 66

reduction of, by action of oil.................................. 64-66

heat produced by........................................ 44

replacement of, by carbonate................................. 67-68

by carbonate, changes in reacting values from............ 70-73

Sulphide, distribution and significance of, in waters.............. 58

injury of oil by............................................... 94

Sulphur, action of, on petroleum................................. 29

content of, in California petroleum........................... 13,14

deposition of, from oil-field waters............................ 28-29

determination of, in petroleum............................... 16

relation of, to gravity of petroleum........................... 31

Summerland petroleum, hydrocarbons in........................ 12

Surface waters, analyses of....................................... 81

T.

Tar sands, occurrence of.......................................... 24

nature of..................................................... 26

Temperature, increase of, with depth, map showing.............. 40

indications of oil from........................................ 37,42

measurements of............................................. 37-42

factors affecting.......................................... 42-43

in various oil fields and other regions..................... 41-42

raised by chemical reactions.................................. 44

raised by recent earth movements........................... 43-44

Page. 

Temperature, source of waters indicated by...................... 49,99

Terpenes, presence of, in California petroleum.................... 10,12

Tests of petroleum, results of..................................... 16-22

Tests of waters by taste and smell, limited value of............... .100

Top water, invasion of oil sands by............................... 93

use of term................................................... 50

V.'

Van Orstrand, C. E., temperatures in oil well measured by...... 43

Viscosity of petroleum, determination of......................... 16

W.

Water determination of, in petroleum............................ 16

invasion of oil sands by, detection of source of................ 96

effects of................................................. 94-96

manner of................................................ 93-94

mineralized, influence of, on the gravity of oils............ 25,26^31

modification of, by hydrocarbons............................ 26-29

produced by oil wells, measurement of....................... 97

relation of, to oil sands....................................... 50-52

samples of, for analysis, map showing sources of.............. 70

Water cuts, measurement of..................................... ~ 97

Water table, depth to............................................ 50

Wells, abandoned, invasion by water through.................... 94

admitting water to oil sand, detection of.................... 97-100

Western Water Co.'s wells, water of, analysis of.................: 82

water of, character of......................................... 78

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