DEPARTMENT OF THE INTERIOR

FRANKLIN K. LANE, Secretary

UNITED STATES GEOLOGICAL SURVEY

GEORGE OTIS SMITH, Director

Bulletin 653

CHEMICAL RELATIONS OF THE OIL-FIELD WATERS 

IK SAN JOAQUIN VALLEY, CALIFORNIA

PRELIMINARY REPORT

BY 

G. SHERBURNE ROGERS

WASHINGTON

GOVERNMENT PRINTING OFFICE 

1917
ADDITIONAL COPIES

OF THIS PUBLICATION MAT BE PROCURED FROM

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CONTENTS.

Introduction.............................................................. 5

Conclusions and recommendations.....................................'. 5

Acknowledgments.................................................... 6

Need for more analyses............................................... 7

Location of the oil fields................................................... 8

San Joaquin Valley....................................................... 9

Geography and drainage............................................... 9

Geology.............................................................. 9

Underground water.................................................... 11

Occurrence of water in the oil fields........................................ 12

General distribution................................................... 12

Water sands...................................................... 13

Texture...................................................... 13

Freedom of circulation........................................ 14

Dry sands......................................................... 15

Relation to the oil................................................. 16

Physical characteristics..:............................................. 17

Head or pressure.........................................../...... 17

Temperature..................................................... 19

Geologic conditions that influence the composition of water.............. 20

General features.................................................. 20

Origin of salt water in rocks........................................ 20

Relation of geologic structure to distribution of salt water in the oil fields. 23

General association of salt water and petroleum..................... 25

Distribution of water in the oil fields........................................ 26

Coalinga field......................................................... 26

Lost Hills field....................................................... 27

McKittrick field...................................................... 27

Midway-Sunset field................................................... 28

Kern River field..................................................... 29

Analysis of water and interpretation of results............................... 29

Mineral constituents in water........................................... 29

Collection of samples................................................. 30

Chemical analysis..................................................... 31

Determination of constituents..................................... 31

Statement of analysis.............................................. 32

Reacting values......................:.............................r.. 35

Properties of reaction.................................................. 37

Source and statement of analyses in this report.......................... 40

Classification of the oil-field waters......................................... 41

Distribution and significance of the constituents......................... 41

Alkalies (sodium and potassium)................................... 41

Alkaline earths (calcium and magnesium).......................... " 42

Sulphate.......................................................... 43

Chloride.......................................................... 44

Carbonate and bicarbonate......................................... 44

Sulphide......................................................... 45

Iron and aluminum................................................ 46

Silica.................... ^........................................ 47

3
4 CONTENTS.

Classification of the oil-field waters Continued.

Distribution and significance of the constituents Continued. page.

Other'constituents................... ............................ 47

Total mineral solids. ................^............................. 47

Organic and volatile matter....................................... 47

Criteria for comparison..................... .*.......................... 48

Proposed classification...........:........................'............. 49

Composition of the oil-field waters............................... '. ......... 53

Description of the types............................................... 53

General comparison................................................ 53

Surface water..................................................... 55

Normal ground water.............................................. 58

Shallow water wells........................................... 58

Oil wells (top water)........................................... 58

Modified ground, water............................................. 64

Altered ground water............................................. 67

Reversed type.........................:..................... 67

Brine...............:........................................ 71

Mixed type.................................................. 75

Relations of the types................................................. 77

Vertical relations. .................................................. 78

Area! relations................................................... 86

Variation in chloride.......................................... 86

Relations of the mixed type................................... 88

Chemical relations between water and the hydrocarbons...................... 93

Alteration of waters by the hydrocarbons............................... 93

Nature of alterations...'............................................ 93

Reduction of sulphate..................... v ...................... 93

Formation of carbonate............................................ 98

Production of gases................................................ 100

Alteration of hydrocarbons by water................................... 102

Solubility of petroleum constituents in water........................... 105

Value of water analyses to the oil operator.................................. 109

Summary of conclusions.................................................. 113

Index................................................................... 117

ILLUSTRATIONS.

Page.

FIGURE 1. Diagram showing circulation.or stagnation of the water in open and 

closed sand lenses before and after the lenses are penetrated by 

wells......................................................... 14

2. Graphic representation of analysis 31, showing method of deducing

the properties of a water from its composition................... 39

3. Diagram illustrating relation of oil-field waters of the meteoric and

connate types, and their alteration as the oil zone is approached.. 51

4. Chart showing chemical relations of the oil-field waters............ 54

5. Variation in chemical character of waters from different depths,

showing alterations by hydrocarbons...................'........ 79

6. Diagram showing increase in salinity of waters in the northern part

of the Midway field with distance from the outcrop............. 88

7. Diagram showing gradation between waters of the mixed type in the 

western part of the Midway-Sunset field and the brines that occur 

at the same general horizon in the deeper territory to the east... 91
CHEMICAL RELATIONS OF THE OIL-FIELD WATERS IN 

SAN JOAQUIN VALLEY, CALIFORNIA.

PRELIMINARY REPORT.

By G. SHEKBURNE ROGERS.

INTRODUCTION.

CONCLUSIONS AND RECOMMENDATIONS.

During the rapid rise of the petroleum industry in the last 50 years 

the geologic occurrence of petroleum has received a great amount of 

study, and the interesting problems involved in its origin and migration have engaged the attention of many geologists. It has long 

been known that oil and gas are commonly associated with water, 

and the great importance of the water as a physical agent in the migration of the oil has been recognized in all geologic theories of the 

accumulation of oil. Of the chemical relations between the water 

and the oil, however, we know little, and scientific literature contains only a few references even to the chemical character of the 

waters themselves. Apparently many of the current ideas on this 

subject either are erroneous or can be accepted only with important 

modifications.

In the oil fields of San Joaquin Valley, Cal., the oil and water are 

found in practically unconsolidated rocks. At most localities several 

water-bearing sands are intercalated in the shales above the oil 

measures, and there is also a water sand a short distance beneath 

them. In some places a water sand occurs in the shale that separates the oil sands, and less commonly oil and water have been found 

in the same stratum. In sinking a well through this complex it is 

difficult to prevent the water, which in places is under high head, 

from entering the oil sand, in which event it may clrive the oil some 

distance back and so ruin a considerable tract of land. The writer 

studied the physical and chemical relations of the water and oil in 

these fields during the summers of 1914 and 1915* The chief conclusions concerning the chemistry of the waters, deduced by him 

from a study of several hundred analyses of water from different 

depths, are as follows:

5
6 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

1. Oil-field water is not necessarily salty, as is generally believed, 

and may not be even slightly salty to the taste. The degree of concentration of chloride in such water is governed primarily by local conditions and is not affected by the position of the water in relation to oil.

2. Sulphate, which predominates in most of the shallow ground 

waters on the west side of San Joaquin Valley, diminishes in amount 

as the oil zone is approached and finally disappears.

3. The concentration of carbonate increases as the oil zone is 

approached but depends largely on the concentration of chloride.

4. The horizon, with respect to the oil zone, at which these alterations take place, is different in each field.

On the basis of these conclusions, which appear to be well grounded, 

at least for the area studied, the following practical suggestions may 

be made:

In drilling a well in untested territory it may be possible to obtain 

an indication of the presence or absence of oil and gas below by ascer- 

' taining by analysis whether the sulphate is diminishing and the carbonate increasing in the waters successively encountered. In some 

areas a significant change may be detected as much as 1,000 feet 

above the oil; in others the upper limit of alteration may be within 

a few hundred feet of the oil.

The source of the water in a well that produces a mixture of water 

and oil may be determined, at least in a general way, by studying 

its chemical composition. In the Westside Coalinga field, for example, the source of the water may thus be determined rather definitely; 

in the Midway-Sunset field, where the distinctions are less sharp, the 

success of this method will depend largely on the number of authentic 

analyses that are available for comparison.

In this report the writer aims first to present the evidence on which 

the foregoing conclusions are based and to discuss the interpretation 

of water analyses and their value from the operator's standpoint, and 

second, to discuss the chemical relations of water and oil in so far 

as present information permits. It is hoped that this preliminary 

presentation will indicate the importance of experimental geochemical 

work on the interaction of the organic constituents of oils and the 

inorganic, substances found in the oil-field waters. Enough is known 

already to warrant the belief that systematic experimental work in 

petroleum hydrology will yield results of practical as well as scientific 

value.

ACKNOWLEDGMENTS.

The writer wishes to express his appreciation of the assistance and 

cooperation rendered by Mr. R. W. Pack, with whom he was associated in a study of the Midway and Sunset fields for the United 

States Geological Survey during the summer of 1914. Dr. Chase 

Palmer and Mr. Herman Stabler, also of the Survey, as authors of
INTRODUCTION. 7

the system of interpretation of water analyses adopted in this report, 

have been freely consulted, and Dr. Palmer in particular has been a 

constant source of help in the study of the chemical relations of water 

and oil. The writer is indebted also to Mr. R. B. Dole for generous 

consultation on some of the problems touching the chemistry of 

natural waters. Dr. Chase Palmer and Mr. S. C. Dinsmore made 

many of the water analyses included in the report.

Special mention should be made of the unpublished work of Mr. E. 

A. Starke, of the Standard Oil Co., on the chemistry of the waters of 

the California oil fields. Mr. Starke has collected and studied a large 

number of water analyses and reached several years ago many of the 

conclusions that the writer has recently arrived at independently. 

Mr. Starke noted the absence of sulphate in waters associated with 

oil and ascribed it to chemical reaction between the two, and so has

guided his prospecting to a considerable extent by studying the composition of the waters encountered in prospect wells. The special 

thanks of the writer are due Mr. Starke for his free discussion of the 

subject and for the use of some of the analyses included in this report. 

The success of any study of underground conditions in an oil field 

depends on the good will and courtesy of the operators, and the 

writer desires gratefully to acknowledge the support and cooperation 

of all the companies visited. A complete list of those who have 

cheerfully and generously furnished information would include 

practically all the operators in the Coalinga, Midway, and Sunset 

fields, many of whom spent considerable time in assisting in the collection of samples of water for analysis. The following gentlemen 

rendered the writer especially valuable aid: Messrs. B. H. van der 

Linden, M. E. Lombardi, E. G. Gaylord, Paul Paine, M. J. Kirwan, 

W. W. Orciitt, M. L. Requa, T. A. O'Donnell, E. 0. Faulkner, W. M. 

Wallace, J. E. Elliot, W. A. Ambrose, F. B. Tough, J. J. Hern, R. D. 

Bush, T. J. Crumpton, W. A. Greer, W. E. Brown, and J. H. Dearin.

NEED FOB. MORE ANALYSES.

In the course of this investigation more than 50 samples of water have 

been specially analyzed and about 250 analyses, most of them made 

for industrial purposes, have been furnished by the oil companies. 

These have been sufficient, it is believed, to form a fair basis for the 

principles set forth in this paper, but they are inadequate to give 

more than a general idea as to the character of the waters in any particular locality. In the Westside Coalinga field all the evidence leads 

to the conclusion that conditions are fairly constant, and that even 

with the data at hand it is possible to determine the general horizon 

of a water from its analysis. In the Midway-Sunset field, however, 

the zone of water altered by the oil may in some localities extend 600 

feet above the oil measures, and it is at present impossible to deter-
8 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

mine whether or not this zone of altered water may be satisfactorily 

subdivided. Even if this differentiation could not be made analyses 

will be of great value in locally correlating the various waters, as, for 

example, in determining whether or not the water produced by two 

neighboring wells is the same.

It is generally recognized to-day that the problem of preventing 

water from invading the oil sands is one of the gravest problems confronting the oil industry in California. By following the methods suggested in this report a clue can probably be obtained to the source of 

the water that floods a well, a knowledge of which is essential to its 

proper exclusion. These methods are being successfully used by the 

Standard Oil Co. and should prove equally valuable to other 

operators.

It may be oorne in mind, however, that the work of gathering the 

data must fall on the operators themselves, for it is impossible for 

anyone not constantly on the ground to collect an adequate set of 

samples. An analysis is of little value as a standard for comparison 

unless the position of the water is known, and properly located samples can usually be taken only while the well is being drilled or 

repaired. The samples need not necessarily be analyzed immediately 

but may be sealed and stored away until their analysis becomes 

desirable. Several of the larger companies have begun to realize 

the value of analyses and are taking samples wherever good ones can 

be obtained. It is well to bear in mind that the trouble and cost of 

collecting a sample and having it analyzed are negligible in comparison with the value that the information thus made available may 

later acquire.

LOCATION OF THE OIL FIELDS.

The oil fields of San Joaquin Valley are in Fresno and Kern counties. The most important fields are on the west side of the valley, 

along the flanks of the Coast Ranges, and extend, with intervening 

unproductive areas, for a distance of 110 miles. The Coalinga field, 

in Fresno County, is the northernmost of the developed fields, and the 

Midway-Sunset field, in Kern County, is the southernmost. The 

Lost Hills and Devils Den districts are roughly halfway between the 

two, and the Belridge' and McKittrick fields are between the Devils 

Den and the Midway. The only field on the east side of San Joaquin 

Valley is the Kern River field, which is on the lowest foothills of the 

Sierra Nevada near Bakersfield, about 30 miles northeast of the 

Midway-Sunset field. By far the most important of these fields, 

named hi order of age of exploitation, are the Kern River, Coalinga, 

and Midway-Sunset fields. At present, however, the Midway-Sunset 

field is the largest in the State in annual production, and it is followed 

by the Coalinga and the Kern River, in the order named.
OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 9

SAN JOAQUIN VALLEY. 

GEOGRAPHY AND DRAINAGE.

San Joaquin Valley, a part of the great .and nearly level-floored 

depression which traverses the central part of California, is bounded 

on the east by the Sierra Nevada and on the west by the Coast Ranges. 

San Joaquin River, which directly drains the northern two-thirds of 

this great valley, discharges through Carquinez Strait into San 

Francisco Bay and thence through the Golden Gate into the Pacific 

Ocean. The southern, more arid third of the valley has no surface, 

outlet under normal conditions, and the surface waters accumulate in 

the Buena Vista reservoir, near the Midway-Sunset field, and in the 

depression occupied by Tulare Lake, southeast .of Coalinga. The 

streams that drain into the valley from the Sierra Nevada carry 

practically 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. On this account the valley floor is unsymmetric, the 

axis or line of lowest depression lying nearer the western than the 

eastern foothills.

A considerable portion of the drainage from the mountains sinks 

into the sand and silt of the valley floor and joins the underground 

circulation. As all the drainage from the valley must pass through 

the narrow outlet at Carquinez Strait the underground circulation 

is probably extremely slow. Mendenhall has aptly referred to the 

great central depression of California, of which San Joaquin Valley is 

the southern part, as "canoe-shaped, with only a notch in the rim at 

the straits through which the waters spill." l

GEOLOGY.2

It is not the purpose of this report to describe in any detail the 

geology of San Joaquin Valley or of its oil fields, but a brief outline is 

necessary to a proper understanding of the conditions governing the 

chemical character and the flow of the underground water.

Although San Joaquin Valley is essentially a great structural 

trough filled with valley wash, the .geologic conditions on its east and 

west sides present many points of contrast. The east boundary of 

the valley is the Sierra Nevada, which is composed of granites and 

metamorphosed sedimentary and igneous masses of pre-Cretaceous

i Mendenhall, W. C., Preliminary report on the ground waters of San Joaquin Valley, Cal.: U. S. Geol. 

Survey Water-Supply Paper 222, p. 25,1908.

* The geology of the oil fields of San Joaquin Valley is more completely described in the following reports: 

Arnold, Ralph, and Anderspn, Robert, Geology and oil resources of the Coalinga district, Cal.: U. 8. Geol. 

Survey Bull. 398,1910. Arnold, Ralph, and Johnson, H. R., Preliminary report on the McKittrick-Bunset 

oilregion, Kern and San Luis Obispo counties, Cal.: U. S. Geol. Survey Bull. 406,1910. Anderson, Robert, 

Preliminary report on the geology and possible oil resources of the south end of the San Joaquin Valley, 

Cal.: U. S. Geol. Survey Bull. 471, pp. 106-136,1912. Anderson, Robert, and Pack, R. W., Geology and 

oil resources of the west border of the San Joaquin Valley north of Coalinga, Cal.: U. S. Geol. Survey Bull. 

603,1915.
10 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

age. At the foot of the Sierra these rocks are overlain by practically 

unaltered Tertiary sediments, which dip gently to the west and disappear beneath the sand and gravel of the valley proper. These 

Tertiary formations^ are not everywhere present, but are well developed in the neighborhood of the Kern River .field. The lower of 

the Tertiary formations is made up in part of diatomaceous shale, 

which is probably the source of the oil; the upper division consists 

of coarse sand, gravel, and clay, into which the oil has probably 

migrated, and in which it is now obtained.

The oldest rocks on the west side of the valley are probably of 

Jurassic age and comprise, a series of altered igneous and sedimentary 

rocks. This formation forms the backbone of the Diablo Range 

north of Coalinga and probably extends beneath the surface for 

some distance to the south. It is overlain on the valley side by a thick 

series of Cretaceous shale and sandstone, from the upper part of which

011 in commercial quantities is produced in the Oil City district of 

the Coalinga field. The Cretaceous is overlain by rocks of Eocene 

and Oligocene (?) (earlier Tertiary) age, above which is a mass of 

sandstone and diatomaceous shale belonging to the middle Tertiary. 

Shale, sandstone, and conglomerate of later Tertiary age (upper 

Miocene and Pliocene) overlie these formations, in most places unconformably, and these are in turn overlain by similar Quaternary 

sediments. The later Tertiary deposits, which are practically un- 

* consolidated, were probably laid down under alternating marine, 

brackish, and fresh-water conditions; the series as a whole is characterized by many minor unconformities and by the lenticularity of 

its individual beds.

In the Coalinga district the oil is believed to have formed hi the 

Oligocene' (?) shale and to have migrated up into overlying beds, 

which are partly middle Tertiary and partly younger. In the 

Temblor Range fields to the south most of the oil probably originated 

in the thick beds of diatomaceous shale of middle Tertiary age; 

it is now found in the irregularly stratified rocks of the later Tertiary. As the lower part of these lenticular masses constitutes the 

main oil measures everywhere except in part of the Coalinga field, 

the correlation of individual oil and water sands by a study of the 

well logs is very difficult.

This whole sedimentary series, resting in what may be considered 

broadly as a great eroded anticline, constitutes the Diablo and 

Temblor ranges. The older rocks, closely folded, form the mam 

mountain mass; the younger rocks, more gently folded but dipping 

in general away from the axis, form the lower flanks and foothills. 

The oil-bearing strata outcrop well down at the foot of the range, 

where the prevailing dips are toward the north or northeast at a 

comparatively low angle. In many places, however, these strata
SAN JOAQUIN VALLEY. 11

are affected by one or more minor flexures which run obliquely out 

from the main ranges, and it has been pointed out by Anderson and 

Pack* that all of the oil fields on the west side are associated with 

folds of this kind. In other words, all of these fields lie either on 

such an anticline or in the syncline back of it, or extend over both 

anticline and syncline. The Midway-Sunset field extends over 

several minor folds. .The-reason for the accumulation of oil only 

under these structural conditions need not be considered here, but 

it is important to note that all of the fields on the west side are 

characterized by this type of structure, for it undoubtedly influences 

the circulation of the oil-field waters.

UNDERGROUND WATER.2

A large proportion of the surface water entering San Joaquin 

Valley sinks below the surface and joins the underground 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 generally fine, and the outlet at Carquinez 

Straits is narrow. As a result of these conditions the ground water 

is under artesian head in a wide belt along the center of the valley. 

Near the north end of the valley the waters are practically ponded 

and the deeper waters are highly mineralized, and even in the southern 

part the main valley circulation probably is abnormally sluggish.

Owing to the sharp contrast in meteorologic and geologic conditions 

between the east and west sides of the valley the ground waters 

present some interesting chemical variations. As the Sierra is a 

region of moderate rainfall, and as the Temblor and Diablo ranges 

are semiarid, practically all the surface water entering the valley 

is brought down by streams on the east side. As this water is the 

drainage of a region underlain by granites and other relatively insoluble silicate rocks, it is low in mineral content and carries chiefly 

carbonates. The west side of the valley, on the other hand, is a 

region of very scanty rainfall, nearly all of which sinks beneath the 

surface before reaching the valley proper and circulates through a 

great series of 'sedimentary formations. These strata contain a 

large amount of disseminated gypsum and other sulphates, which

i Anderson, Robert, and Pack, K, W., Geology and oil resources of the west border of the San Joaquin 

Valley north of Coalinga, Cal.: U. 8. Oeol. Survey Bull. 603, pp. 116-121,1916.

* For a complete account of the underground waters of San Joaquln Valley, see Mendenhall, W. C., 

Dole, B. B., and Stabler, Herman, around water in San Joaquin Valley, Cal.: U. 8. Geol. Survey WaterSupply Paper 398,1916.
12 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

are readily dissolved by the waters leaching through them. The 

waters of the west side are therefore high in mineral matter and 

predominantly sulphate in character. Dole 1 has shown that an 

intermediate or axial zone may be distinguished near the center of 

the valley, where the waters are characterized principally by their 

high content of alkalies (sodium and potassium).

The character of ground waters in San Joaquin Valley is, therefore, 

controlled primarily by geologic conditions, and it will be shown that 

in the oil fields local chemical influences have led to the development 

of still other types of water. Broadly speaking, the ground water of 

the valley enters it chiefly from the east side and flows slowly and 

against considerable resistance toward the north. It has been 

suggested that because of these conditions the meteoric water entering from the Sierra side has produced sufficient hydrostatic head to 

force the oil to the west side of the valley and to trap it under the 

peculiar structural features locally existing there. In other words, a 

flow or pressure across the valley rather than in a longitudinal direction is postulated. That underground waters have had much to do 

with the accumulation of the oil can not be doubted, and some 

support is lent this view by the fact that the water certainly encounters 

considerable resistance hi its normal northerly course. The possibility of lateral pressure must be borne in mind in considering the 

accumulation of the oil, but it may be pointed out that the chemistry 

of the oil-field waters offers little support to this view; that if the 

theory is correct the anomalous position of the Kern Kiver field on 

the east side of the valley must be explained; and that a theory 

involving the transmission of hydrostatic head through 20 to 40 

miles of lenticular materials, and with only a slight initial difference 

in head, involves grave difficulties.

OCCURRENCE OF WATER IN THE OIL FIELDS. 

GENERAL DISTRIBUTION.

In considering the ground-water system of the valley as a whole 

it has been tacitly assumed that the water exists as a continuous 

body'saturating all the rocks to an indefinite depth. This conception 

is well founded and is valuable in a broad study, although the fact 

that the circulation of the water is confined largely to certain strata 

is of course of great practical importance. The question in which 

layers the water will circulate depends on a variety of factors, most 

of which are well understood. There is no intrinsic difference 

between a water sand and any other sand.

 i Mendenhall, W. G., Dole, B. B., and Stabler, Herman, op, clt., p. 117.
OCCURRENCE OF WATER IN OIL FIELDS. 13 

WATER SANDS.

Texture. Water flows most readily through rocks of uniformly 

coarse grain, and hence tends to circulate chiefly hi the sandy layers.1 

The amount and pressure of the water hi a sand depends largely on 

local conditions, but if these were uniform water would normally be 

found hi greater available quantity and under higher head hi coarse 

sand than in tight sand or sandy shale. In other words, the character 

of the rock has much to do with its content of available water, 

which in a thick sandy stratum is usually concentrated hi one or 

more "pay streaks" just as oil is concentrated in>certain parts of an 

oil sand.

The rapidity of circulation of the water through a stratum is not, 

however, an index of the amount of water that the rock contains. 

Coarse open sand, through which flow is most rapid, has an average 

pore space or absorptive .capacity of 32 to 37 per cent; unsorted or 

tighter sand, of 38 to 42 per cent; and clay, of 44 to 47 per cent.2 

The important consideration for practical purposes is, however, that 

the sand yields its water readily because more fluid can easily take 

its place, whereas movement is slower in the clay and much of the 

water is probably held by capillary attraction. A sandy shale or a 

tight sand may also contain considerable water which will not be 

apparent hi drilling because it escapes too slowly from the bed. If 

all the strata penetrated by an ordinary oil well could be carefully 

examined, those below the ground-water level probably would be 

found to contain more or less water, although the water content of 

certain strata might be far less than the absorptive capacity of the 

rock. Most of the beds, however, are too fine grained to permit 

perceptible movement of the water hi them, and consequently most 

of the drainage passes through a few layers.

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 grams are sharper or more angular, or that 

they are smaller, or that water sand contains grams 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 governing the movement of water 

and oil.

1 Slichter, C. S., The motions of underground waters: U. S. Geol. Survey Water-Supply Paper 67,1902; 

Field measurements of the rate of movement of underground water: U. S. Geol. Survey Water-Supply 

Paper 140,1905.

2 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.
14 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

Freedom of circulation. Although the grain of the rocks is an 

important factor in determining which beds the drainage follows, as 

the term "water sand" implies, an equally great factor in lenticular 

material is the freedom of inlet and outlet of the lens itself. It is 

evident that water will not circulate hi a bed unless that entering at 

the outcrop can escape at the lower end of the lens, either into another 

lens or through some practicable channel. (See fig. 1.) If the upper 

end is open and the lower end sealed water will accumulate only up 

to the absorptive capacity of the sand, and if the hydrostatic head of

Water-bearing sand

FIGURE 1. Diagram showing circulation or stagnation of the water in open and closed sand lenses 

before and after the lenses are penetrated by wells.

the water thus trapped is not great enough to force an outlet movement will cease until the pocket is opened by the drill. The structure 

of the rocks may exercise an entirely similar effect in preventing 

circulation, so that water may be trapped in a syncline or a basin. 

If a lens is effectually sealed on all sides there can be no movement 

even when it is penetrated in drilling unless the rock pores are partly 

filled with air or gas under pressure, under which circumstances the 

expansion of the gases may displace some of the water. It is probable 

that most of the so-called water sands in the valley fields fall in one 

of these three classes, which are shown diagrammatically in figure 1.
OCCURRENCE OF WATER IN OIL FIELDS. 15 

DRY SANDS.

In most well logs an attempt is made to differentiate water sands 

and "dry" sands, the "dry" sands being typically those which 

absorb water instead of yielding it. Under ordinary conditions of 

drilling it is generally necessary to maintain a certain depth of water 

in the drill hole, ranging from a few hundred feet when drilling 

shallow wells by the standard method to the total depth of the hole 

when the rotary method is used. The driller's characterization of a 

stratum as water sand or dry sand must then depend largely on the 

fluctuation of the water level in the hole. If the water in the sand 

is under high artesian head the water will rise in the drill hole and 

may flow at the surface (fig. 1, C). However, a column of drilling 

water a thousand feet high exerts a pressure of 434 pounds per square 

inch at the bottom of the hole, and this pressure must be counterbalanced by the hydrostatic pressure in the sand before the water 

level in the drill hole will rise. If the hydrostatic pressure is equal 

to the weight of the column of drilling water no change in level will 

occur, but if the pressure is lower the water level will sink and most 

of the drilling water may be absorbed. Thus sands which rapidly 

absorb most of the drilling water might instead yield a short column 

of water if the drill hole were dry, and if they were pumped might 

prove steady producers. Many such sands have doubtless been 

reported to be dry. This distinction is by no means an academic 

one. Water under low hydrostatic head may be unimportant in the 

early history of an oil field, but at alater period, after the gas pressure 

has diminished and a considerable portion of the oil has been removed, 

the oil sands constitute a convenient reservoir, and such water on 

entering them is capable of doing considerable damage.

The factors causing artesian flows are well known and need not be 

discussed here, but some of the causes of unusually low hydrostatic 

head, leading to the conditions described above, may be mentioned. 

If the sand is a sealed lens completely filled with water it can neither 

receive nor yield water when it is penetrated by the drill. If, on the 

other hand, it is open at both ends so that there is free circulation 

the head may be either moderate or low, depending chiefly on the 

inclination or dip of the bed and the amount of resistance encountered by the water in its passage between the sand grams (fig. 1, B). 

If the resistance is extremely low the head will be very low, for the 

water will follow the path of least resistance. In many wells of this 

kind the head is probably less than that of the water in the drill hole, 

and as circulation is comparatively free, part of this water will be 

absorbed.

However, in some drill holes, in which the drilling water has disappeared into a sand with great rapidity, the conditions just described
16 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, GAL.

do not offer adequate explanation. For these drill holes, figure 1, D, 

which shows a water-filled sand lens with free outlet at the lower end 

but sealed at the upper, is suggestive. Under these conditions a 

negative head or partial vacuum would be created, and if such a 

sand were penetrated by the drill the drilling water might be taken 

up as fast as it could be poured into the well. These conditions do 

not depend on the complete sealing of the upper end of the lens, for 

the same principle would operate to a lesser degree providing only 

that the outlet is larger and accommodates more water than the 

intake. As the freedom of circulation normally decreases with 

depth, the outlet might have to be considerably greater than the 

intake, but this relation is probably no less common than the reverse, 

by which a .high positive head would be developed.

It may be mentioned in passing that many geologists believe that 

meteoric and connate waters are confined to a relatively shallow zone 

near the earth's surface, below which the rocks are normally dry. 

The literature of ore deposits contains many references to this belief 1 

and strong evidence in favor of it is also found in the Appalachian 

oil fields. In the fields of San Joaquin Valley, however, large amounts 

of water have been found at the greatest depths reached, more than 

4,000 feet, in the fields of the west side, and 5,000 feet in the Kern 

River field.

RELATION TO THE OIL.

The lenticular rocks overlying .the oil in the San Joaquin Valley 

fields include a number of well-recognized water sands. These sands 

may be traced within small areas, though wide correlations are impossible. Numerous factors influence the distribution of the water and 

the course of its circulation and therefore where irregular and lenticular rocks are concerned it is impossible to predict in advance of 

drilling where the greatest flows will be found.

The ground-water level, or the plane below which most of the strata 

are saturated, varies from place to place but is generally within 300 

feet of the surface. Between this level and the horizon of the oil 

from one to a dozen or more water sands are found, the number 

depending on the locality and on the depth of the oil. In some localities no flows are encountered in the 300 feet or more of strata directly 

above the oil, but in others there is a water sand less than 50 feet 

above it. Sands yielding large quantities of water are generally 

encountered below the oil, the distance depending somewhat on the 

thickness and character of the oil zone itself. Where the oil is confined to sands in one zone 300 feet or more thick, there is generally a 

water sand between 10 and 100 feet below the base of the oil zone.

1 One of the earliest papers is that of Kemp, J. F., The r61e of the igneous rocks in the formation of 

veins: Am. Inst. Min. Eng. Trans., vol. 31, pp. 109-198,1902.
OCCURRENCE OF WATER IN OIL FIELDS. 17

Where the oil occurs in several more widely separated sands water is 

usually encountered between them.

In addition to the sands that are wholly filled with either oil or 

water there are sands that contain both, the oil occupying the upslope and the water the down-slope portion. The topmost sand in 

the oil zone in the Westside Coalinga field, for example, contains 

water down the dip, and analogous conditions exist in several localities in the Midway and Sunset fields. It is generally recognized 

that if any persistent oil sand in any of the fields could be followed 

far enough down the dip the oil would finally be found to be replaced by water.

The terms locally applied to waters in the three positions described 

are respectively "top water," "bottom water," and "edge water." 

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, and 

edge water may be either top water or bottom water or both. These 

terms are perhaps too commonly used -and too convenient to discard, 

but the term top water should be restricted to water above the highest 

oil sand, and the other terms should be used only when their meaning 

is perfectly clear. The terminology suggested by the writer (see p. 51), 

which is also based ultimately on the position of the water in relation 

to the oil, is believed to offer a basis for more rational distinctions.

PHYSICAL CHARACTERISTICS. 

HEAD OK PRESSURE.

In several fields of the San Joaquin Valley the water in many sands 

is under great pressure, and it has been necessary to devise special 

methods of shutting off this water in order to prevent its entering the oil sands. In the McKittrick field, for example, several 

wells near McKittrick encountered water which is said to have 

flowed for a while over the derrick, and in the Midway-Sunset field 

many flowing waters have been struck at different depths, the 

greatest more than 3,500 feet. As a general rule, to which there 

are many exceptions, the pressure increases with the depth, and the 

waters below the oil zone are generally confined under considerable 

pressure. The head in most of the sands reported as water sands by 

drillers is more than 200 feet, and it has already been pointed out that 

many sands reported as dry probably carry water under a head of 

more than 50 feet.

The pressure of the water in most sands, however, is not constant, 

but diminishes noticeably a short time after the sand is tapped. 

'Waters that flow for months or years finally cease to flow, and the 

60439° Bull. 653 17 2
18 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

head of waters that rise but do not reach the surf ace is also known to 

decrease. The rate of decrease in any given sand depends on local 

factors and may differ widely among neighboring wells, but the general decrease in any area as a whole is striking.

In water wells outside of oil fields the pressure is generally either 

hydrostatic or artesian hi character, or is due to rock pressure. 

Hydrostatic pressure is caused by the weight of the downward-bearing 

column of water, and its amount at any point is controlled chiefly by 

the difference in elevation of that point and the point at which the 

water enters the bed, and in practice by 'the fineness of the material 

through which the pressure is transmitted. The factors controlling 

hydrostatic head are fairly well understood and may be determined 

with considerable accuracy. Rock pressure is commonly believed 

to be the weight of the overlying column of rock, which exerts a compressive effect on the beds beneath it. During the deposition of the 

sediments this undoubtedly leads to closer packing of the grams, but 

after a state of equilibrium has been reached the effect of further 

compression is a matter of speculation, unless the rocks concerned 

are deeply buried. A factor often overlooked in this connection is 

the tensile strength of the overlying rocks, which may conceivably 

be great enough to relieve a part of the pressure from a given point. 

As the weight.of the strata is thus somewhat irregularly distributed, 

the rock pressure on a body of ground water must be irregular. 

Rock pressure is doubtless an important factor under some conditions, 

but its effect is generally an unknown quantity.

Gas pressure must also be taken into account in regions in which 

gas is contained in the rocks. In general the gas pressure in any 

sand is less than the weight of an overlying column of water, but 

there are- many sands in which it is considerably greater and in 

which, therefore, its influence must be considered. If a sealed sand 

lens is filled partly with water and partly with gas 'under pressure, 

the water may flow out under great apparent head when the sand is 

tapped. (See fig. 1, E.) When the gas has expanded somewhat, the 

apparent head of the water decreases, and some, though not all, of 

the decrease in the head of oil-field waters is doubtless due to diminishing gas pressure. Some puzzling differences in the head of these 

waters may also be ascribed to gas pressure, the effect of which can 

not be overlooked, although its ultimate cause has never been satisfactorily determined.

Aside from 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 are partly liberated at the foot of the well, and act somewhat like-an air lift in 

causing the water to flow. Their action is feeble as compared with
OCCURRENCE OF WATER IN OIL FIELDS. 19

the propulsive effect of a body of compressed gas, but it is doubtless 

more widespread and causes some waters to flow that might not 

otherwise quite reach the surface.

In the oil fields of the west side of the valley much of the water is 

under high initial head or pressure, but in the main Kem River field 

on the east side of the valley the pressure is notably lower. Its present, pressures are not comparable with those in the more recently 

developed fields of the west side, but even in the early period of its 

development fewer flowing waters were found. Most of the important factors influencing head or pressure have probably entered into 

this difference; the geologic structure in the Kern River field is more 

gentle, and the sands are thicker and more persistent, the underground circulation is freer, and the initial gas pressures were considerably lower.

TEMPERATURE.

The temperature of the oil-field waters generally increases with 

depth at about the rate that is normal in most regions, or possibly at 

a slightly higher rate. .The temperature of the shallow waters is generally between 80° and 90° F., and that of the waters near the oil 

sands between 95° and 110° F. The waters from depths of 3,000 to 

4,000 feet in several wells have a temperature of 120° to 130° F., 

though that from similar depths in other wells is cooler. The geothermic gradient is fairly regular, so that the source of the water is indicated in a general way by its temperature, and a sand receiving much 

surface drainage is generally abnormally cool. The temperatures of 

some of the waters discussed in this report are given in the tables of 

analyses on pages 63, 66,70, 73,74,76, and 77. The cooling effect of 

expanding gas, as well as several minor factors, may injure the value 

of temperature measurements made at the mouth of a well, so that 

some variation would be expected, and in addition it seems certain 

that the waters undergo chemical changes, probably exothermic in 

character, which may locally disturb the normal gradient still more.

Measurements of the geothermic gradient have been made in sev-' 

eral localities in North America and Europe, and it is interesting to 

note that Koenigsberger and Miihlberg l after studying and correcting 

these measurements conclude that the gradient is abnormally high 

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 available are deemed 

inadequate and that there are apparent -exceptions. Although the 

average of the gradients measured by Koenigsberger and Miihlberg 

in oil fields is slightly higher than that of gradients in other regions,

1 Koenigsberger, Job., and Miihlberg, Max, On the measurements of the increase of temperature in bore 

boles: Inst. Min. Eng. (England) Trans., vol. 39, pp. 617-644,1910; also tJber Messungen der geothermischen 

'Tiefenstufe: Neues Jahrb., Beilage Band 31, pp. 107-157,1911.
20 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

the wide variation between individual gradients in oil fields suggests 

that more data might reverse their results. Irregular variations, as 

stated above, also characterize the temperatures of the waters in the 

oil fields of the San Joaquin Valley.

GEOLOGIC CONDITIONS THAT INFLUENCE THE COMPOSITION OF

WATER.

GENERAL FEATURES.

Owing to the fact that underground Waters in a region of sedimentary rocks tend to follow the bedding planes, the structure or attitude 

of the rocks has an important 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 in structural troughs or 

basins and held there indefinitely. Whether the water so trapped was 

originally salt or fresh, it is evident that during its long period of 

association with the rocks it will dissolve certain of their constituents 

and become more highly mineralized. The waters of the oil fields 

of the valley differ widely from one another in both their content of 

chloride and their total load of dissolved mineral matter, and it is 

thought that these variations are caused by such physical factors as 

the geologic structure, the lenticularity of the beds, and the amount of 

rainfall. The solution of rock constituents by underground waters 

is a somewhat complicated problem that may best be discussed in 

connection with the chemistry of the waters, but the distribution of 

chloride is so largely a physical problem that it will be considered here.

ORIGIN OF SALT WATER IN ROCKS.

. When sediment is deposited on the floor 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 this water, but that remaining ordinarily fills the 

pore spaces of the rocks after they have assumed their normal bulk. 

Uplift, however, causes circulation of the water to commence, and 

meteoric water falling on 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, only slightly altered by its contact with the rocks, 

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 the water will accu-
OCCURRENCE OF WATER IN OIL FIELDS. 21

miilate in its deepest portion and remain there, somewhat as the 

surface waters of Great Salt Lake are held in their basin. Where 

the outlet is not entirely closed but is merely restricted, other factors 

enter into the problem, 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 such subordinate factors as 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. The deeper 

of two deep wells in the same locality would ordinarily be expected 

to yield a more salty water, owing to the smaller volume of circulation in the deeper rocks as compared with those nearer the surface. 

In a region of lenticular beds irregularities are to be expected, for 

the freedom of circulation differs from bed to bed and some sands 

will therefore retain their salt water much longer than others.

After marine sediments have been elevated to form land and the 

underground circulation thus set up has leached out part or all of the 

connate water the rocks may again subside beneath sea level. In this 

event the fresh water contained in the beds will be partly replaced by 

sea water, and sediments that are laid down over these beds will be 

saturated with sea water. After the second period of elevation has 

occurred and circulation has again been established the process of 

freshening will be repeated. Under these= conditions it is evident 

that the older or deeper formations, having undergone longer continued leaching, may contain less salt water than those nearer the 

surface, where the replacement by fresh water may be incomplete. 

Examples of salt water underlain by fresh water are not uncommon 

on the Atlantic Coastal Plain,1 and it is possible that similar conditions 

exist in several places along the borders of San Joaquin Valley.

In the foregoing paragraphs the burial and retention of sea water 

only has been considered, but it is evident that strata laid down in a 

fresh-water lake may contain entrapped fresh water, which is just as 

truly connate as entrapped salt water. In other words, the term connate water as originally employed 2 means simply water occluded in 

the sediments when they were deposited and is not restricted to any 

particular chemical type of water. On the other hand, if used in 

this strict sense, the term should be restricted to water laid down 

with the formation in which it is now found; it therefore should not 

be applied to water that has migrated from one formation to another,

1 Sanford, Samuel, Saline artesian waters of the Atlantic Coastal Plain: U. S. Geol. Survey Water- Supply 

Paper 258, pp. 75-86,1911.

Stephenson, L. W., and Palmer, Chase, A deep well at Charleston, S. C.: U. S. Oeol. Survey Prof. Paper 

90, pp. 69-94,1915.

a Lane, A. C., Mine waters and their field assay: Geol. Soc. America Bull., vol. 19, p. 501,1909.
22 OIL-FIELD WATERS IN" SAN JOAQUIN VALLEY, CAL.

or to water that has entered the rocks during a second period of 

immersion.

The general concept of connate water is a valuable' one, but the 

practical application of the term in its strict sense is attended by so 

many difficulties that it seems advisable to redefine it in conformity 

to current usage. fA. sample of salt water may reasonably be called 

connate if it approximates ocean water in chemical composition and if 

it occurs in rocks of marine origin in which the circulation of the water 

is very slight. The water in beds of fresh-water origin may be thought 

to be connate, but as the composition of the body of fresh water in 

which the beds were deposited is unknown, the application of the term 

can not be supported by chemical evidence and must rest wholly on 

geologic considerations of a more or less conjectural nature. In actual 

practice, the term can not be applied to a specific sample of water 

unless chemical evidence can be adduced, that is, unless the composition of the original body of water is available for comparison, and 

usually this is possible only when the water is of marine origin. Practically, therefore, the term connate must be restricted to connate 

waters of the marine type, and so xfar as the writer can learn this 

accords with the common use of the term at the present time. On the 

other hand, it is generally impossible to ascertain how far a water has 

migrated or whether it is actually connate to the rocks in which it 

is now found. (See discussion of analysis 25, p. 61.) If it has 

migrated from one formation to another or if it entered the rocks 

during a later period of jmmersion, it is not strictly connate, but 

neither is it pluvial or meteoric. If it were ordinarily possible to 

determine these facts it might be advisable to introduce a new term, 

but as it is not the writer believes that the term connate may be 

extended to include such extraneous waters. Although Lane,1 in 

introducing the term connate, notes that connate water may be either 

salt or fresh, neither he° nor any other investigator, so far as the 

writer knows, has ever attempted to apply the term to specific samples 

of fresh water. If, however, this application should become desirable 

a qualifying adjective may be used to distinguish connate fresh water 

from connate marine water. Similarly, if it is desired to use the term 

in its strict etymologic sense as water that was buried with the bed 

at the time of deposition a phrase such as " connate to the bed in 

which it is found" may be used. For practical purposes, therefore, 

connate water may be defined simply as fossil sea water. The term is 

so used in this report, and although it is recognized that connate fresh 

waters are thereby included with the meteoric or pluvial types there 

seems to be no practicable way of distinguishing them.

The definition here adopted is thus based principally on chemical 

rather than geologic evidence, though as water in contact with rock

i Lane, A. C., op. cit.
OCCURRENCE OF WATER IN OIL FIELDS. . 23

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, like the Paleozoic, may have changed so 

materially that its origin, so far as chemical evidence goes, may be in 

doubt, but some of the salt water in the rocks of San Joaquin Valley is 

so similar to sea water that there can be little doubt that it is fossil sea 

water. (See Table 8, p. 73.) This view is strengthened by the fact 

that the differences in composition between it and normal sea water 

may be adequately explained by fairly definite chemical reactions and 

is corroborated by the fact that geologic conditions in the areas in 

which it occurs are such as to prevent free circulation, which explains 

why it has not been leached out. Some geologists hold that connate 

water can not be retained long in rocks that have been elevated above 

sea level and that salt ground waters are due to the leaching of salt

deposits. However, waters that have leached salt deposits would 

ordinarily differ in composition from ocean water in several respects 

and would probably be unlike any waters in the San Joaquin Valley 

oil fields that are known to the writer. Moreover, as geologic conditions in that region seem to be locally favorable to the retention of 

connate water, the view ascribing salt waters to the leaching of hypothetic saline deposits need not be considered further.

RELATION OF GEOLOGIC STRUCTURE TO DISTRIBUTION OF SALT WATER

IN THE OIL FIELDS.

Though much of the deeper water in the oil fields of San Joaquin 

Valley is very salty, in some localities it is practically fresh. This difference is believed to be due largely to difference in structural conditions. All the fields of the west side are characterized by similar 

structure, being associated with the minor anticlines that border the 

edge of Temblor and Diablo ranges. The anticlines and the synclines 

behind them in all these fields have a general southward plunge. In 

considering hydrologic conditions each field may be regarded as occupying one or more of the following positions: The eastern flank of the 

anticline near its north end, where erosion has uncovered and truncated the oil-bearing strata; the summit and flanks of the anticline, 

where the oil-bearing rocks are deeply buried and do not outcrop; 

the trough between the anticline and the main slope of the valley; 

and the western limb of this trough near the outcrop of the oil-bearing 

beds. If San Joaquin Valley itself be thought of as a great open 

trough with these structural features perched high on its western rim 

it becomes evident that the synclines constitute traps in which the 

ground water may be effectually ponded. In the first position mentioned, however, drainage down into the main valley should be 

relatively free, and in the second and fourth positions the freedom of 

drainage would depend on the completeness with which the waters are
24 OIL-FIELD WATERS IN" SAN JOAQUIN VALLEY, CAL.

ponded in the trough. It is perhaps noteworthy that the accumulation of oil in the first position seems to be unusual and is illustrated 

only in the northern part of the Eastside Coalinga field.

These ideas seem to be supported by the character of the water 

hi the four structural provinces distinguished. So far as data are 

available, all the synclines are characterized by more or less salty 

water, and the proportion of chloride at any point hi the trough is 

apparently governed by its depth and distance from the outcrop. 

The water near the axis of the Midway syncline, for example, is very 

salty, whereas, nearer the outcrop to the west, where fresh water 

may enter the beds, it is much less so, and every gradation between 

the two extremes may apparently be found. (See figs. 6 and 7 and 

discussion, pp. 86-91.) On the other hand, hi the northern part of the 

Eastside Coalinga field, which is on the eastern slope of the southwardpitching anticline, the waters contain only a small proportion of 

chloride, many of them far less than is perceptible to the taste. (See 

analyses 35 and 36, Table 6, p. 69.) The pitch of the anticline has 

caused the oil-bearing strata in this'locality to outcrop a short distance west of the field, and as there is apparently no structural barrier to the east to prevent circulation down into the main valley, 

practically all the connate water has been driven from the beds. 

The removal of chloride has been even more complete north of the 

limits of the productive field, where the structure becomes truly 

monoclinal and the dip somewhat steeper. Chloride is much more 

abundant toward the southern end of the field, however, or down the 

pitch of the fold where the strata are deeply buried.

A similar contrast is apparent if the Kern River field on the east 

side of the San Joaquin Valley is compared with the Midway field. 

The structure in the Kern River field is very much more gentle than 

that typical of the fields of the west side, and apparently no structural barrier exists to pond the water. Furthermore, owing to the 

much greater abundance of water on the east side of the valley, the 

chlorides have been in large part removed, and such other salts as 

are derived from the rocks usually form only a dilute solution. The 

writer knows of only two waters whose analyses show a concentration greater than 2,000 parts per million, and most of the waters 

contain less than 1,000 parts of dissolved mineral matter. (See p. 85.)

The period of subsidence during which the salt water now present 

in the oil fields became entrapped in the rocks can not be determined. 

The Cretaceous and older Tertiary deposits were laid down beneath 

the sea and were once saturated with salt water, and some of the 

later Tertiary formations are also to a large extent of marine origin. 

However, much of the water originally entrapped in the Cretaceous 

sediments was probably leached out during later periods of elevation, and some of the salt water now found in these rocks doubtless
OCCURRENCE OF WATER IN OIL FIELDS. > 25

entered them during the Tertiary periods of subsidence. Furthermore, the stresses incident to the folding of the strata may have 

caused migration from one formation to another; this appears to be 

the most plausible explanation for the local occurrence of salt water 

in the fresh-water beds of late Tertiary age. (See p. 61.) In one 

locality or another salt water is now found in all the Cretaceous and 

older Tertiary formations and in most of the later Tertiary deposits 

as well, but there is usually no way of telling whether or not it is 

connate to the beds in which it occurs, and doubtless much of it was 

entrapped during the most recent periods of immersion.

GENERAL ASSOCIATION OF SALT WATER AND PETROLEUM.

It has long been known that in most oil fields petroleum is rather 

closely associated with salt water, and many attempts have been 

made to explain this widespread association. Few analyses of oilfield waters have been made, however, and the presence of salt in 

many waters has probably been detected by the taste. Although 

presumably the water in most oil fields is salty, and in some is extremely salty, it may be borne in mind that the degree of saltiness 

is known to be variable and must therefore be influenced to some 

extent by local conditions.

Presumably on the assumption that all oil-field waters are strongly 

salty Ochsenius,1 Zaloziecki,2 Beeby Thompson,3 and others have 

suggested that the chloride was concerned in the formation of the oil 

itself, either by acting chemically on the organic matter or by 

retarding premature decomposition. Although there is as yet little 

chemical evidence to support these views it is possible that the 

chloride has exercised some such effect, or has influenced the polymerization, of the oil during a later period in its history. The fact that 

the present distribution of chloride in the oil fields of San Joaquin 

Valley is apparently controlled by local structural conditions would 

not necessarily refute this theory. Such influence as the salt water 

might have would be exercised during the earlier stages of formation 

of the petroleum; and as the diatomaceous shales which are the 

probable source of the California oil are known to have been laid 

down beneath the sea they must have been originally saturated with 

sea water.

On the other hand, there is a possibility that the occurrence of salt 

water in oil fields, may be everywhere explained by the simple principles that seem to be effective in the San Joaquin Valley fields, 

namely, that the water is more or less completely trapped in closed

1 Ochsenius, C., Zur Entstehung des Erdoles: Chem. Zeitung, Band 15, pp. 935 and 1735,1891; Erdolbildung: Deutsche geol. Gesell. Zeitschr., Band 48, pp. 239,685,1896; Erd61 und Salz: Chem. Zeitung.Band 

21, p. 57,1897.

2 Zaloziecki, R., Zur Entstehung des Erdoles: Chem. Zeitung, Band 15, p. 1203,1891.

3 Thompson, A. B., Petroleum mining, p. 113,1910.
26 OIL-FIELD WATEES IN SAN JOAQUIN VALLEY, GAL.

sand lenses or by structural barriers. The very fact that the oil 

itself can accumulate and remain within a small area under high 

pressure for long periods of tune implies that the underground 

circulation is decidedly restricted. Hence if salt water originally 

saturated the beds it is reasonable to expect that under most conditions some of it would be retained also. No very positive proofs of 

this simple explanation, can be offered until more is known of the 

chemical character of oil-field waters in relation to physical conditions, but in the absence of evidence to substantiate the theory that 

chlorides are concerned in the formation of the oil, this suggestion 

may be worthy of consideration.

Another view that may be mentioned in passing is that salt water 

in oil fields has certain peculiarities of composition which indicate 

that it is, in part at least, of deep-seated origin.* It has been shown 

that the distribution of salt water in the San Joaquin Valley oil 

fields may be explained on simple physical principles, and it will be 

shown below that this water has yearly the composition of sea water 

with certain modifications due to definite chemical reactions. There 

is nothing to show that it has emanated from the interior of the earth, 

and an appeal to recondite agencies is unnecessary.

DISTRIBUTION OF WATER IN THE OIL FIELDS.

The following notes on the occurrence of water in the several oil 

fields are included in order to enable* one unfamiliar with the fields to 

understand more clearly certain features of the chemical relations of 

the waters. No attempt is made to describe local conditions in 

detail or the damage wrought by the intrusion of water into the oil 

sand. Most of the analyses on which this paper is based represent 

waters from the Coalinga, Midway, and Sunset fields, and reference 

to the physical conditions in these fields will again be made in discussing the chemical relations of the waters.

COALINGA FIELD.

The Coalinga oil field is divided into two fairly distinct districts, 

the Westside and the Eastside fields. The Westside field is situated 

on the western limb of a syncline and the Eastside field is practically 

confined to the summit and eastern limb of the anticline to the east. 

The deeper portion of the syncline has not been explored. The 

ground-water level in the whole area is generally within 200 feet of 

the surface, and most of the water needed for industrial use is 

obtained from comparatively shallow water wells. Throughout the 

area the shallower waters are highly mineralized and are notable for 

their very high proportion of sulphate.

1 Washburae, C.JW., Chlorides in oil-field waters: Am. Inst. Min. Eng. Trans., vol. 48, pp. 687-694,1915.
DISTRIBUTION OF WATER IN OIL FIELDS. 27

In the Westside field many of the waters above the oil sands are 

under considerable head, and water flowed at the surface from some 

wells for several years. Some of these top waters are very corrosive 

and have caused considerable damage by attacking and destroying 

the casing used to prevent their entrance into the oil sands. Strong 

water sands are generally encountered near the tar sand zone, and 

many of these waters contain hydrogen sulphide and are known as 

sulphur waters. In the deeper or eastern part of the Westside field 

there is a water sand a short distance above the oil zone but farther 

up the rise to the west this same sand carries oil. In most localities 

a similar condition apparently exists in a sand near the base of the 

oil zone; to the east this sand carries the "bottom water," but up 

the rise it is oil bearing and the first water below the oil is hi the 

upper part of the Oligocene (?) shale. In general the water below 

the oil zone is confined under considerable pressure, and even now 

rises within a few hundred feet of the surface.

Owing to the southerly pitch of the anticline on which the Eastside 

field is situated the strata outcrop a short distance west of the northern end of the field but at the southern end are deeply juried. As the 

beds dip rather steeply to the east in the northern part of the field, 

and as there is apparently no structural barrier to the east to restrict 

circulation, a relatively free passage is afforded such water as seeps 

in at the outcrop. In most sands the water is therefore not under 

very high head. It is not so highly mineralized as in the Westside 

field and is characterized by a low proportion of chloride. However, 

toward the southern end of the Eastside field the circulation is more 

restricted, and the average head is therefore higher and the percentage of dissolved matter, especially chloride, is greater. The occurrence and distribution of the water in the Eastside .field is not yet 

thoroughly understood and presents many puzzling irregularities.

LOST HILLS FIELD.

The Lost Hills field extends in a narrow belt along the axis of a 

well-defined anticline, the continuation of that which dominates the 

structure in the Coalinga field. Most of the strata penetrated by the 

wells probably do not outcrop, and conditions are therefore not favorable for free circulation. On the west or inclosed slope of the anticline very salty water is obtained at relatively shallow depths, in 

some places within a few hundred feet of the surface, but farther east 

the shallow water contains a high proportion of sulphates. From the 

scanty information available it appears that the water near the oil 

zone is very salty and is confined under considerable pressure.

McKITTRICK FIELD.

The McKittrick field is characterized by more complex structural 

features than any other field in San Joaquin Valley. In a general
28 OTL-PIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

way, the productive district lies on the flanks of three folds, but the 

structure is complicated by overturned folds and thrust faults.

The circulation of the shallower waters is apparently controlled 

chiefly by the topography, these waters being more abundant and 

more highly mineralized in the McKittrick Valley than in the foothills to the west. The deeper circulation, however, is undoubtedly 

affected by the complex geologic structure, and little can be said of 

its course or nature until more complete information is available. 

The oil-bearing zone is generally underlain by a sand carrying warm 

water under considerable pressure. In part of the field the oil sands 

have been flooded, and it is generally believed that the damage had 

been done by this water. Whatever its original source, the water 

that has flooded the oil zone is very uniform in chemical composition 

and is probably the yield of a single water sand. Little variation is 

shown by about 30 analyses of this water at the writer's disposal, 

and analysis 89 (Table 14, p. 85) is entirely representative.

MIDWAY-SUNSET FIELD.

The Midway and Sunset fields are arbitrary divisions of a great oilproducing area, and as the geology of both fields is similar they may 

best be described together. The developed area extends west from 

the east slope of the Buena Vista anticline across the Midway syncline and up on its western limb, where the oil-bearing strata outcrop. 

The western limb of the trough is not a regular slope as in the Westside Coalinga field but is broken by several minor anticlines, all pitching to the southeast.

The ground-water level in the Midway-Sunset field is lower than 

in the Coalinga field and is generally 250 to 500 feet below the surface. Along the hilly western part of the field the shallower water 

is almost lacking and in some localities is not abundant even to the 

depth of the oil zone. Generally, however, some water is found near 

the tar sands and also between them and the oil. At a variable depth 

below the oil zone, usually less than a hundred feet, abundant supplies of warm water under considerable pressure are found. Owing 

to the scarcity of shallow water this "bottom water" is widely used 

for industrial purposes in this part of the field.

In the Midway Valley and the Buena Vista Hills, which are the 

surface reflections of a syncline and an anticline, respectively, the 

water conditions are somewhat different. In the valley moderate 

supplies of water may generally be obtained at a depth of 200 to 

500 feet, but in many localities even the shallower water contains 

a remarkably high percentage of sodium chloride. In the Buena 

Vista Hills the water level is generally lower, but the water is similarly salty. The percentage of salt increases with depth, but at a 

variable rate; in some localities water from 700 feet is almost fresh
OCCURRENCE OF WATER IN OIL FIELDS. 29

enough to be potable, whereas in others it is nearly as salty as sea 

water. Many of the deeper top waters are confined under high 

pressure and flow at the surface. In most localities there is a rising 

or flowing water a short distance below the top oil sand, and in the 

deeper part of the syncline this oil sand is itself water bearing. 

Where second and third oil sands have been found, strong water 

sands are generally present between them. Although the water 

pressure as a rule is high, it is decidedly variable, and "dry" sands 

have been reported in many places. The deeper waters in this part 

of the field are fairly uniform in chemical character but differ from 

those at the same horizon in the shallower western part of the field. 

(See figs. 6, p. 88, and 7, p. 91.) Their average temperature is also 

different, being ordinarily some 10° higher.

KERN RIVER FIELD.

The Kern River field, lying on the lowest foothills of the Sierra 

Nevada on the east side of San Joaquin Valley, differs in many 

respects from those just described. The geologic structure is relatively simple; the strata lie in a gentle monocline, which is modified 

in places by minor wrinkles. The oil sands are very thick and are 

highly productive, but the gas pressure has never been very high.

Kern River, which has a large drainage basin in the Sierra Nevada 

flows along the edge of the field. The waters draining from the Sierra 

are very different in chemical character from the waters on the west 

side of the valley and contain only a very small amount of dissolved 

salts, which are chiefly carbonates. The ground-water level in the 

Kern River field is high, and in most localities abundant supplies of 

potable water are obtained relatively close to the surface, and thence 

at short intervals down to a depth of many hundred feet. In general 

the percentage of dissolved salts increases with depth, but even in 

'the deepest waters reached is usually less than in the average shallow water in the fields of the west side. Owing to the sandy character of the strata and to the fact that no pronounced structural 

barrier separates the field from the valley proper, the underground 

circulation is less restricted than in most of the fields of the west 

side, and the general water pressure is therefore comparatively low. 

Flowing waters have been encountered, but they are not common.

ANALYSIS OF WATER AND INTERPRETATION OF 

RESULTS.

MINERAL CONSTITUENTS IN WATER.

Natural waters are essentially solutions of mineral substances 

which have been derived from the rocks or other material with which 

the waters have come in contact. All solutions may be regarded as 

homogeneous bodies, through which the mineral substances are
30 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

uniformly distributed, and all solutions have definite properties, 

which depend on the nature and proportional amounts of the substances of which they are composed. By chemical analysis of 

water only the proportional amounts of the constituents are determined. The nature of each constituent, that is, its conduct toward 

other substances whose natures are known, has been learned by other 

methods, and as the properties of a solution are an assemblage of 

the properties of all its constituents, the properties of a water may 

be deduced from the statement of its analysis.

The amount and character of the mineral substances dissolved in 

different waters vary greatly and depend on many factors. Chief 

among these 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. Water under a given temperature and pressure 

can dissolve only a definite amount of any substance; and if the 

heat and pressure are lowered, as, for example, when an underground 

water emerges at the surface, the excess of dissolved matter may go 

out of solution as a precipitate. It is through this readjustment to 

changed conditions that mineral matter is deposited around some 

springs or wells. Similarly, if two waters carrying different salts 

in solution come into contact, a chemical reaction may take place 

and some of the dissolved material may be precipitated. Although 

many of the reactions that take place are obscure and can not be 

completely explained, the properties of natural solutions, which are 

the net results of these reactions, furnish a rational basis for general 

classification.

In addition to dissolved mineral solids or gases, which chiefly determine the chemical properties of a water, two other classes of substances are generally present material in suspension, which can be 

removed by filtering, and material in colloidal solution, a state intermediate between suspension and true solution. In the present 

study consideration has been given chiefly to the commoner dissolved mineral substances. Small amounts of several elements, such 

as lithium, barium, phosphorus, and boron, are probably present hi 

some of the oil-field waters, but they do not materially affect the 

quality of the water and their determination is not essential to a 

study of the relations of water to petroleum.

COLLECTION OF SAMPLES.

In most districts the collection of representative water samples for 

analysis is a simple matter, but in the oil fields, where the- universal 

aim is to shut the water out of the wells, it is often very difficult. In 

wells that supply water for industrial uses the depth of the water 

sands is generally known, and samples can, of course, be easily taken,
ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 31

but the waters that can be obtained in this way are few. Some of 

the oil wells produce water which is known to come from a certain 

depth, but generally its exact source is unknown. In the oil fields, 

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. When a sufficient number of authentic samples 

of typical waters in any area has been collected and analyzed it will 

then be possible, by comparison with these standards, to form an 

estimate of the probable source of any water.

Authentic samples can usually be taken only while drilling the 

well or while repairing it later. Flowing waters may, 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. When the well is being drilled by 

the standard method the collection of samples is not especially difficult, and samples uncontaminated by water from upper sands may 

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 rotary 

systems are used the proper collection of samples is often difficult 

or even impossible. Waters that flow when the pressure is released 

may be sampled at -the expense of slight 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 be 

used as a standard for exact comparison. For this 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. 

DETERMINATION OF CONSTITUENTS

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 former 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 (Si02 ), ferric oxide (Fe2O3 ), and alumina (A1203 ). The con-
32 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

stituents 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 or 

equilibrium 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.

The number of constituents to be determined and the accuracy 

with which the work is done differs 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 (S04 ), chloride radicle (Cl), 

nitrate radicle (N03 ), carbonate radicle (C03 ), bicarbonate radicle 

(HC03 ), silica (Si02 ), and total solids at 180° C. It is well also to 

test waters from oil fields for sulphide (S), a nonvolatile negative 

constituent, and the volatile substances hydrogen sulphide (H2S), and 

carbon dioxide (C02 ). The quantity of suspended matter and the 

quantity of organic matter also are usually determined.

Iron and aluminum are usually precipitated and weighed together 

and reported as the oxides (Fe2O3 +Al2O3 ) in industrial analyses, and 

carbonate and bicarbonate are often not distinguished from each 

other. The laborious determination and separation of sodium (Na) 

and potassium (K) 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 implies, of course, that 

the determination of all the other radicles is absolutely correct, which 

is practically never the case; whatever errors are made in the determination of all the other radicles are repeated and thrown together 

in the calculation of the alkalies. This practice thus conceals all 

error of analysis and makes it impossible to ascertain the accuracy 

of the analysis from the reported figures. If, on the other hand, all 

the radicles are actually determined the bases can be balanced against 

the acids and the discrepancy discovered. Even -with reasonably 

careful work the unavoidable errors in determination usually amount 

to 1 per cent and may be. 4 or 5 per cent.

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
ANALYSIS OF WATER' AND INTERPRETATION OF RESULTS. 33

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 roots or portions of compounds that are 

known as radicles. In fact, present chemical knowledge indicates 

that a salt dissolved in water largely ceases to exist as an actual compound; according to the ionic theory it becomes partly dissociated 

into its component radicles, which become electrically charged or 

ionized, and it participates in chemical reactions only in so far as it 

is ionized. Even if it were held that the radicles of dissolved salts 

are actually combined it is a chemical and mathematical impossibility to ascertain by analysis to what extent a given base is' combined 

with a given acid.1 Despite this condition it is common practice to 

report hypothetical combinations by several methods of calculation, 

founded on different theories or devised from different points of view, 

in accordance with which the radicles are apportioned to one another. 

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. It has been shown that -the character of a water for industrial 

purposes, its fitness for domestic use, and its relation to its environment can be defined without recourse to hypothetical combinations.2

As there appears to be no valid reason for reporting analyses hi 

hypothetical combinations and as it is impossible to compare analyses 

so reported by different chemists, the analyses in this report have been 

calculated to 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.

For the convenience of those who may desire to transform results 

into parts per million it may be stated that 1 grain per United States 

gallon is equivalent to 17.1 parts per million, 1 grain per imperial 

gallon to 14.3 parts per million, 1 part per hundred thousand to 10 

parts per million, 1 gram per kilogram to 1,000 parts per million by 

weight, and 1 gram per liter to 1,000 parts (weight) per million 

(volume). All the analyses in this report made by the Geological 

Survey are 'stated in parts by weight per million volume/ and the 

remaining analyses are believed to be also stated in this way.

1 Dole; R. B., Hypothetical combinations in water analysis: Jour. Ind. and Eng. Chemistry, vol. 6, 

pp. 710-721,1914.

2 Stabler, Herman, The mineral analysis of water for industrial purposes and its interpretation by the 

engineer: Eng. News, vol. 60, p. 355,1908; Some stream waters of the western United States, with chapters 

on sediment carried by the Rio Grande and the ind ustrial application of water analyses: U.S. Geol. Survey 

Water-Supply Paper 274, pp. 165-181,1911. Clarke, F. W., The data of geochemistry, 3d ed.: U. S. GeoU 

Survey Bull. 616, pp. 59-61,1916. See also U. S. Geol. Survey Water-Supply Paper 254, pp. 233-258,1910, 

and Water-Supply Paper 259, pp. 173-197, 1912.

60439° Bull. 653 17 3
34 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

The factors in the accompanying table may be used for converting 

statements in hypothetic combinations into ionic form. The product 

obtained by multiplying the reported content of each salt by the 

appropriate factor is the content of the positive radicle or base, and 

the difference between this product and the reported content of the 

salt is the content of the negative or acid radicle in the compound. 

The aggregate for each radicle in the various salts is the total quantity 

of that radicle in the water. Silica, iron oxide, and alumina may 

generally be considered colloids and so retained in the restated 

analysis.

Factors for calculating the amount of the base or positive radicle in various salts.

GivenMagnesium sulphate (MgS04 ). ..........................................To find 

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

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

Magnesium (Mg) . . 

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

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

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

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

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

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

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

Potassium (K)....

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

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

Hydrogen (H) ....

Factor.

0.294 

.361 

.400 

.247 

.202 

.255 

.288 

.165 

.324 

.394 

.434 

.274 

.590 

.411 

.449 

.524 

.569 

.391 

.059

For illustration the details of converting an analysis into ionic form 

in parts per million are given. The labor involved is considerably 

lessened if a slide rule or similar calculating machine is used.

Grains per, 

Analysis as reported: ' u. S. gallon.

Calcium sulphate (CaS04j................................. 3. 79

Calcium carbonate (CaC03)................................ 7. 90

Sodium chloride (NaCl) ................................. 40. 60

Sodium carbonate (NaaCOg) ............................... 21. 70

Recalculation:

3.79 grains CaS04 X

3.79 -

7.90 grains CaC03 X

7.90 -

40.60 grains NaCl X

40.60 -

73.'99

.294............................ LllCa

1.11....;....................... 2. 68 S04

.400 ........................... 3.16 Ca

3.16 ........................... 4. 74 C03

.394........................... 16.00Na

16.00 .......................... 24. 60 Cl

21.70grains NaoC03 X .434 ........................... 9. 43 Na

21.70 - S.43 ........................... 12. 27 C03
ANALYSIS OF WATER AND INTERPRETATION OF RESULTS. 35

_ , . ,. /-, , j Grains per Recalculation Continued. U. S. gallon.

Total Ca =1.11 +3.16 .................................... 4.27

Total Na =16.00+9.43 .................................... 25.43

Total S04 ................................................ 2.68

Total Cl ................................................. 24. 60

Total C03=4.74 +12.27 ................................... 17. 01

73. 99

Grains per Parts per 

U. S. gallon. million.

Ca = 4. 27 X 17.1= 73.1 

Na =25. 43 X 17.1=435. 2 

S04= 2:68 X 17.1= 45.9 

Cl =24.60 X 17.1=421.1 

C03=17.01 X 17.1=291.2

73. 99 1,266. 5 

Proof: 73.99X17.1=1,266.5.

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 of reacting 

values, which shows numerically the relative proportions of the radicles by chemical weight, in terms of capacity for reaction. 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 capacity for chemical reaction, though the ratios for the several radicles 

are different and the relation between the two forms of statement is 

therefore complex. The reacting value per unit weight of magnesium, 

for example, is much higher than that of sulphate, 10 parts of magnesium being chemically equivalent to 39.5 parts of sulphate. In 

order to understand the possibilities of reaction of the radicles in a 

water they should be considered as individuals acting together under 

the law of equivalent combining weights, each contributing its proportional share to the balance of the system.

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* 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 is the ratio of the reaction capacity of one part of that 

radicle to the reaction capacity of eight parts of oxygen; in numerical 

value it is the valence of the radicle divided by its weight on the

1 Stabler, Herman, The mineral analysis of water for industrial purposes and its interpretation by the 

engineer: Eng. News, vol. 60, p. 355,1908; also chapter on the industrial application of water analyses in 

U. S. Geol. Survey Water-Supply Paper 274, pp. 165-181,1911.
36 ' OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

atomic scale. The following table shows the reaction coefficients of 

the positive and negative radicles most commonly found in waters:

Reaction coefficients of positive and negative radicles most commonly found in waters.

Positive radicles.

Potassium (K) ...................

Reaction coefficients.

0. 0434 

.0256 

.0499 

.0821 

.992

Negative radicles.

Chloride (Cl)....................

Nitrate (N08 ). ..................

Carbonate (C03 ) ................

Bicarbonate (HC03 ) ............

Reaction coefficients.

 0.0208 

.0282 

.0161 

.0333 

.0164 

.0622

The reacting values of silica, iron, and alumina 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 of 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 radicles (acids), the 

reacting values of the two groups should be the same, each making 

up 50 per cent of the total. This principle is utilized by tha chemist 

in making a partial analysis wherein the alkalies are calculated by 

difference. If the analysis under consideration is of this type the 

sum of the reacting values of the bases and acids should therefore be 

the same, but if all the constituents have been directly determined 

unavoidable errors usually cause the totals of basic and acidic reacting 

values to differ slightly and this difference is an index of the accuracy 

of the analysis.

The conversion of the following analysis from the ionic form into 

reacting values is included in order to make this explanation clearer:

Conversion of analysis from ionic form into reacting values.

Parts per 

million.

Na............................ 435.2

Ca............................. 73.1

X 

X,

Reaction Reacting Reacting values

coefficients. values, in per cent.

0.0434 = 18.88 41.9

. 0499 = 3. 64 3.1

508. 3

S04 

CL. 

C0a ............................ 291.2

758.2

22. 52 50. 0

45.9 X

421.1 X

291. 2 X

.0208 =

. 0282 =

.0333 =

.95

11.87

9.70

2.1

26.4

21.5

22. 52 50. 0
ANALYSIS OF WATER AND INTERPRETATION OP RESULTS. 37

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 1 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 the one followed in this 

report. The writer has found this system very valuable, for it 

emphasizes certain differences between waters that are fundamental 

from the standpoint of the geologist and the industrial chemist, and 

is very convenient in the comparison of analyses.

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 soft, but 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 and determinable properties. 

For example, if 90 parts of sodium chloride and 10 parts of sodium 

carbonate are dissolved in water, the properties of the composite 

solution will be a summation of those of the solutions of the separate 

salts; in other words, the composite solution is characterized by 90 

per cent salinity and 10 per cent alkalinity. If to this solution calcium chloride is added, the percentage of these properties is altered, 

and a third property, hardness, is introduced. In a mixed solution 

of this kind it is no longer possible to state how much of each salt is 

present; reactions have taken place and it is impossible to learn by 

analytical methods the order of the combinations that have resulted. 

Chemical analysis can determine only the amounts of the different 

radicles presant.

Although for the sake of simplicity the properties or qualities of 

the solution have in the preceding paragraph been ascribed to various 

salts, they are in reality due to the radicles themselves, uniformly 

distributed and,held in balance; and inasmuch as the salts can not 

be determined they need not be considered further.. The general 

reactive properties of the solution may be readily deduced from the 

amounts of the radicles present, and in order to do this without 

undue complication those radicles which are similar chemically or 

associated geologically may conveniently be grouped together. Thus, 

the common bases may be grouped as" alkalies (Na and K) and alka1 Palmer, Chase, Geochemical interpretation of water analyses: U. S. Geol. Survey Bull. 479,1911.
38 OIL-FIELD .WATERS IN SAN JOAQUIN VALLEY, CAL.

line earths (Ca and Mg), and the common acids as strong acids (Cl, 

S04, and N03 ) and weak acids (C03 , HC03 , and S). The reactive 

properties of a water are governed by the respective proportions of 

these groups. Thus, if the value of the alkalies exceeds that of the 

strong acids, the hardness of the water may be removed simply by 

boiling, but if the strong acids exceed the alkalies, the -water is permanently hard. Similarly, if the value of the strong acids is less 

than that of the alkalies plus the earths, the water is characterized 

by alkalinity, but if it is greater the water is acid.

In order to define more exactly the properties of a water, Palmer 

considers in detail the balances that may exist between the two basic 

and two acid groups of radicles and assigns to each a jiame. Salinity 

is denned as the property induced by the strong acids and alkalinity 

as that measured by the weak acids. The properties due to the 

presence of alkalies are called primary, and those due to the presence 

of the alkaline earths secondary properties. Hence the balance 

between the alkalies and the strong acids is called primary salinity 

and that between the alkaline earths and the weak acids secondary 

alkalinity, which is more commonly known as temporary hardness. 

If the strong acids exceed the alkalies, the excess must be held in 

equilibrium by the alkaline earths, and this balance is accordingly 

called secondary salinity > which is permanent hardness. If, on the 

other hand, the alkalies exceed the strong acids, the excess is balanced, against the weak acids, and this balance is known as primary 

alkalinity. The two last-named properties are obviously incompatible ; nearly all waters are characterized by either one or the other, 

but a water can not exhibit both. All the oil-field waters are characterized by primary salinity and secondary alkalinity and by either 

primary alkalinity or secondary salinity. The three properties furnish a rational basis for classification and preliminary study, and are 

evidently far more convenient for general comparison than the detailed analyses.

The manner in which these properties are deduced from the analysis 

is shown graphically in figure 2, which represents analysis 31 (Table 5, 

p.-66). It is assumed that the analysis has already been converted 

into the ionic form and that the reacting values of the radicles have 

been determined and reduced to a percentage basis as previously 

described. In this form the values of the basic radicles constitute 

50 per cent of the total and those of the acid radicles 50 per cent. 

In the figure the bases and acids have been plotted to scale in two 

columns of equal length, the alkalies and strong acids being placed 

at the bottom and the earths and weak acids above. In the central 

column, are shown the properties of reaction that result from the 

proportions of these groups shown. As primary salinity is due 

to the balance between equal values of the alkalies and strong acids
ANALYSIS OP WATER AND INTERPRETATION OF RESULTS. 39

Properties of 

reaction

Acids Bsses

its amount is determined by the smaller of its two components. In 

other words, the 22.3 per cent of strong acids present, in connection 

with an equal amount of alkalies, forms 44.6 per cent of primary 

salinity. This leaves an excess (19.5 per cent) of the alkalies which 

balances with an equal value of the weak acids and induces the property primary alkalinity to the extent of 39 per cent. Of the 27.7 

per cent of weak acids 8.2 per cent are then left 

in balance with the total (8.2 per cent) alkaline 

earths, which gives rise to 16.4 per cent of secondary alkalinity. This water is therefore characterized by 44.6 per cent primary salinity, 39 

per cent primary alkalinity, and 16.4 per cent 

secondary alkalinity. On the basis of these properties, or relations of reacting values, it may be 

rationally classified or compared with any other 

water.

In the analysis selected the alkalies exceed the 

strong acids and therefore induce primary alkalinity. If the reverse were true, and the strong 

acids exceeded the alkalies, it is evident that a 

different property would result. In such a water 

some of the strong acids would be balanced by 

the alkaline earths and secondary salinity would 

result instead of primary alkalinity; in other 

words, the water would be permanently hard. 

The writer has found this distinction one of the 

most valuable features of Palmer's classification, 

for by it all waters are separated into two important .groups. The distinction is valuable industrially, for it separates permanently hard waters 

from those whose hardness is mostly lost on boiling. The distinction is of equal importance geologically. Thus, the surface waters on the west 

side of San Joaquin Valley are characterized by 

high sulphate and low carbonate and by roughly 

equal amounts of the alkalies and alkaline earths; 

some of the strong acids are balanced by alkaline 

earths and the waters have, therefore, the property of secondary salinity. On the other hand, in most of the waters 

associated with the oil the alkalies are very high and sulphate is 

lacking; in these waters some of the alkali group are in equilibrium 

with weak acids and 'the waters therefore have the property of primary alkalinity. By a study of the properties of the waters all tfye 

stages in the transition from the extreme secondary saline type to the 

extreme primary alkaline type may be definitely traced, and distincFIQURE 2. Graphic representation of analysis 31 

(Table 5, p. 06), showing 

method of deducing the 

properties of a water from 

its composition.
40 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

tions become apparent that do not suggest themselves in a study of 

the original analysis.

In addition to the three properties of reaction two other factors 

may be taken into account as criteria for comparison. One of these 

factors is the ratio of the chloride to the sulphate radicles, for in 

Palmer's system these radicles are classed together as strong acids. 

Since the strong acids give rise to salinity, chloride salinity and 

sulphate salinity may be distinguished, and these may conveniently 

be expressed as percentages of the total salinity. For example, the 

sulphate salinity ratio in analysis 31 (shown graphically in fig. 2, 

p. 39) is rS04 divided by rS04 + rCl, or 13 divided by 22.3 = 58.3 per 

cent (of the total salinity). The other factor 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. In 

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.

The calculations involved in the stages leading up to the deduction 

of the properties of reaction may seem long and tedious, but the 

value of the results should more than pay for the necessary labor. 

Adequate comparison is impossible until the analyses have been converted into ionic form; and when this step has been accomplished 

the labor of calculating the reacting values and deducing from them 

the properties of reaction is inconsiderable.

i . 

SOURCE AND STATEMENT OF ANALYSES IN THIS REPORT.

In order to give an adequate idea of the principles that seem to 

control the composition of the oil-field waters, 88 analyses selected 

from several hundred available for the writer's study are included in 

this preliminary report. These analyses have been selected, first, 

according to their representation of the chemical variation encountered; second, according to their position with regard to the oil; 

third, according to the probable accuracy of the analytical work; 

and, fourth, according to their geographic distribution.

Of the 88 analyses given 30 were made by the Geological Survey, 

17 by the Standard Oil Co., 12 by the Kern Trading & Oil Co., and 

29 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 pretty close limits. The remaining 

analyses are believed to be reliable, but they were made only for
CLASSIFICATION OF THE OIL-FIELD WATERS. 41

industrial purposes and doubtless 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.

In the tables of analyses the properties of reaction are stated first, 

as they are believed to be the most suggestive as well as the most 

convenient basis for general comparison. The sulphate salinity 

ratio, or the percentage of rS04 in rS04 +rCl, is included under the 

properties of reaction, and in certain types of water the ratio of the 

values of carbonate and bicarbonate to the sulphate value is also 

given. Below the reaction properties is given the analysis itself, 

stated in radicles in parts per million; this is a summary of the basic 

data on which any form of interpretation must rest. The analysis 

is also stated in reacting values in percentages, a form that admits

direct comparison of the chemical values of the radicles but does not 

express the actual amounts present or the concentration of the solution. Finally, those analyses which were not made by the Geological 

Survey and which were originally stated in hypothetical combinations in grains per United States gallon are given in the tables in 

their original form also. To some readers this form of statement 

may be the most familiar, but for rational scientific study one of the 

other forms is strongly recommended.

CLASSIFICATION OF THE OIL-FIELD WATERS.

DISTRIBUTION AND SIGNIFICANCE OF THE CONSTITUENTS.

Alkalies (sodium and potassium}. In most of the analyses in this 

report the alkalies, sodium and potassium, have not been separated, 

and as their chemical properties and distribution are similar they 

will be considered together. The alkalies are by far the most abundant-bases in the oil-field waters, and in many of the deeper waters 

they and their equivalent acid radicles constitute over 95 per cent 

of the total mineral content. In surface waters the alkalies are less 

prominent, but in waters from depths of more than 250 or 300 feet 

they usually predominate over the other bases. The waters associated with the oil in the western parts of the Coalinga, Midway, and 

Sunset fields contain the alkalies almost to the exclusion of the other 

bases.

The great predominance of alkalies over the other bases is a notable 

feature of the composition of the waters of the oil fields of the west 

side of San Joaquin Valley, for in most regions of sedimentary rocks 

the waters are characterized by a moderate to low proportion of alkalies. The salts of the alkalies are highly soluble and therefore are 

never deposited from saturated solution, except in arid regions, 

where they tend to accumulate at the surface as deposits of "alkali,"
42 OIL-FIELD WATERS IN SAN JpAQUIN, VALLEY, CAL.

which is usually the sulphate. As the oil fields on t^ie west side of 

the valley are located in a very arid region the relative prominence of 

the alkalies in the shallower waters is to be expected. Furthermore, 

in connate1 water (fossil sea water) the alkalies greatly predominate 

over the other bases, and as the deeper oil-field waters are partly 

or wholly of connate origin, two sets of conditions have combined to 

cause the high concentration of alkalies in the waters of the fields 

of the west side. In the Kern River field, on the east side of the 

valley, water is more plentiful, and the first condition is therefore 

less pronounced, but as the deeper waters are partly of connate 

origin their content of alkalies is fairly high.

In sixteen of the analyses given below sodium and potassium have 

been determined separately. The potassium is generally present in 

very small proportion, the average ratio of sodium to potassium by 

weight being about 125 to 1. The average surface water in most 

regions contains by weight about one-fourth as much potassium as 

sodium, and ocean water only about one-thirtieth as much. 1 This 

discrepancy is due to the fact that when mixed solutions containing 

sodium and potassium are passed through soil or clay the potassium is 

almost wholly extracted and held, whereas the sodium is comparatively 

unaffected; 2 hence the potassium in ordinary surface waters is largely 

lost during their passage to the sea. Similarly, if sea water is then 

entrapped in the sediments, the separation will continue still further 

and nearly all the potassium will be removed. This principle has 

thus operated to remove nearly all of the potassium in the connate 

and partly connate water of the oil fields. (See p. 93.)

Alkaline earths (calcium and magnesium}. In a few of the surface 

waters and shallow ground waters in the oil fields of the west side 

of the valley the alkaline earths exceed the alkalies, but in practically 

all the deeper waters their relative proportion is very low. This is 

due not only to the high concentration of the alkalies, as already 

explained,.but also to the fact that the alkaline earths themselves 

are generally present in small actual amount. Large amounts of 

the earths can not be retained in waters in which more than a certain value of carbonate or bicarbonate is present, and if this value 

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 important constituents, but 

in the waters near the oil zone in the western parts of the Coalinga, 

Midway, and Sunset. fields carbonate is high and the earths are 

accordingly low. In the connate waters in the central part of the 

Midway and Sunset fields chloride is very high and carbonate low,

1 Clarke, F. W., The data of geochemistry, 3d ed.: U. S. Geol. Survey Bull. 610, p. 138,1916.

2 Van Bemmelen, J. M., Das Absorptionsvermogen der Ackererde: Landw. Versuchs-Stationen (Berlin), vol. 21, pp. 135-191,.1878.
CLASSIFICATION OF THE OIL-FIELD WATERS. 43

and in this type of water the earths constitute as much as 10 per 

cent of the total mineral content.

In sea water the ratio of magnesium to calcium by weight is about 

3, or if expressed in terms of reacting values, about 5. It is therefore 

interesting to note that in that type of oil-field water which the writer 

considers connate, and which closely resembles sea water in all other 

respects, the average ratio of the reacting values of magnesium to 

calcium is only 0.71. In some of the surface waters and shallower 

ground waters, especially those in the Coalinga field, the ratio is 

almost as high as in sea water, but this is accounted for by the fact 

that these waters are a part of the drainage of areas in which ferromagnesian (Jurassic) rocks outcrop. The deficiency of magnesium 

in the deeper waters can not be so easily explained. At high temperatures magnesium is deposited from solution as basic carbonate or 

hydrate,1 and it is possible that the temperatures of 100° to 125° F., 

which prevail in the oil fields at depths of 1,000 to 3,000 feet, have 

had some effect in lowering the concentration of magnesium. It is 

also possible that the magnesium is removed as magnesium silicate, 

though no evidence was obtained in the field to support this view.

In the table on page 92 are given the average ratios of magnesium 

to calcium in the several types of water in the Coalinga, Midway, and 

Sunset fields, only the analyses included in this report being represented. The variations, in these ratios are discussed in more detail 

below, but it may be pointed out here that the average ratio in the 

Coalinga field is considerably higher than in the Midway and Sunset 

fields, and that the ratio in the brine is only about half as great as in 

the other types of water.

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 

Coalinga field sulphate and its equivalent basic radicles constitute 

over 85 per cent of the total mineral content. Outside of the oil 

fields most of the deeper ground waters are also characterized by a 

high concentrationxof sulphate, but this figure bears no constant relation to depth. Within the oil fields, 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 1 per cent, although in the Eastside Coalinga field sulphate is 

usually higher and some of the waters may contain as much as 5 per 

cent. The tables of analyses below show the ratio of sulphate to 

sulphate plus chloride by reacting value in all the waters discussed, 

and in many of these waters the ratio of sulphate to carbonate as well.

i Davis, W. A., Studies of basic carbonates: Soc. Chem. Ind. Jour., vol. 25, p. 796,1906.
44 OIL-FIELD WATERS IF SAN JOAQUIN VALLEY, CAL.

The decrease of sulphate in the waters as the oil measures are 

approached, 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 93-99.

A great predominance of sulphate in the shallower waters is characteristic of most arid regions. Gypsum (calcium sulphate) is disseminated through the rocks and furnishes an abundant supply to 

the scanty volume of water percolating through them. In addition, 

much of the "alkali" that occurs<as an incrustation or efflorescence 

in arid regions is sodium and magnesium sulphate. Ocean water 

contains about 2,700 parts per million of sulphate, or 7.7 per cent of 

the total mineral content.

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.

As already explained, the chloride in the oil-field waters is undoubtedly 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. Where the geologic structure is 

such as to prevent circulation the water is very salty, and in some 

localities the concentration of chloride in it is as great as in ocean 

water. Near the surface and 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 industrial 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, in 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 in temperature or decrease in pressure may drive 

part of the carbon dioxide from the solution and thus cause a rever-
CLASSIFICATION OF THE OIL-FIELD WATERS. 45

sion to carbonate. A solution of calcium bicarbonate, for example, 

yields calcium carbonate on boiling. The bicarbonates of 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 

formed, most of the normal carbonate is thrown out as a precipitate 

or "scale." The solubility of the alkaline earth radicle in the presence of the carbonate radicle therefore depends largely on the concentration or "partial pressure" of carbon dioxide in the solution. 

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 in 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 the San Joaquin 

Valley, and in the normal ground water are generally present in 

minor amount. In the waters associated with the oil, however, 

they are generally present in larger amounts, and when chloride is 

absent carbonate .and bicarbonate constitute the only acid radicles. 

As chloride increases, however, these weak acid radicles decrease, 

and in the strong brines they are present only in very small amounts.

Carbonate and bicarbonate have been differentiated in 30 of the 

analyses in this report. In 19 of these waters there is no carbonate, 

and in the remaining 11 the average carbonate value is only onefifth of the bicarbonate value. Three of these 11 ; waters may be 

disregarded, for the carbonate reported probably formed during the 

time the samples had stood before being analyzed. It is perhaps 

noteworthy that of the remaining 8j in which carbonate and bicarbonate exist together, 3 are surface waters and shallow ground water, 

and 5 are deep waters, either from or below the oil measures. Apparently in the zone directly above the oil, in which the carbonate waters 

are believed to have formed there is a sufficient excess of carbon 

dioxide to prevent the formation of normal carbonate.

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 

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 due.
46 OIL-FIELD WATERS °IN SAN JOAQUIN VALLEY, CAL.

Many waters from the Eastside Coalinga field carry considerable 

amounts of sulphide, which is reported in the industrial analyses as 

"sodium sulphide." In these analyses, however, the alkalies are 

calculated by difference, and as the amount of alkalies present is not 

definitely known, the assumption that a sufficient amount is present 

to balance all of the sulphide is unwarranted. Although some of it 

may be balanced by alkalies, it is probable that much of it is actually 

present as the acid sulphide, which implies only half as much alkali 

as the normal sulphide, and that at least some of it is merely hydrogen 

sulphide.

Sulphide in the oil-field waters of San 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 an important product. As 'hydrogen sulphide is a gas, 

it tends to rise to higher waters or to the surface, if it is free to migrate 

at all, 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 water percolates into 

the brown shale below the oil measures, as along the western edge of 

the Midway field, and there encounters small amounts of oil or gas, 

the sulphate may be partly reduced to sulphide and a sulphur water 

thus formed far below the oil zone. Some of the most pronounced 

sulphur waters in the oil fields are obtained from wells located near 

the outcrop of the oil sands, which draw their water from the strata 

below the oil. . / .

Iron and aluminum. 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 generally do not affect the chemical aspects of the 

water.

In a great many natural waters much the larger part of the "iron 

oxide and alumina" reported is iron oxide, and the amount of 

alumina is very small. In a few of the analyses given in this report 

the two have been separately determined, and in these oil-field waters 

the reverse seems to be more generally true. The iron is usually very 

low, although it varies widely. It seems probable that the low content of iron is due to the fact that in the presence of hydrogen sulphide 

it has reverted from the colloidal state and formed iron sulphide, 

which being only slightly soluble has been mostly precipitated. On 

the other hand, the unusually large amounts of iron sometimes found 

are probably derived through the corrosion of the iron casing of 

wells, and some of this iron may be present not as colloid but in true 

solution.
CLASSIFICATION OF THE OIL-FIELD WATERS. 47

Silica. 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 primary alkaline waters it may enter 

the solution as silicate, but probably soon breaks down into the 

colloidal form (Si02 ). It varies greatly in amount in the oil-field 

waters, but averages higher in primary alkaline waters than in brine.

Other constituents. Several mineral constituents in addition to 

those already mentioned are probably present in the oil-field waters. 

Nitrate has been sought in 27 of the samples here discussed and 

has been found in only 5, of which 4 are surface waters. A small 

quantity of boron was found in the one sample tested for it. Bromine and iodine have been detected in some of the oil-field brines, 

and the iodine was determined quantitatively in one sample. (See 

analysis 58, Table 9, p. 74.) Iodine in unusually large amounts 

in several samples of brine from the Midway and Sunset fields was 

also reported many years ago by Watts. 1

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 oil-field waters. In the surface water and shallow 

ground water of the Kern River field the content of dissolved mineral 

matter is lowest and is generally less than 200 parts per million. 

All the shallower waters examined in the fields of the west side of 

the valley contain more than 300 parts, and most of them contain 

between 1,000 and 4,000 parts. The concentration in general increases with depth; most of the deeper waters of the Kern River 

field contain between 1,500 and 4,000 parts, and those of the fields 

on the west side of the valley between 8,000 and 40,000 parts. 

Although the concentration of the various types of water is fairly 

regular, individual samples may show considerable variation.

In the tables of analyses given below the concentration is represented simply by the totals of the constituents reported except 

when 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.

Organic and volatile matter. The figure given in most industrial 

analyses under the heading' "organic and volatile" represents the 

loss in weight when the solid matter obtained on evaporation is 

heated to redness. It consists chiefly of carbon dioxide and whatever 

organic or hydrocarbon matter was present jn the water. Many of 

the primary alkaline waters that have been closely associated with 

the oil contain dissolved organic matter in the form of petroleum 

acids, which would be included in this determination. However, most

i Watts, W. L., The gas and petroleum yielding formations of the Central Valley of California: California 

State Min. Bur. Bull. 3, pp. 90-91,1874.
48 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

samples of oil-field water as submitted for analysis contain a small 

amount of oil floating on the surface, and as this oil is also included 

in the determination it is evident that the figure has no exact value. 

It has therefore been omitted from the tables of analyses published 

in this report.

CRITERIA FOR COMPARISON.

Natural waters differ widely in the chemical character of the substances dissolved in them, and several different types of water may be 

found in nearly every region. However, the different varieties tend 

to mingle and react through constant circulation, until the pure 

types may be less common than the gradations between them. 

Moreover, if the rocks differ irregularly in composition, the waters, 

whose character reflects that of the rocks with which they come in 

contact, must be similarly different. In many areas, therefore, the 

natural waters present such infinite variation in chemical composition that even though it is recognized that a certain type is normally 

characteristic of a certain locality or formation it is impossible to 

draw a definite line of demarcation.

In the oil fields of San Joaquin Valley, however, special conditions have led to the formation of very distinct types of water. As 

the transitions from one type to another occur within relatively 

short distances fairly definite zones or localities that are characterized 

by the same type of water can be established. The development of 

these distinct types has been due partly to the influence of the oil 

 and gas, and the oil-field waters therefore present contrasts that are 

lacking in the waters of most areas.

The three groups of salts most commonly dissolved in natural 

waters are chlorides, sulphates, and carbonates, and in the oil fields

there are waters which contain any one of the three almost to the 

exclusion of the others. The concentration of chloride has already 

been shown to be governed by physical conditions, such as freedom 

of circulation; and since these conditions are more or less local and 

irregular the content of chloride furnishes the least satisfactory basis 

for the comparison of waters. The relative proportion of sulphate 

and carbonate, on the other hand, is influenced by fairly definite 

chemical reactions that take place only near accumulations of oil and 

gas; hence the carbonate-sulphate ratio may serve as an indication 

of the position of the water with respect to hydrocarbons. Study of 

the carbonate-sulphate ratio in waters in a developed field, in which 

the relations of oil, gas, and water have been discovered, forms an 

excellent criterion for differentiation and a tangible basis for a system 

of classification; in an undeveloped field, on the other hand, it may be 

used as an indication of the presence or absence of hydrocarbons 

near by.
CLASSIFICATION OF THE OIL-FIELD WATERS. 49

It is often difficult, owing to the wide variations in the chemical 

character of natural waters, to distinguish without careful study 

the significant differences from the 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. The carbonate-sulphate ratio is a significant criterion, 

^ for it is apparently governed chiefly by the position of the water 

with regard to the oil; but the ratio of sodium to potassium, for 

example, is controlled by factors that are indeterminable or not 

well understood. These ratios are interesting and are valuable for 

some purposes, but they involve too much speculation to be of basic 

importance in a study of oil-field waters. Unfortunately, several 

investigators who have already undertaken the study of the California oil-field waters have deemed it unnecessary to make complete 

analyses, and have based their estimates of the position of a water 

upon such isolated criteria as the concentration of chloride, the 

ratio of magnesium to calcium, or the presence or absence of such rare 

constituents as lithium or iodide. Some of the conclusions based on 

these incomplete studies have proved erroneous, and the writer encountered considerable skepticism among the oil operators as to the 

/" practical value of chemical studies of the oil-field waters. The-more 

I complete information now available furnishes a better basis for conclusions, both as to the influence of hydrocarbon material on the 

composition of a water and also as to the genetic relations of the 

waters themselves.

J PROPOSED CLASSIFICATION.

* Since 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. For practical convenience 

it is evident that oil-field waters should be classified as far as possible 

according to their position in relation to the oil. As waters near the 

oil measures differ in composition from those nearer the surface, a 

classification based directly on the chemical character of the waters 

and indirectly on their position in relation to the oil may be made.

x) The sulphate-carbonate ratio furnishes a convenient basis for classifying waters that contain only minor amounts of chloride, but in 

most localities chloride must be taken into account. Thus, in the 

Midway field chloride may be far more prominent than sulphate in the 

shallow waters, and in the deeper waters may be present almost to

i' the exclusion of carbonate. Under these circumstances the replacement of sulphate by carbonate is less striking.

The relation of the various types becomes clearer when their origin 

is considered. The sulphate water, being the normal ground water 

60439° Bull. 653 17 4
50 OIL-FIELD WATERS IN SAN JQAQUIN VALLEY, CAL.

of the region, is typically of meteoric origin; that is, it is rain water 

that has entered the ground and dissolved some of the more soluble 

constituents of the rocks. The salt water, however, is typically of 

connate origin and represents sea water that has been entrapped and 

retained in the sediments, dissolving some of their constituents and 

losing some of its own, but in the main retaining its original composition. The connate water is relatively stationary or stagnant, but 

the meteoric water is to some extent continually descending from the 

surface and mixing with the connate water. Both types are similarly affected by constituents of the oil or gas, sulphate being removed 

and carbonate introduced, but whereas the composition of the meteoric water is entirely reversed by this process, the pure connate water, 

which contains at the start only a small proportion of sulphate, is 

much less conspicuously altered. Most waters are mixtures of connate and meteoric types, and the extent of their alteration therefore 

depends on the proportions of the mixture. Two sets .of forces are 

at work; the one leads to the mixing of two opposing types of water 

in various proportions, and the other induces in both types chemical 

changes which are similar in kind but different in degree.

This distinction between meteoric and connate waters is valuable 

in forming a conception of the genetic relations of the oil-field waters, 

but it may be well to reiterate that it canjiot be strictly applied in 

the field. (See p. 22.) Connate marine water is readily identified by 

its high content of chloride, but the connate fresh water which the 

rocks may contain can not be distinguished from meteoric water. 

Although the terms strictly represent origin, in actual practice they 

are necessarily reduced to a chemical basis and are so used in this 

report. As the reactions of a water with hydrocarbon material depend 

on its chemical character rather than on its origin, the precise genetic 

classification is chiefly of theoretic value.

An attempt has been made to present graphically the chemical relations of the oil-field waters in figure 3. In this diagram the meteoric 

water is shown as entering the rocks and percolating down toward the 

oil, undergoing a modification and finally a reversal of its chemical 

character; the connate water is shown as already existing in the 

rocks but undergoing a similar alteration as the oil is approached; 

and the two classes are shown as converging and mixing in various 

proportions. The three broad divisions of both types and their mixtures, according to their relation to the oil, may be called normal, 

modified, and altered. Normal ground water is that which contains 

a normal percentage of sulphate; this percentage is generally high, 

for this type is either pure meteoric water or a mixture in which 

meteoric water predominates. Strictly normal or unaltered connate 

water has not been encountered. The modified group, characterized 

by a percentage of sulphate lower than normal, may be either meteoric
CLASSIFICATION OF THE OIL-FIELD WATERS. 51

or connate but is generally a mixture in which meteoric water predominates. The waters of the altered group contain practically no 

sulphate; they may be either meteoric or connate, or a mixture of 

the two. Many analyses of altered waters are available, and since 

the two extremes, meteoric and connate, are well represented, three 

types of altered water may be distinguished. Altered water of meteoric origin may be called the reversed type; altered connate water may

Meteoric, 

wafer* Surface 

water

Connate^ 

water-* -

Reversed 

type

Mixed 

f-ype.

FIGURE 3. Diagram Illustrating relation of oil-field waters of the meteoric and connate types, and their 

alteration as the oil zone is approached.

be called simply brine, and altered mixtures of the two may be called 

the mixed type. This classification may be summarized as follows:

Group 1. Normal, strongly sulphate water (typically of meteoric origin). 

Group 2. Modified, less strongly sulphate water (may be either meteoric or 

connate but is commonly a mixture in which meteoric water predominates). 

Group 8. Altered, practically sulphate-free water (meteoric and connate 

waters and mixtures of the two).

Reversed (carbonate water, originally meteoric). 

Brine (chloride water, originally connate). 

Mixed (chloride-carbonate water).

This is primarily a classification of the ground waters, but for convenience surface waters may be included in the normal group. The 

normal group includes most shallow ground water, but the depth to 

which normal waters descend depends principally on the depth of 

the oil zone. Modified waters occupy the zone below the normal 

zone and include the sulphur waters often found some distance above 

the oil. The thickness of the modified zone is generally several 

hundred feet, but it is variable and no definite limits can be assigned. 

In the Westside Coalinga field the oil measures occur at the base of 

the modified zone, and the normal and modified groups are therefore
52 OIL-FIELD WATERS IN SAN" JOAQUIN VALLEY, CAL.

coincident with the "top water/' but in the Midway-Sunset fields several hundred feet of strata containing altered water intervene between the base of the modified zone and the top of the oil measures. 

All the "bottom water" or "edge water" examined is of the altered 

type, and in general this type extends for several thousand feet 

below the oil measures.

As most of these waters are mixtures of meteoric and connate 

water their degree of alteration as the oil is approached is different. 

Normal connate water would contain by reacting value about 9.2 

per cent of sulphate, so that a water of this class containing only 3 

per cent of sulphate might reasonably be referred to the modified 

group; a normal meteoric water, on the other hand, may contain 45 

per cent of sulphate, hence a water of meteoric origin containing 

only 15 pe"r cent would naturally fall in the modified group also. 

Furthermore, the composition of normal ground water is different 

in different areas, and therefore the modified and altered types 

derived from it will differ in composition.

Any limits assigned these groups evidently must be arbitrary and 

of only local value, but for the waters in the oil fields on the west 

side of San Joaquin Valley the following limits are suggested:

1. Normal group:

Secondary salinity present, sulphate high; ratio of carbonate to sulphate generally less than 1; alkaline earths may be prominent.

2. Modified group:

Chiefly of meteoric origin. Primary alkalinity present; sulphate 

salinity greater than 15 per cent of the total salinity; ratio of carbonate to sulphate generally between 1 and 15; alkaline earths generally subordinate to alkalies.

Chiefly of connate origin. Secondary salinity present; sulphate salinity 

greater than 1 per cent of the total salinity; alkaline earths generally 

less than 10 per cent of total reacting value.

3. Altered group:

Reversed type. Primary alkalinity greater than 50 per cent; sulphate

salinity less than 15 per cent of the total salinity; ratio of carbonate

to sulphate generally greater than 15; alkaline earths generally less

than 8 per cent of total reacting value. 

Brine. Secondary salinity present; sulphate salinity less than 0.5 per

cent of total salinity; alkaline earths generally between 2 and 10

per cent. 

Mixed type. Primary alkalinity less than 50 per cent; sulphate salinity

less than 1 per cent of total salinity; alkaline earths generally about

1 or 2 per cent.

These limits have been observed as far as possible in grouping the 

analyses. The groups are not mutually exclusive, however, and 

when a water falls in two groups its classification has been decided 

by comparison with the waters above and below it.
OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 53

COMPOSITION OF THE OIL-FIELD WATERS.

DESCRIPTION OP THE TYPES. 

GENERAL COMPARISON.

The analyses of the oil-field waters are discussed and the general 

characteristics of each type are pointed out in the following sections.

I Seventy-three of the analyses given represent the types of water 

found in the Coalinga, Midway, and Sunset oil fields, and these have 

been classified in Tables 1 to 11. In Tables 12 and 13 groups of 

analyses are arranged to show the variation in water from different 

depths. Table 14 contains analyses of types of water from the Kern 

River, Lost Hills, and McKittrick fields, which are introduced to 

show that the same principles apparently govern the character of

1 the waters in those localities. Although the classification is directly 

chemical it is indirectly based on the position of the water in rela-

 tion to the oil, so that the tables group waters according to their

horizon as well as according to their composition. A number of

waters have been included that differ in one particular or another

N from the average for the type, or, if they conform to the type, they

occupy an apparently anomalous position, and these exceptions are

\ explained as far as possible in the discussion. Undue stress has per-

' haps been laid on these rarer occurrences, but it has seemed desirable

to point out at this time such variations from the normal as are most

likely to be encountered.

In order to sum up the more important variations in the chemical 

J character of the waters and to show graphically their genetic relations, all the analyses given in this paper have been plotted in figure 4. 

In this diagram the two incompatible properties of waters sec-

 ondary salinity or permanent hardness and primary alkalinity 

expressed in per cent, represent the horizontal axis to the left and

right respectively of a common line. All the secondary saline waters

therefore fall in the left section of the chart and all of the primary

alkaline in the right. On the vertical axis has been plotted the

sulphate salinity ratio (per cent of rS04 in rS04 + rCl), and accordN ingly all of the sulphate-free waters associated with the oil appear

I along the base line of the chart. The approximate concentration

(total mineral solids) in parts per million of each water is shown by

symbols. 

It is believed that the properties selected to represent the axes of 

this diagram furnish the most satisfactory criteria for a broad comparison of oil-field waters. It will be noted that most of the surface 

waters, high in sulphate and in alkaline earths, fall in the upper lefthand corner of the chart. The normal ground waters of meteoric
Secondary salinity ("permanent- hardness") Primary 

70 60 SO 40 30. 20

70

+

Concentration (total 

solids) in parts per 

million.

. Less than 2,OOO

x 2,000 ro 5,000

o 5,000 fo /S.OOO

e Over I5,OOO 

Numbers refer to 

analyses in Tables I to 14-

30 

FIGUEE 4. Chart showing chemical relations of the oil-field wa
COMPOSITION OF THE OIL-FIELD WATERS. 55

origin show a somewhat lower percentage of secondary salinity but 

a fairly high proportion of sulphate, and therefore fall to the right 

of and somewhat below the surface waters. The waters closer to the 

oil measures, being lower in sulphate and higher in carbonate, fall 

still farther in the same direction, which is indicated by an arrow. In 

the lower right-hand corner of the chart are the altered waters of 

meteoric origin, forming the reversed type. In the course of their 

progressive alteration from the surface downward these meteoric 

waters therefore fall .along a line extending diagonally across the 

whole chart. Their concentration is never high, although the deeper 

waters naturally contain more dissolved mineral matter than those 

near the surface.

The alteration of the connate waters proceeds in the same direction 

but along another course. For purposes of comparison an analysis 

of ocean water (analysis 52) has been plotted, and it will be noted 

that all of the oil-field brines fall below it and somewhat to the right, 

indicating a loss of sulphate and a decrease in secondary salinity. 

Analyses 25* and 87 may be regarded as intermediate and as representing modified connate waters. The concentration of all these 

brines is fairly uniform, being close to that of sea water. As suggested by the length of the arrows, the amount of alteration undergone by the connate waters in their transition to the brine type is 

very small as compared with the almost complete reversal of composition undergone by the meteoric waters.

Between the chiefly meteoric waters and the chiefly connate fall 

the various mixtures. Only four analyses of normal and modified 

waters of distinctly mixed origin are available, but in the group of 

altered waters variously proportioned mixtures are common. Nearly 

every gradation from typical brine to the practically pure carbonate 

water represented by analysis 36 is shown. The concentration shows 

a similar gradation from more than 15,000 parts per million in the 

brines to less than 5,000 parts in waters of the reversed type.

SURFACE WATER.

Representative analyses of surface water from the Coalinga, 

Midway, and Sunset fields are shown in Table 1. Although these 

waters differ widely in some respects, all of them except No. 6 have 

certain fundamental properties in common. It will be noted that 

in all of them, except No. 6, the sulphate salinity ratio is over 80 per 

cent and that all of them are characterized by secondary salinity. 

In all of them the primary salinity is 50 per cent or less, the secondary 

salinity between 15 and 70 per cent, and the secondary alkalinity 

between 11 and 62 per cent. In other words the alkaline earths 

exceed the alkalies and sulphate is generally the predominating acid
56 OIL-FIELf) WATERS IN SAN JOAQtflN VALLEY, CAL.

radicle. The concentration ranges between 314 parts per million and 

8,790 parts.

The water of Los Gatos and Diaz creeks in the Coalinga field 

(analyses 1 and 2) is the drainage of a district in which igneous and 

metamorphic as well as sedimentary rocks outcrop. These waters 

differ from the other surface types in their higher content of alkalies 

and in the marked predominance of the magnesium value over that 

of calcium. Crocker Spring (analysis 4) in the Midway field is interesting as the most extreme secondary saline type encountered, the 

predominating dissolved salt being gypsum. (See fig. 4.) Bitterwater Creek (No. 5) is characterized by high sulphate and by an 

extremely large amount of dissolved solids, greater than that carried 

by many of the deeper waters. The Kern County Land Co. Spring 

(analysis 6), on the other hand, is characterized by a lower proportion 

of dissolved solids than any of the other waters of the west side, 

which may be due to the fact that it issues near a fault between 

granite and sedimentary rocks. Chiefly because of its low concentration it is characterized by a much higher proportion of'secondary 

alkalinity than any "of the others.

Analysis 83 (Table 14, p. 85) shows the average composition of 

Kern River on the east side of San Joaquin Valley. As this water is 

the drainage of a region underlain by granites and other resistant 

rocks it is characterized by primary alkalinity rather than secondary 

salinity, and contains a relatively low proportion of sulphate. It is 

a very dilute solution dominantly secondary alkaline in character.
COMPOSITION OF THE OIL-FIELD WATERS. 57

TABLE 1. Analyses of surf ace water from the Coalinga, Midway, and Sunset oil fields,

Gal

PROPERTIES OF REACTION IN PER CENT.

Per cent of rS04 in rSO<+rCl ..........

CONSTITUENTS IN PARTS PER MILLION.

Iron oxide (FezOs) and alumina ( Al20s) 

Sulphate ($0*)....... ................. Nitrate (N03 ). ........................

Chloride (Cl)..... ....... ..............

Bicarbonate (HC03).. . ................

Silica(Si02).............-.............

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa). ....................

Alkaline earths:

Strong acids: 

Sulphate (rS04) ...................

Nitrate (rN03 ) ....................

Chloride (rCl). .....................

Weak acids:

Bicarbonate (rHCO3 ) ..............

ANALYSIS A3 REPORTED, c

Silica..................................

l

40.8 

16.0 

0 

43.2

81.4

o!85

40 

117 

4.5 

436

75 

6255

4.4

1,116.9

o20.4

5.1 

24.5

23.1

5.3 

621.6

24.53 

7.21

5.85 

11.17 

15.99 

.26

.26

65.27

2

50.0 

38.4 

0 

11.6

95.7

0668

248 ' 

203

2,361

78 

6203

13

3,774

o25.0

10.6 

14.4

42.3

1.9

65.8

111.30

7.51 

27.28

16.10 

54.49 

3.06

.76

220.50

3

44.4 

22 

0 

33.6

86.1

} 216

92 

87

580 

Trace. 

70 

0 

433 

87

1,345

L 22.2

10.9 

16.9

28.6

4.6

.0 

16.8

4

14.4 

70.4 

0 

15.2

94.9

117

444 

107

1.393 

5 

53 

0 

335 

50

2,334

7.2

30.7 

12.1

40.2 

.1

2.1

.0

7.6

5

45.4 

48 

0 

6.6

93.4

1,409

630 

511

5,638 

Trace. 

300 

30 

475 

38

8,790

22.7

11.7 

15.6

43.6

3.1

.4 

2.9

6

19.6 

18.8 

0 

61.6

66.1

23

56 

16

47 

30 

18 

7.2 

178 

29

314.2

9.8

27.4 

12.8

9.6 

4.7

4.9

2.3

28.5

7

28.4 

43.6 

0 

28.0

90.5

( oll2

138 

66 

1.9 

538

42 

6144

12

1,053.9

/ 014.2 

\. .......

20.1 

15.7

32.6

3.4 

614.0

15.30 

4.06 

8.36 

14.04 

19.04

.11 

.69

61.00

o Reported and calculated as sodium but Includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

c In hypothetic combinations, in grains per U. S. gallon.

Coalinga field:

1. Los Qatos Creek, T. 20 S., R. 14 E. Analyst, Kern Trading & Oil Co.

2. Diaz Creek. T. 19 S., R. 14 E., sampled above junction with Los Gatos Creek. Analyst, Kern

Trading & Oil Co. 

Midway field:

3. Frazers Spring, sec. 2, T. 30 S., R. 21 E. Spring is in Santa Margarita (?) formation, but source of 

water may be affected by near-by fault. Sampled by G. S. Rogers, September, 1915, Analyst, 

S. C. Dinsmore. »

4. Crocker Spring, sec. 18, T. 31 S., R. 22 E. Spring is in shale of Monterey group. Sampled by G. S.

Rogers, September, 1915. Analyst, S. C. Dinsmore. 

Sunset field:

5. Bitterwater Creek, sec. 29, T. 11N., R. 24 W. Sampled by G. S. Rogers, September, 1915. Analyst, 

S. C. Dinsmore.

6. Kern County Land Co. Spring in west corner of San Emigdio land grant. Sampled from pipe line 

of Western Minerals Co. by G. S. Rogers, September, 1915. Analyst, S. C. Dinsmore.

7. San Emigdio Creek, San Emigdio land grant. Analyst, Standard Oil Co., June, 1910.
58 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

NORMAL GROUND WATER.

Shallow water wells. Analyses of normal ground water from shallow 

water wells in the Coalinga, Midway, and Sunset fields are given in 

Table 2. These waters, like the surface waters, show a rather wide 

range in composition. All of them except Nos. 9 and 14 are secondary 

saline waters, but the secondary salinity is generally lower than in 

the surface waters and the primary salinity higher. Chloride and 

the alkalies are somewhat higher, especially in the waters from the 

Midway field.

Analyses 8 and 9 represent shallow well waters from the Eastside 

Coalinga field. They are very similar in composition, though on 

opposite sides of the dividing line, No. 8 being slightly secondary 

saline and No. 9 showing 1.8 per cent of primary alkalinity. Analysis 

10 shows the general composition of the water in many of the shallow 

wells in the northern part of the Westside Coalinga field. Nos. 11 

and 12 are very similar to surface waters, although in No. 12 chloride 

is high. Analyses 13 and 14 represent waters from the Midway-Sunset field, both of which are characterized by high chloride. No. 14 

represents a mixed water derived from two sands, 450 feet apart, the 

deeper of which has probably contributed the small percentage of 

primary alkalinity present.

Analyses 84 and 87 (Table 14, p. 85) represent shallow ground 

waters of very different types from the Kern River and Lost Hills 

fields. No. 84 is similar to the water of Kern River, already discussed, differing from it only as the shallow ground waters of the 

west side of the valley differ from the surface waters of that region. 

No. 87 is water from a well 180 feet deep, located somewhat west of 

the axis of the Lost Hills anticline. Its properties are very close to 

those of sea water (see fig. 4, p. 54), the chief differences being a 

slight reduction in sulphate and a very small increase in carbonate. 

The concentration is exceptionally high for a shallow water, being 

over a third of that of sea water. This water is distinctly a connate 

type, and the slight alteration that it has undergone is remarkable 

in view of its proximity to the surface.

Oil wells (top water). Tables 3 and 4 contain twelve ana.yses of 

normal ground water or top water from oil wells in the Coalinga and 

Midway-Sunset fields. There is, of course, no essential difference 

between these waters and those from shallow water wells, the separation being merely one of convenience. However, most of these 

waters are deeper than those shown in Table 2, and consequently 

the primary salinity is generally higher and the secondary salinity 

and secondary alkalinity lower. The concentration is generally 

higher, and in several waters is very high.
COMPOSITION OF THE OIL-FIELD WATERS. 59

TABLE 2. Analyses of normal ground water from shallow-water wells in the Coalinga, 

Midway, and Sunset oil fields, Col.

PROPERTIES OF REACTION IN PER CENT.

Primary alkalinity. ...................

Per cent of rSO< in rS04+rCl ..........

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na) ..........................

Calcium (Ca) ..........................

Iron oxide (FesOs) and alumina (A12 03 ) 

Sulphate (804) ................. . , . . . . .

Chloride (Cl).. ........................

Bicarbonate (HC03). ..................

Silica (SiOs)... ........................

REACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths:

Strong acids: 

Sulphate (rSO*)...................

Chloride (rCl).. ....................

Weak acids: 

Carbonate (rCO3 ). . ................

ANALYSIS AS REPORTED, c

Silica..................................

8

78,0 

4.2 

.0 

17.8

88.5

o470

59 

34 

Trace. 

914 

88 

6140

44

1,749

o39.0

5.6 

5.4

36.4 

4.7

68.9

74.30 

8.48

8.56 

4.01

4.22 

Trace. 

2.56

102. 13

9

80.2 

.0 

1.8 

18.0

87.0

o457

45 

26 

7 

814 

88 

6143

61

1,641

o41.0

4.6 

4.4

35.0 

5.1

69.9

70.35 

8.50 

1.27

6.60

5.20 

.41 

3.57

95.90

10

72 

25 

0 

3

79

a981

297 

21 '48 

2,177 

423 

654

21

4,022

o36.0

12.5 

1.5

38.4 

10.1

61.5

126.49 

40.82 

.58 

55.96 

2.19 

2.96 

2.17 

1.25 

2.82

235.24

11

37.2 

43.4 

.0 

19.4

72.7

o!98

166 

75

649 180 '.' 

6134

1,402

ol8.6

18.0 

13.4

29.3 

11.0

69.7

14.56 

17.40

15.20 

13.10 

21.70

81.96

12

58.2 

37.6 

0 

4.2

43.6

o980

257 

217 

3.3

1,473 

1,399 

691

45

4,465.3

o29.1

8.7 

12.2

20.9 

27.0

62.1

11.03 

134.91 

1.20

45.78 

3.79 

57.95 

3.36 

.19

2.62

260.83

13

76.0 

12.6 

0 

11.4

26.6

o254

61 

6

166 

335 

651

26

899

38.0

10.3 

1.7

11.8 

32.5

5.7

14

87.4 

0 

3.4 

9.2

60.2

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 

4.0

o Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

c In hypothetic combinations, in grains per U. S. gallon.

Coalinga field:

8. Standard Oil Co. water well 3, sec. 28, T. 19 S., R. 15 E. Analyst, Standard Oil Co., September, 

1910.

9. Standard Oil Co. water well 2, sec. 36, T. 19 S., R. 15 E. Depth, 444 leet. Analyst, Standard 

Oil Co., February, 1913.

10. Associated Pipeline Co., shallow water well at station 1, sec. 18, T. 20 S., R. 15 E. Analyst, Smith, 

Emery & Co. Authority, Associated Oil Co.

11. Traders Oil Co. water well, sec. 24, T. 20 S., R. 14 E. Depth, 85 feet. Analyst, L. J. Stabler, 

May, 1909. Authority, Traders Oil Co.

12. California Oil & Gas Co., water well 1, sec. 6, T. 21 S., R. 15 E. Analyst, Smith Emery & Co. 

Midway and Sunset fields:

13. Western Water Co. wells in sec. 5, T. 31 S., R. 25 E. Analyst, Kern Trading & Oil Co., Jan. 1, 

1913.

14. Midway Northern Oil Co. water well, sec. 32, T. 12 N., R. 23 W. Water from sands at 350 and 

790 feet. Sampled by G. S. Rogers, August, 1914. Analyst, Chase Palmer.

Most of these waters may be readily distinguished from surface 

waters, but their distinction from the modified waters beneath 

them is less easy. As shown by figure 4, the shallower waters are
60 OIL-FIELD WATERS IN SAN JOAQUIET VALLEY, GAL.

secondary saline in character and high in sulphate, whereas those 

near the oil are primary alkaline and free from sulphate. However, 

there are many intermediate types which show primary alkalinity 

and still retain a fairly high proportion of sulphate. For convenience hi discussing the waters of the fields of the west side the 

secondary saline waters high hi sulphate have been referred to the 

normal group and those of primary alkaline character containing 

considerable sulphate to the modified group. The line of demarcation is therefore assumed to be the point at which secondary salinity 

disappears and primary alkalinity appears. As a rule this division 

is justified, for the decrease of secondary salinity is probably due as 

much to the normal increase of alkalies with depth as to actual 

decrease of sulphate. However, when sulphate is very high and the 

alkalies are proportionately less abundant than usual, the property 

of secondary salinity may be retained after some of the sulphate 

has'been removed. Analyses 21 and 26, for example, represent 

sulphur waters, the hydrogen sulphide being presumably due to 

the reduction of some of the sulphate, yet both of these waters are 

secondary saline and are therefore grouped with normal types. As 

an additional criterion of the alteration of the waters the ratio of 

carbonate to sulphate is shown hi Tables 3 to 7. It will be noted 

that in all of the analyses in Tables 3" and 4 except Nos. 19 and 21 

this ratio is less than 0.25, and that No. 21 is a sulphur water which 

has doubtless been somewhat modified. This ratio explains another 

apparent inconsistency in Table 3, namely, the inclusion of No. 17, 

a primary alkaline water, with the normal secondary saline waters. 

In this water the sulphate is extremely 'high in comparison with 

both chloride and carbonate and the appearance of primary alkalinity 

is due rather to the abnormally low proportion of alkaline earths than 

to any loss of sulphate. As already stated, no single property or 

constituent of a natural water can be a universal criterion of its 

relation to the oil.

Analyses 15 and 16 represent the ordinary top water in the 

northern part of the Eastside Coalinga field. The exact position of 

these waters is not known, but from the higher primary salinity and 

concentration of No. 16 it is thought to be somewhat the deeper of 

the two. No. 18, from the Westside Coalinga field, is a water very 

similar in composition to the last but of exceptionally high concentration. It is a sulphur water and therefore has probably been 

slightly influenced by the hydrocarbons, though the proportion of 

sulphate as compared with both carbonate and chloride is still very 

high. No. 19 represents an unusual top water whose exact horizon 

is unknown. Its concentration is very much lower than that of 

most waters of the west side and therefore the sparingly soluble bicarbonates of calcium and magnesium, though present in small actual
COMPOSITION OF THE OIL-FIELD WATERS. 61

amount, constitute an unusually high percentage of the total solids. 

The alkalies are exceptionally low, though chloride predominates 

over sulphate. No. 21 is somewhat similar in character to the last. 

In the locality from which this water was obtained the oil measures 

are only 650 feet below the surface and the water 304 feet. The 

water is essentially a shallow type and yet has undergone some 

alteration, as evidenced by the higher ratio of carbonate to sulphate 

and by the presence of hydrogen sulphide. No. 20 is somewhat 

similar to No. 21 but more nearly resembles the types represented 

by the preceding analyses. Analyses 22 and 24 represent very 

similar top waters, both being pronounced secondary saline types. 

No. 23 is a water characterized by a small percentage of primary 

alkalinity, but it is included here because of its very low carbonatesulphate ratio and its very high sulphate salinity ratio.

Analysis 25 represents a water encountered at a depth of 670 feet 

in Midway Valley. This water is very similar in composition to No. 

87, discussed above, and represents as near an approach to normal 

connate water as can be expected. Its reactive properties resemble 

those of sea water (see analysis 52, Table 8, p. 73), though the 

secondary salinity is rather low. The sulphate salinity ratio is about 

that of sea water and therefore much lower than in the shallow 

meteoric types. The carbonate-sulphate ratio is about normal for 

either the meteoric or the connate type. The concentration is almost 

three-fourths that of sea water. It is noteworthy that this water 

occurs in that part of the McKittrick formation correlated with the 

Tulare formation, which consists of deposits laid down in fresh water 

and which probably has never been submerged beneath' the sea. 

Assuming that the sample was correctly taken, this water therefore 

presumably represents sea water that was originally entrapped in 

the marine strata below, and that has since migrated to the higher 

beds. Such an ascent would indicate considerable artesian pressure 

and would imply that the escape of the deeper waters by migration 

along the lines of stratification is practically cut off. If this explanation is correct it throws light on the completeness with which the 

connate water is trapped in the Midway syncline.

Analysis 26 represents sulphur water from a well drilled near the 

outcrop of the oil measures which probably penetrates the shale of 

the Monterey group. The presence of hydrogen sulphide and also 

the somewhat high carbonate-sulphate ratio indicate that this water 

has been slightly modified, but it is included here because of its 

secondary salinity. Owing to the proximity of the outcrop of the 

sand there has been a considerable admixture of meteoric (sulphate) 

water, and chloride is not so high as in the waters farther east. 

Several other wells drilled in the brown shale just west of the western 

edge of the Midway field have obtained similar sulphur water, but,
62 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

as already explained (p. 46), the presence of small amounts of oil or 

gas in this formation may lead to the development of a modified type ' 

of water some distance stratigraphically below the oil measures. 

TABLE 3. Analyses of normal ground water ("top water' ')from oil wells in the Coalinga

oilfield, Cat.

PROPERTIES OF REACTION IN PERCENT.

Primary salinity. .....................

Secondary alkalinity.... ..............

Per cent of rS04 in rS04+rCI .........

Ratio of rC03+rHC03 to rSO4 . . ......

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na)o and potassium (K) .... 

Calcium (Ca).........................

Magnesium (Mg) .....................

Iron oxide (FeaO3) and alumina ( A1203) 

Sulphate (S04 ) .......................

Chloride (01).........................

Carbonate (COs)...... ...............:

Bicarbonate (HC03)..................

Silica (SiOa)..........................

Hydrogen sulp'hide (HjS) ............

REACTING VALUES, IN PER CENT.

Alkalies: 

Sodium (rNa)o. ..................

Pntq,ssl»m (rK),, ,..,

Alkaline earths:

Magnesium (rMg). ...............

Strong acids: 

Sulphate (rS04 ) ..................

Chloride (rCl). . ...................

Weak acids: 

Carbonate (rC03 ). . ...............

Bicarbonate (rHCO3 ). . ...........

ANALYSIS AS REPORTED, c

Sodium carbonate ....................

Magnesium carbonate. ................

Iron oxide and alumina... . ...........

Silica.................................

Hydrogen sulphide. . .................

15

74.2 

14.6 

0 

11.2

86.9 

.15

596 

163 

9 

102 

1.276 

140 

6117

3

2,406 

14

37.1

11.8 

1.1

38.6 

5.8

65.6

88.82 

13.47 

.46 

20.19 

8.96 

.35 

1.65 

5.97 

.19

140.06 

.82

16

85.4 

6.6 

0 

8.0

95.0 

.09

1,111 

,83 

51 

27 

2,376 

91 

6135

441

4,315

42.7

3.6 

3.7

43.7 

2.3

64.0

187. 46 

8.75 

1.55 

7.42 

6.63 

8.64 

4.29 

1.59 

25.78

252.11

17

82.4 

0 

12.0 

5.6

95.4 

.22

1,760 

22 . 

42 

62 

3,058 

109 

6427

6.7

5,486.7 

.0

47.2

.7 

2.1

39.3 

1.9

68.8

258.46 

10.49 

34.33

""3." 23" 

4.98 

5.05 

3.64 

.39

320.57 

.00

18

82.4 

9.4 

0 

8.2

95.0 

.09

3,285 

385 

142 

1 

7.264 

296 

6419

49

11,841 

Present.

41.2

5.5 

3.3

43.5 

2.4

64.1

557.32 

28.57

28.33 

35.39 

34.66 

4.56 

.06 

2.86

691. 75 

Present.

19

11 

51 

0 

38

38.7 

1.58

40 

105 

107

185 

212 . 

0 

364 

29

857

} 5.5

16.5 

28

12 

19

0 

19

.........

20

66 

30 

0 

4

70 

.06

641 

209 

47 

6 

1,365 

427 

649

7

2,751 

.0

f 33.0

12.4 

4.6

33.7 

14.3

52.0

65.54 

41.18

41.41

7.83 

4.06 

.35 

.38

160.75 

.00

21

35.6 

39.0 

0 

25.4

78.5 

.43

521 

265 

336 

0 

1,789 

360 

6484

40

3,795 

Present.

17.8

10.5 

21.7

29.3 

8.0

6 12..'

42.05 

34.72 

7.16 

10.40 

31.09 

86.12 

7.82 

.00 

2.34

221.70 

Present.

o Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

c In hypothetic combinations, in grains per \J. S. gallon.

15. California Oilfields (Ltd.) well 2, sec. 10, T. 19 S., R. 15 E. Analyst, Smith, Emery & Co., October, 

1915. Authority, California Oilfields (Ltd.|.

16. California Oilfields (Ltd.) well 16, sec. 14, T. 19 S., R. 15 E. Analyst, Smith, Emery & Co., September, 1915. Authority, California Oilfields (Ltd.).

17. Record Oil Co. well 5, sec. 22, T. 19 S., R. 15 E. Water from above oil zone. Analyst, Smith 

Emery & Co., October, 1915.

18. Premier Oil Co. well 3, sec. 24, T. 20 S., R. 14 E. Black sulphur water from about 700 feet, or 

about 400 feet above the oil. Analyst, Schalk Chemical Co. Authority, Premier Oil Co.

19. Kern Trading & Oil Co. well in sec. 13, T. 20 S., R. 14 E. Sampled by G. S. Rogers, October, 

1915. Analyst, S. C. Dlnsmore.

20. Nevada Petroleum Co. well 3, sec. 30, T. 20 S., R. 15 E. Flowing water from about 2,100 feet, or 

about 500 feet above the oil. Analyst, Dodge Manfacturing Co., March, 1911. Authority, Nevada 

Petroleum Co.

21. Ozark Oil Co. well 3, sec. 26, T. 20 S., R. 14 E. Sulphur water from 304 feet, or about 350 feet 

above oil. Analyst, Smith, Emery & Co., January, 1912, Authority, Ozark Oil Co.
COMPOSITION OF THE OIL-FIELD WATERS. 63

TABLE 4. Analyses of normal ground water ("top water") from wells in the Coalinga

and Midway oil fields, Cal.

PROPERTIES OF REACTION IN PER CENT.

Primary salinity... . .................................

Per cent of rSCh in rSO<+rCl ...................... 1 .

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na).. ......................................

Sulphate (S0<)-. ....................................

Chloride (Cl)... ......................................

Silica(Si03)...................-.......- .............

REACTING. VALUES IN PER CENT.

Alkalies:

Alkaline earths:

Strong acids:

Chloride (rCl) . ...... ............................

Weak acids:

Bicarbonate (rHCOs). . ..........................

ANALYSIS AS REPORTED. c

Silica................................................

22

59.2

28.4

0

12.4

77.7

.18

a 442

140

76

639

1,062

226

6121

2,106

o29.6

10.7

9.7

34.0

9.8

66.2

53.33

21.74

14.84

9.47

19.44

1.92

2.27

123.01

23

92.4

0

2.0

5.6

92.4

.09

"1,335

34

22

2,518

154

6141

17

4,221

o47.2

1.4

1.4

49 7

3.5

63.8

917 7f>

14.83

3.59

5.00

4.48

.98

246. 58

24

53.8

35.6

0

10.6

78.3

.15

066!

249

148

6105

1,793

368

6169

3,493

o26.9

11.6

11.5

35.0

9.7

65.3

76.10

35.46

33.01

12.07

37.62

3.67

6.12

204.05

25

94.0

5.4

0

.6

7.0

.08

o8,794

397

61

62.4

1,381

13,304

671

45

24,055.4

o47.0

2.4

.6

3.5

46.2

6.3

25.95

1, 282. 50

69.42

6.92

17.75

.14

2.65

1,405.33

26

90.2

3.4

0

6.4

30.6

.22

8.4

23

39

605

1,013

0

175

32

2,717.4

44.7

.4

1.3

3.6

14 .

32 '

.0

3.2

o Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

«In hypothetic combinations, in grains per U.S. gallon.

Coalinga field:

22, 23, and 24. Kern Trading & Oil Co. wells in sec. 25, T. 20 8., R. 14 E. Nos. 22 and 23 represent 

water which corroded the casing and temporarily flooded the wells. The water certainly occurs 

above the oil and probably more than 500 feet above it. No. 24 represents water from a depth 

of 648 feet, or just above the zone of tar sands and 480 feet above the oil. Analyst, Kern Trading 

& Oil Co.

Midway field:

25. Standard Oil Co. well 6, sec. 12, T. 32 S., R. 23 E. Water is from 670 to 730 feet, or about 2,000 

feet above the horizon of the oil. Analyst, Standard Oil Co. January, 1912.

26. August Water Co., California Amalgamated well 2, sec. 35, T. 32 S., R. 23 E. Sulphur water from 

1,090 feet, probably in shale of Monterey group. Temperature, 84° F. (Seep. 19.) Sampled 

by G. S. Rogers, July, 1914. Analyst, Chase Palmer.
64 OIL-FIELD WATERS IN- SAN JOAQUIN VALLEY, CAL. 

MODIFIED GEOUND WATER.

Table 5 contains analyses of water, modified presumably by the 

action of the hydrocarbons, from the Coalinga, Midway, and Sunset 

fields. As already explained, the modified group is arbitrarily 

assumed to include only those waters that are primary alkaline in 

character and that contain a moderate to high proportion of sulphate. 

In all the analyses included in Table 5 the ratio of carbonate to sulphate is greater than 1, and in several it is much higher. Most of 

these waters are characterized by a high percentage of primary 

alkalinity, but this figure is^ largely governed by the concentration 

of the chloride.'

Analysis 27 represents the type of water tnat occurs in the Eastside 

Coalinga field some distance above the oil. It will be noted that the 

primary salinity is very low and primary alkalinity very high. The 

sulphate salinity ratio is fairly high, but this is due chiefly to the very 

small proportion of chloride present. When chloride is as low as it 

is in most of the waters from this district the relative proportions of 

sulphate and chloride are of less value than the comparison of sulphate and carbonate. Analysis 28 shows a somewhat saltier water 

from the north end of the Coalinga syncline. The primary alkalinity 

is fairly high though the water still contains a large amount of sulphate. No. 29 is a good analysis of the distinctly modified water 

that occurs just above the tar sand zone in the Westside Coalinga 

field. Despite the high sulphate salinity ratio and the low carbonatesulphate ratio the fact that some of- the sulphate has already been 

reduced is indicated by the presence of a considerable amount of 

sulphide, part of which is combined as hydrogen sulphide. Analysis 

30 represents the water used at the Coalinga Sulphur Baths, which 

is interesting because, although distinctly a modified type, it occurs 

600 feet below the oil. This water, however, is probably obtained 

from the Chico strata (Upper Cretaceous*) and is very different from 

that obtained in or just below the oil zone (upper Miocene), which 

is represented by analysis 64 (Table 10, p. 76).

Analysis 31 probably represents a mixture of waters above and 

below the oil from a well on the extreme western edge of the Midway 

field. The sulphate is high in proportion to both chloride and 

carbonate, indicating a considerable admixture of upper water. It 

is also possible, because of the proximity of the outcrop of the sands 

and the fact that large quantities of water are being removed from 

them, that sulphate water is entering at the outcrop of the lower water 

sand faster than it is being altered. Analysis 32 represents an 

unusual type of water from Buena Vista Valley. Although occurring

1 Arnold, Kalph, and Anderson, Robert, Geology and oil resources of the Coalinga district, Cal.: U.S. 

Oeol. Survey Bull. 398, p. 223,1910.
-i

COMPOSITION OP THE OIL-FIELD WATERS. 65

at a depth of about 3,000 feet-its concentration is only 364 parts, 

which is less than that of even the shallowest ground water in most 

localities in the fields of the west side. No oil had been encountered 

at this depth, and if present is probably some distance below. The 

low carbonate-sulphate ratio shown by the analysis indicates a water 

only slightly modified, if at all, though as no shallower water from this 

locality is available for comparison a definite estimate of its relations 

can not be made. No. 33 is a much saltier and more concentrated 

water than any of the foregoing and is included here for purposes of 

comparison. This water has been greatly modified and closely 

approaches the altered water associated with the oil along the western 

edge of the Midway and Sunset fields. (See Table 11, p. 77.) The 

presence of hydrogen sulphide and the appreciable amount of sulphate 

still retained prevent its classification as an altered water, especially

as it occurs at least a hundred feet above the oil. A similar type is 

shown by analysis 81 (Table 13, p. 83).

Analysis 80 (Table 12, p. 81) represents a meteoric water of the 

modified type similar in every way to those discussed above but 

formed under very different conditions. This water is the mine water 

at the old coal mine in sec. 26, T. 30 S., R. 14 E. It probably has 

not been affected by oil or gas and its modification must therefore 

be due to the coal.

60439° Bull. 653 17 5
66 OIL-FIELD WATEES IN SA-N JOAQUIN VALLEY, CAL.

TABLE 5. Analyses of ground water modified byaction of oil, from wells in the Coalinga, 

Midway, and Sunset oil fields, Cal.

PEOPEETIES OF REACTION IN PEE CENT.

Primary salinity. ......................

Primary alkalinity. ...................

Ratio of rS04 to rS04+rCl. ............

CONSTITUENTS IN PAETS PEE MILLION.

Sodium (Na) . .........................

Potassium ( K) ........................

Calcium (Ca) ..........................

Iron (Fe).. ............................

Sulphate (SO4) ........................

Chloride (Cl) ..........................

Bicarbonate (HC03 )......-............

Sulphide (S)... . .......................

Silica (Si08)...........................

EEACTING VALUES IN PEE CENT.

Alkalies:

Potassium (rK).... . ...............

Alkaline earths:

Strong acids:

Chloride (rCl).... . .................

Weak acids:

Sulphide (rS).. ....................

ANALYSIS AS EEPOETED.d

Silica..................................

27

14.0

0

82.6

3 4

75.7

7.5

01,003

17

g

\ &4.8

971

54

cl,067

52

an

2, 497. 8

.9

.8

* <t

1.7

C39.5

3 ^

ia 41

5 OK

106. 45

7 34

i nn

1.80

.39

1.48

.28

145.89

28

49.0

0

- 47.4

3.6

43.7

2.4

o807

26

377

354

c555

2,119

1.8

10.7

13.8

c25.5

32.60

CO Af\

3.74

123.88

29

di d

0

22.4

09 9

67.4

1.6

VfW

21

194

104

f Trace.

679

241

0

1,36641

Q7

2,690

97

33.3

.6

6.8

9.3

15.3

7.4

0

24.3

3.0

30

20.2

0

74.2

5.6

25.7

15.3

460

10

19

2.6

Trace.

53

113

0

1,037

34

1,202.6

47.1

.1

2.3

.5

2.6

7.5

0

39.9

31

44.6

0

39.0

16.4

58.3

2

1

618

33

31

45

Trace."

. i 

403

210

160

693

115

1, 959. 1

40.5

1.3

2.4

5.8

13.0

. 9.3

8.3

19.4

32

56.6

0

11.0

32.4

64.0

1.2

a93

26 .

. 8

| 64.8

103

43

c77

9.6

364.4

o33.8

10.7

5.5

18.1

10.2

C21.7

8.91

4.17

2.03

3.74

1.59

.28

.56

21.28

33

77.4

0

15.6

7.0

1.2

22.6

4,969

102

109

144

109

6,740

0

3,623

67

14,025 

1.3

46.0

.5

1.1

2.4

.5

38.2

0

11.3

o Reported and calculated as sodium but includes potassium.

c Reported and calculated as carbonate but probably in part bicarbonate. 

d In hypothetic combinations, in grains per U.S. gallon.

Coalinga field:

27. California Oilfields (Ltd.) well 16, sec. 26, T. 19 S. , R. 15 E. Waterf rom 2,415 to 2,450 feet (above the 

oil). Analyst, Smith, Emery & Co., November, 1915. Authority, California Oilfields (Ltd.).

28. Union Oil Co. well La Vista 4. sec. 4, T. 20 S., R. 15 E. Water from 3,191 feet, or about 400 feet 

above first show of oil reported. Analyst, E. H. Miller, April, 1911. Authority, Union Oil Co.

29. Coalinga Homestake water well, sec. 26, T. 20 S., R. 14 E. Sulphur water from 336 to 354 feet, 

or at top of tar sand zone and 200 to 300 feet above the oil. Sampled by G. S. Rogers, October, 

1915. Analyst, S. C. Dinsmore.

30. Santa Rosa Oil & Development Co. water well, sec. 12, T. 21 S., R. 14 E. Sulphur water from 

2,077 feet, or about 600 feet below the oil. Temperature, 118* F. Sampled by G. S. Rogers, 

October, 1915. Analyst, S. C. Dinsmore. 

Midway and Sunset fields:

31. Stratton Water Co. well 3, sec. 7, T. 32 S., R. 23 E. Probably a mixture of waters from above 

and below the oil. Temperature, 90° F. Sampled by G. S. Rogers, August, 1914. Analyst, 

S. C. Dinsmore. 32. Midway BasinOilCo.wellinsec.28,T.3lS.,R.24E. Water from 2,980 feet. No oil encountered, 

though possibly present at greater depth. Analyst. Standard Oil Co., November, 1910.

33. Union Oil Co. water well Diamond 2, sec. 13, T. 11 N.. R. 24 W. Sulphur water from about 650 

feet, or about 100 feet above the oil. Sampled by G. S. Rogers, September, 1915. Analyst, S. C. 

Dinsmore.
- COMPOSITION OF THE OIL-FIELD WATERS. 67 

ALTEEED GEOUND WATEE.

Reversed type. When a pure sulphate water is altered by the 

action of hydrocarbons it apparently becomes a pure carbonate 

water, a reversal from complete salinity to complete alkalinity 

taking place. However, there are few waters anywhere that do not 

contain some chloride, and in oil fields, where the- underground circulation is normally restricted, a large concentration of chloride is 

generally found. It is probable therefore that oil-field waters of the 

reversed type, in which chloride is practically lacking, are rare, and 

so far as the writer knows the only fields in which they c'onstitute 

the rule rather than the exception are the Eastside Coalinga and possibly the Kern Kiver fields. (See p. 85.) Tables 6 and 7 show analyses 

of this type of water. The type is characterized by low primary 

salinity and high primary alkalinity, by a moderately low concentration, and by a high ratio of carbonate to sulphate. Owing to 

the small amount of chloride present the sulphate salinity ratio 

(per cent of rS04 in rS04 +rCl) is much higher than in most altered 

waters, though generally below 10 per cent. In some waters, however, the actual amount of sulphate seems to be abnormally large 

for a water associated with the oil, and it is possible that in some 

localities sulphate water is entering at the outcrop and percolating 

down faster than it is being altered.

All the analyses in Table 6 and four of those in Table 7 represent 

water from the Coalinga field. No. 34 is a sulphur water which 

occurs a short distance above the oil measures at the upper end of 

the Coalinga syncline. Circulation is doubtless restricted in this 

locality and a considerable proportion of chloride has been retained. 

The primary salinity is 35 per cent and the primary alkalinity only 

52 per cent, and the water is therefore a mixed type, approaching 

that shown in Table 10, but characterized by a lower concentration. 

The presence of hydrogen sulphide together with a small amount of 

sulphate indicates that the alteration of this water is not entirely 

complete. Analyses 37, 38, and 39 represent waters from the 

deep territory on the east side of the Coalinga anticline near its 

southern end. These waters resemble 34 in that a considerable 

proportion of chloride is present, indicating an admixture of connate 

water. The properties of these waters are very similar, and all of 

them are characterized by a high proportion of carbonate as compared 

with either chloride or sulphate. However, a rather large amount 

of sulphate is present, especially in No. 39, which may be the normal 

condition or which may be due to an admixture of upper water in 

the samples analyzed. It may also indicate that these waters occur 

above the oil measures instead of in or below them, as generally 

believed. Analysis 42, which is very similar to these, represents
68 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

a water definitely reported to occur at 4,022 feet, or near the base 

of the main oil measures. It will be noted that this analysis shows 

only about half as much sulphate as analyses 37, 38, and 39.

Analyses 35, 36, and 40 contain an even lower proportion of 

chloride than analysis 42 and represent the extreme of the reversed 

type. These waters occur on the east flank of the anticline, farther 

north and in shallower territory than those discussed above. Apparently in this locality the connate water has been entirely drained 

away and replaced by meteoric water. In Nos. 36 and 40 primary 

salinity is only 1.4 per cent, and these waters are therefore practically 

pure solutions of sodium carbonate. No. 36 contains no sulphate 

whatever, but a small amount of the hydrogen sulphide formed by 

the reduction of the sulphate that it formerly contained is still 

present. In Nos. 35 and 40 the sulphate seems high when compared with the chloride, but is negligible in comparison with the 

carbonate. Analysis 41 represents a water similar to No. 40, but 

characterized by higher salinity, both chloride and sulphate. Sulphate is relatively high, and the presence of hydrogen sulphide presumably indicates that alteration is not complete.

Analysis 43 represents a water similar to No. 41, but occurring 

under very different conditions in the Westside Coalinga field 

This water was obtained from a well drilled to a depth of only 410 feet 

(probably in the brown shale, Oligocene ?) a mile west of the developed 

oil field. The strata dip steeply in this locality and the water sand 

outcrops not far west of the well. The occurrence of an almost 

completely altered water so close to the surface is very unusual, but 

it is known that small quantities of oil or gas are disseminated 

through the formation, and there is said to be an oil seep within a 

mile of the well. Furthermore, only a very small supply of this 

water was found and the action of reducing agents would therefore 

have been localized. Ordinarily, however, the water obtained from 

the brown shale in similar relative locations is only partly modified.

Analyses 44 and 45 represent waters of the reversed type from the 

northern part of the Midway field. No. 44 was obtained from a 

depth of 3,860 feet or probably several thousand feet below the 

main oil measures, but it is reported that a "stray" oil sand was 

found just below the water. It is said that the production of this 

well increases perceptibly after the rains, which is not inconsistent 

with the fact that the water is chiefly of meteoric origin. No. 45 is 

a similar type of water, though it contains an even smaller proportion of chloride and is less concentrated. It occurs above the oil 

measures and probably in the zone of tar sands. These waters are very 

different from those found 2 miles to the southeast and described in 

the following section.
COMPOSITION OP THE OIL-FIELD WATEES. 69

Analysis 85 (Table 14, p. 85) shows a similar water from the Kern 

~River field. It resembles the waters of the west side very closely, 

although its concentration is lower and its secondary alkalinity is 

somewhat higher.

TABLE 6. Analysis of essentially meteoric water altered by action of oil (reversed type), 

from oil wells in the Coalinga oilfields, Cal.

PROPERTIES OF REACTION IN PER CENT.

Secondary salinity. .......................

Eatio of rCOa+rHCOs to rS04 . ............

CONSTITUENTS IN PARTS PER MILLION.

Calcium (Ca). . ............................

Magnesium (Mg) ..........................

Sulphate (S04). ...........................

Chloride (Cl). .............................

Carbonate (C0s)6 .........................

Silica(SiOa)...............................

Hydrogen sulphide (HS S) .................

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa) and potassium (rK> . . . 

Alkaline earths: 

Calcium (rCa). ........................

Magnesium (rMg) .....................

Strong acids: 

Sulphate (rSO<). ......................

Chloride (rCl).........................

Weak acids: 

Carbonate (rCOs)6. ....................

ANALYSIS AS REPORTED. c

Sodium sulphate. .........................

Silica......................................

34

34.8

0

51.8

13.4

2.8

65.2

799

62

28

15

22

480

784

86

2,276 

26

43.3 

3.8

2.9

.5

16.9

32.6

1.89

46.21

64.18

9 05

1 74

.85

<; n>;

132. 97 

1.52

35

4.6

0

75.8

19.6

4.4

477

1,123

60

109

38

8

95

1,737

69

3,239 

0

40.2 

2.4

7.4

.1

2.2

47.7

150. 95

.48

8 QQ

.15

7.45

15.52

2.22

4.05

189.21 

.00

36

1.4

0

94.4

4.2

0

00

1,458

22

22

3.4

0

32

1,953 .

41

3,531.4 

6.3

47.9 

.8

1.3

.0

.7

49.3

2.03

193.69

.55

2.79

.43

4.07

.19

2.45

206.20 

.37

37

28.6

0

69.4

2.0

10.5

23.8

3,699

13

37

4.8

238

1,494

3,514

53

9,052.8

49.0 

.2

.8

1.5

12.8

35.7

20.61

143. 97

351. 42

1.91

7.56

.28

3.07

528.82

38

30.6

0

68.6

.8

9.2

24.8

3,968

6.3

16

1.5

228

1,700

3,634

29

9,582.8

49.6 

.1

.3

1.4

13.9

34.7

19.68

163.86

370.29

V

.92

3.26

.09

1.72

559. 82

39

34.4

0

59.2

6.4

13:4

14.3

2,610

122

21

262

1,280

2,382

37

6,714

46.8 

2.5

.7

2.3

14.9

32.8

21.39

123. 43

222.96

.40

17.46

.73

3.70

2.18

392.25

o Reported and calculated as sodium but includes potassium.

6 Reported and calculated as carbonate but probably in part bicarbonate.

c In hypothetic combinations, in grains per U. S. gallon.

34. California Oilfields (Ltd.) well 5, sec. 29, T. 19 S.. R. 15 E. Sulphur water from 2,655 feet, or a short 

distance above oil zone. Analyst, Standard Oil Co., October, 1915.

35. California Oilfields (Ltd*) well 37, sec. 27, T. 19 S., R. 15 E. Analyst, Smith, Emery & Co., October, 

1915. Authority, California Oilfields (Ltd.).

36. California Oilfields (Ltd.) well 15, sec. 34. T. 19 S., R. 15 E. Analyst, Smith, Emery & Co., November, 

1915. Authority, California Oilfields (Ltd.).

37,38,39. Water from oil wells in sees. 35 and 36, T. 19 S.,R. 15 E., and sec. 2, T. 20 S.,R. 15 E., respectively. 

This water is thought by most of the operators to occur at the base of the main oil zone; it is certainly closely associated with the oil. Analyst, Kern Trading & Oil Co.
70 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

TABLE 7. Analyses of essentially meteoric water altered by action of oil (reversed type), 

from wells in the Coalinga and Midway oilfields, Cal.

PROPERTIES OF REACTION IN PER CENT.

Primary sal inity ...............'...........

Secondary Alkalinity. .....................

Per cent of rSO< in rSO4+rCl. .............

Ratio of rCOa+rHCOa to rSOi. ............

CONSTITUENTS IN PARTS PER MILLION.

Sodium (Na). .............................

Potassium (K). ...........................

Calcium (Ca). . ............................

Sulphate (S0<). . ..........................

Chloride (Cl)..............................

Carbonate (COs). ....................

Bicarbonate (HC03 ) ......................

Silica (SiOj)..... ....... ....................

Hydrogen sulphide (HaS) .................

REACTOTQ VALUES IN PER CENT.

Alkalies: 

Sodium (rNaV. . .......................

Alkaline earths: 

Calcium (rCa). ........................

Strong acids: 

Sulphate (rSO<). ......................

Chloride(rCl).........................

Weak acids: 

Carbonate (rCOs).... - .................

Bicarbonate (rHCOs).... . .............

ANALYSIS AS REPORTED.**

Sodium sulphate. .........................

Calcium sulphate.... . .....................

Silica......................................

40

1.4 

0 

88.4 

10.2

11.4 

493

ol,087

25 

50

} 63.9

4.1 

22 

cl,555

68

2.815 

14

a44.9

1.2 

3.9

.1 

.6

c49.3

.98 

145.25 

.34 

3.41 

no

.92

9.28 

.23 

3.97

164. 40 

.80

41

14.4 

0 

83.6 

2.0

36.0 

16.5

al,007

10 

6.3

61.7

111 

147 

"1,148

f9

2,450 

5

o49.0

.5 

.5

2.6 

4.6

C42.8

9.57

14.17 

115.38

Trace.

1.46

1.28 

.10 

1.13

143.09 

.29

42

33.8 

0 

64.2 

2.0

5.3 

36.8

3,295 

23 

31 

19 

( Trace.

135 

1,695 

36 

5,956 

46

8,214

48.8 

.2

.5 

.5

.9 

16.0

.4 

32.7

..........

43

27.8 

0 

69.8 

2.4

1.4 

180

o718

7.2 

5

5.8 

310 

c691 

...........

1,747

o 48. 8

.6 

.6

.2 

13.7

c36.1 o

.50

90 Q1*

69.04

1.04

1.01

.59

102. 11

44

40.2 

0

57.8 

2.0

1.5 

99

2,052 

9.7

19 

11 

Trace. 

3.1

28 

1,293 

342 

2,732

72

5,175.8

48.9 

.1

.5 

.5

.3

19.8

6.2 

23.7

..........

..........

45

22.4 

0 

60.4 

17.2

Trace.

-

ol,010

56 

77

Trace. 

421 

c 1,236

Trace.

2,800 

Present.

o41.4

2.6 

6.C

11.2

c38.8

o Reported and calculated as sodium but includes potassium.

Reported and calculated as carbonate but probably in part bicarbonate. 

<* In hypothetic combinations, in grains per U.S. gallon.

Coalinga field:

40. California Oilfields (Ltd.) well 1, sec. 34, T. 19 S., R. 15 E. Analyst, Smith,.Emery & Co., November, 1915. Authority, California Oilfields (Ltd.).

41. California Oilfields (Ltd.) well 31, sec. 34, T. 19 S., R. 15 E. Water from about 2,156 feet, or a 

short distance above main oil zone. Analyst, Smith, Emery & Co. , November, 1915. Authority, 

California Oilfields (Ltd.).

42. Kern Trading & Oil Co. well, in sec. 11,T.20 S.,R. 15E. Water from 4,022 feet ornearbaseof 

lower oil zone. Sampled by G. S. Rogers, October, 1915. Analyst. S. C. Dinsmore.

43. Kern Trading & Oil Co. water well 1, sec. 15, T. 20 S., R. 14 E. Water from 410 feet. Well is 

probably in brown shale (Oligocene?) and is located close to the outcrop of the water sand. 

Analyst, Kern Trading & Oil Co. 

Midway field:

44. General Petroleum Co., Carnegie water well, sec. 9, T. 31 S., R. 22 E. Water from brown shale 

at 3,860 to 3,880 feet, or probably over 3,000 feet below horizon of main oil zone. Temperature, 

131° F. Sampled by G.S.Rogers, July, 1914. Analyst. S. C. Dinsmore.

45. Potter Oil Co. well 2, sec. 15, T. 31 S., R. 22 E. Water from about 500 feet, or in tar sand zone 

and 200 to 300 feet above the oil. Analyst, Smith, Emery & Co. , May, 1915. Authority, Potter 

Oil Co. ,
COMPOSITION OF THE OIL-FIELD WATEES. 71

' Brine. In Tables 8 and 9 are shown analyses of brine, or connate

"N water, altered presumably by the action of hydrocarbons. For

convenience in discussion the term brine is here restricted to waters

that are practically sulphate-free and that are characterized by

secondary salinity. The primary salinity generally ranges upward

from about 80 per cent and the secondary salinity downward from

about 20 per cent; the concentration is generally between 25,000 and

,N 45,000 parts per million, and secondary alkalinity is therefore very

; low. The greatest actual amount of sulphate in any of the waters

shown is 34 parts per million, and owing to the large amounts of

chloride present the sulphate salinity ratio is less than 0.5 per cent.

Owing to the very small amount of both carbonate and sulphate the

ratio between them generally has little significance. To facilitate

comparison an analysis of ocean water is included in Table 8 as No. 52.

Analysis 46 represents a very exceptional water from the Coalinga

x\ field, which is exactly on the dividing line and exhibits neither

i secondary salinity nor primary alkalinity. Carbonate is low and

only a trace of sulphate is reported, so that this water is essentially

a solution of sodium chloride. The concentration is unusually low

and secondary alkalinity is present in corresponding high proportion.

A partial analysis of a deeper water from the same well showed more

i chloride and less carbonate, indicating a true (secondary * saline)

\ brine. Both these waters are said to be from the brown shale below

the oil measures. Apparently no brines have been encountered in

the main Coalinga field south of this well, though they probably

exist in the deeper unexplored portion of the syncline.

The remaining analyses in Table 8" represent brines from the 

Midway syncline and the Buena Vista anticline. All these waters 

> occur close to the oil, some a short distance above and others below. 

In all of them the sulphate salinity ratio is less than 0.1 per cent and 

two of them contain no sulphate whatsoever. In all other respects 

they closely resemble sea water, the properties of reaction varying 

within the limits stated above and the concentration ranging between 

29,000 and 39,000 parts. No. 48 is the only oil-field water that has 

come to the writer's attention in which secondary salinity is as high 

as it is in sea water.

V Table 9 contains analyses of seven brines from the Midway and 

Sunset fields. Nos. 53 and 55 to 58 are in every way similar, to those 

^ already described and are believed to be representative of the water 

associated with the oil in the central and eastern parts of these fields. 

Nos. 54 and 59 are somewhat different types, having a very much 

lower concentration than the rest. No. 54 contains an exceptionally 

j high proportion of the calcium and carbonate radicles and primary 

). v and secondary salinity are therefore unusually low. No. 59, which is
72 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

a water from a considerable depth, probably in the Vaqueros forma- » 

tion, is characterized by a lower concentration than many surface 

waters, although its properties resemble those of the other brines. 

Nos. 54 and 59 contain only minute amounts of sulphate. Analysis 

88 (Table 14) represents a brine associated with the oil in the Lost 

Hills field.
COMPOSITION OF THE OIL-FIELD WATERS. 73

TABLE 8. Analyses of brine or connate water altered by action of oil, from oil wells in 

the Coahnga and Midway oilfields, Cal., and of ocean water.

PROPERTIES OF REACTION IN PER 

CENT.

Secondary alkalinity ............

Per cent of rS04 in rSO4+rCl. ...

CONSTITUENTS IN PARTS PER 

MILLION.

Sodium (Na).. ................. .

Calcium (Ca).. ..................

Iron oxide (FejOs) and alumina 

(Al&»)... ..................... Sulphate (S04). .................

Chloride(Cl). ...................

Bicarbonate (HCO«). ............

Silica(SiOj).....................

REACTING VALUES IN PER CENT. 

Alkalies:

Potassium (rK)..... ........

Alkaline earths:

Strong acids: 

Sulphate (rS04)... ..........

Chloride(rCl)...............

Weak acids:

Bicarbonate (rHCOa) ........

ANALYSIS AS REPORTED. C

Sodium sulphate ................

Sodium chloride. . ...............

Sodium carbonate ...............

Calcium sulphate. ...............

Calcium chloride ................

Calcium carbonate. ..............

Magnesium sulphate. ............

Magnesium chloride .............

Magnesium carbonate ...........

Iron and alumina.. .............

Silica............................

46

96.2

.0

0

3.8

Trace.

o4,137 '

81 

40

32

Trace.

6,367

6218

40

10,924

Q48.1

1.0

nPr(M>o

48 1

61.9

Trace.

605.36

7.34

2.98'

9.13

Trace.

4.24

4.37

1.88

2 84

638.14

47

86.6

12.2

0

1.2

0

11,160

124

848 

425

0

20,694

48

110

102

33,578

43 0

.3

3 7

3.0

.0

49.4

.1

.5

48

75.9

22.5

0

1.6

.01

olO,522

2,894 

7.2

35

31

20,955

6293

18

34,755.2

V»37.95

19 nn

.05

.05

49.15

6.80

1,560.10

2.57

434.50

28.60

1.64

2.05

1.08

2,030.44

49

83.8

13.4

0

2.8

.06

al3,253

1,089 

685

11

18

23,553

6626

65

39,300

o41.9

4.0

4 1

48 K

61.5

1,954.36

O M

1.47

167.26

6.95

114.05

37.95

no

3

QQ

2 9Qft ftt

50

91.8

6.6

0

1.6

0

olO,704

284 

326

0

17,631

6243

12

29,200

045.9

1.4

o 7

.0

AQ 0

6.8

1,575.11 in on

41 QQ

61.88

11.24

.70

i 7n*\ R9

51 .

82.0

17.0

0

1.0

.01

11,011

156

1,188 

510

9

18,750

0

280

123

31,885

40 6

.4

5.3

3 7

TVo/»n

49.5

.0

.5

52

78.6

21.1

0

.3

9.2

10,710

390

420 

1,300

2,700

19,410

670

35,000

38.5

.8

1.8

8.9

4.6

45.2

6.2

o Reported and calculated as sodium but includes potassium. 

6 Reported and calculated as carbonate but probably in part bicarbonate, 

c In hypothetic combinations, in grains per U. S. gallon, 

Coalinga field:

46. Acorn Oil Co. well 1, sec. 2, T. 20 S., R. 14 E. Flowing water from 1,104 feet (in brown shale), or 

about 1,000 feet below main oil horizon. Temperature, 86° F. Analyst, Luckhardt & Co. 

Authority, H. W. Bell. A partial analysis by H. W. Bell of water struck in this well at 2,528 

feet shows about 7,700 parts per million of Cl and 175 parts of COs. This deeper water thus 

probably resembles No. 50 in its properties of reaction. 

Midway field:

47. Mays Consolidated Oil Co. well 6, sec. 28, T. 31 S.. R. 23 E. Flowing water from 3,000 feet, or a 

few feet beneath the oil sand. Temperature, 125° F. Sampled by G. S. Rogers, September 

1915. Analyst, S. C. Dinsmore. .

48. Standard Oil Co. well 6, sec. 22, T. 31 S., R. 23 E. Water from 2,700 feet, or in oil zone Analyst 

Standard Oil Co., September, 1915.

49. Associated Oil Co. well 2, sec. 32, T. 31 S., R. 23 E. Water from a short distance above 3,100 feet, 

or more than 100 feet above the oil. Analyst, Smith, Emery & Co. Authority, Associated Oil Co.

50. Associated Oil Co. well Pioneer Midway 7, sec. 30. T. 31 S., R. 23 E. Water probably from 2,840 

to 2,885 feet, or in the oil measures. Analyst, Smith. Emery & Co. Authority, Associated Oil Co

51. Honolulu Oil Co. well 6, sec. 10, T. 32 S., R. 24 E. Water from 2,755 feet, or close to the horizon

of the oil. Sampled by Paul Paine. Analyst, S. C. Dinsmore 

Ocean water:

52. Interpretation of the mean of 77 analyses by W. Dittmar of sea water collected by the Challenger 

expedition ( Challenger Exped. Rept., Physics and chemistry, vol. 1, p. 203,1884).
74 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

TABLE 9. Analyses of brine or connate water altered by the action of the oil, from oil wells 

in the Midway and Sunset oil fields, Cal.

PROPERTIES OF REACTION IN 

PER CENT.

Secondary salinity. .............

Per cent'of rSO< in rSO<-i-rCl. ..

CONSTITUENTS IN PARTS PER 

MILLION.

Sodium (Na)...................

Iron (Fe)................. ......

Alnm,iniim (A1)_

Sulphate (SO*) .................

Nitrate(NO3)...............-..

Chloride(Cl). ..................

Iodide (I).. .....................

Sllica(SIOj)........... .........

Carbon dioxide (CO3 ) ...........

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa)..............

Potassium (r K). ............

Alkaline earths:

Strong acids: 

Sulphate (rSO4 ). ...........

Nitrate(rNO3 ).............

Chloride (rCl).. ......... N...

Weak acids:

ANALYSIS AS REPORTED. <*

Sodium chloride. . ..............

Magnesium chlorid e. ...........

Silica...........................

/

53

84.2 

14.6 

0 

1.2

.01

ol5,015

1,895 

342

[ HI 

32

27,i02

c275

60

44,732

o42.1

6.1 

1.8

49.4 

c.6

2,226.21 

2.64 

274. 80 

26.78 

78.40 

.64 

3.50

2,612.97

54

48.6 

5.0 

0 

46.4

Trace.

ol,323

1,223

61.7 

3.6

2,254

cl,645

4.1

6,454.4

Q24.3

25.7

26.8 

c23.2

196.25 

.30 

19.92 

160.25 

...........

.24

377.06

55

84.0 

11.4 

0 

4.6

0

o9,855

1,064 

345

65 

0

17,231

c692

10

29,202

042.0

5.2 

2.8

47.7 

e2.3

1,461.20

97.36 

67 ^9

78.93 

.29 

.62

1, 705. 79

56

84.6 

13.8 

0 

1.6

.20

10,548 

72 

772 

570

{ iS

34 

0 

19,624

0 

573 

43

31,953.5 

Present.

32.1 

.2

3.5 

4.2

.1

49.1

.0

.8

..........

57

83.4 

16.2 

0 

.4

Trace.

oll,656

1,281 

443

4.3

21,415

c90

39

34,928.3

041.7

' 5.3 

3.0

49.8 

c.2

58

83.6 

16.0 

0 

.4

.0

11,176 

86 

1,100 

503

0 

45 

20,421 

29 

0 

162

33,440 

Present.

41.6 

.2

4.7 

3.5

.1

49.7

.0 

.2

..........

59

85.0 

12.6 

0 

2.4

,.48

[ 671

69 

.21

7.8 

0 

1,170

0

48 

5

1,967.8 

Present.

[ 42.5

5.0 

2.5

.2

48.6

.0 

1.2

..........

o Reported and calculated as sodium but includes potassium.

Reported and calculated as carbonate but probably in part bicarbonate. 

<* In hypothetic combinations, in grains per U.S. gallon. 

Midway field:

53. Standard Oil Co. well 7, sec. 12, T. 32 S., R. 23 E. Water from 2,600 feet, or 400 feet below a gas 

sand and about 100 feet above the oil. Analyst, Standard Oil Co., June, 1913.

54. Standard Oil Co. wells, sec. 20, T. 32 S., R. 24 E. Water from 3,250 feet, or about 200feet below 

the oil. Analyst, Standard Oil Co., February, 1911.

55. Standard Oil Co. well 1, sec. 28, T. 32 S., R. 24 E. Water from 2,390 feet, or about 400 feet above

the oil. Analyst, Standard Oil Co., August, 1909. ' 

Sunset field:

56. M. J. & M. M. Oil Co. well M. J. 6, sec. 36, T. 12 N., R. 24 W. Flowing water from 2,270 feet, or 

about 200 feet below top oil sand and above lower oil sand. Sampled by G. S. Rogers, July, 

1914. Analyst, S. C. Dinsmore.

57. Kern Trading & Oil Co. well, in NE. i sec. 31. T. 12 N., R. 23 W. Water from 2,924 feet, or about 

200 feet below horizon of top oil sand. Analyst, Kern Trading & Oil Co., January, 1915.

58. Midway Northern Oil Co. well 5, sec. 32, T. 12 N., R. 23 W. Flowing water from 2,505 feet, or 

below top oil sand and about 100 feet above second oil sand. Temperature, 115° F. Sampled 

by G. S. Rogers, August, 1914. Analyst, Chase Palmer.

59. Sunset Security Oil Co. well 1, sec. 29, T. 11 N., R. 23 W. Flowing water, probably from sands 

between 2,992 and 3,997 feet, or below several shows of oil. Sampled by G. S. Rogers, September, 

1915. Analyst, S. C. Dinsmore.
COMPOSITION OF THE OIL-FIELD WATERS. 75

Mixed type. In Tables 10 and 11 are shown analyses of waters of 

mixed meteoric and connate origin, altered presumably by the action 

of hydrocarbons. This type naturally overlaps on the two preceding, 

for few waters can be considered wholly meteoric or wholly connate, 

but it appears to have a fairly definite geographic distribution. (See 

p. 88.) The type may be defined as comprising primary alkaline 

waters that are characterized by less than 50 per cent of primary 

alkalinity and that contain practically no sulphate. Primary salinity 

usually ranges between 55 and 85 per cent and secondary alkalinity 

between 1 and 10 per cent. The concentration is intermediate 

between that of the reversed type and that of the brine, but generally 

ranges between 6,000 and 12,000 parts. (See fig. 4.)

Table 10 includes five analyses of this type of water from the Westside Coalinga field. In this locality the mixed type everywhere

occurs in or below the oil measures and constitutes the bottom water, 

but so far as is known it does not occur above them. The only exception to this statement is found in the water which in the deeper portion of the field replaces the oil in the highest oil sand, the so-called 

"upper edge water." This is represented by analysis 62 and the 

bottom water by analyses 60, 61, 63, and 64. Two of these waters 

contain no sulphate whatever, in two others it is negligible, and in 

the other it amounts to 37 parts per million. The primary alkalinity 

ranges between 23 and 42 per cent and the other properties vary 

accordingly. The concentration ranges between 4,000 and 8,000 

parts.

Analyses 65 to 73, Tables 10 and 11, represent waters of the mixed 

type in the Midway and Sunset fields. Generally speaking, these 

waters exhibit lower primary alkalinity and higher concentration 

than the Coalinga types; in other words, the mixture contains a 

somewhat larger proportion of connate water. In the Midway and 

Sunset fields this type of water is found both below and above the 

oil, No. 70, for example, occurring 700 feet above the main oil zone. 

The type is confined to the western edge of the fields or to the zone 

nearest the outcrop.

In No. 73 the sulphate amounts to 27 parts per million; in the 

remainder it is either absent entirely or present in negligible amount. 

The properties of reaction and the concentration show essential regularity within the limits defined, although Nos. 66 and 72 show lower 

primary alkalinity and higher concentration, indicating a larger proportion of connate water. Analysis 82 (p. 83) shows another example 

of this type from the Midway field.

Analysis 86 (Table 14, p. 85), represents a water of the mixed type 

encountered near the bottom of a well 5,135 feet deep in the Kern River 

field. It is similar in every way to the waters of this type from the 

fields on the west side of the valley, except that its concentration is
76 OIL-FIELD WATERS IF SAN JOAQUIN VALLEY, CAL.

somewhat lower. In parts of the McKittrick field water of the mixed 

type, whose original source is generally believed to have been below 

the oil, has flooded the oil measures. About 30 analyses of the water 

obtained from oil wells in this field have been made available for the 

writer's study. All of them are very similar and belong to the same 

type, which is represented by analysis 89 (Table 14, p. 85).

TABLE 10. Analyses of mixed meteoric and connate water altered by action of oil, from 

oil wells in the Coalinga and Midway oilfields, Cal.

\

PROPERTIES OF REACTION IN 

PER CENT.

Primary alkalinity .............

Per cent of rS04 in rSO4+rCl. . .

CONSTITUENTS IN PARTS PER 

MILLION.

Sodium (Na).. .................

Potassium ( K) .................

Iron (Fe)................. ......

Aluminum (A 1) ......... L

Sulphate (S04). ...... ..........

Chloride (Cl).... ....... ........

Carbonate (CO3 ). ...............

Silica (SIOj).... ................

Carbon dioxide. . ...............

REACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths: 

Calcium (rCa).. ............

Magnesium (rMg)

Strong acids: 

Sulphate (rS04 ) ............

Chloride (rCl)....... ........

Weak acids: 

Carbonate (rCO3 ) ...........

Bicarbonate (rHC03 ) .......

60

54.8 

0 

35.6 

9.6

0

[2,273

77 

81 

22

0 

2,119 

0 

3,013 

61

6,116

[ 45.2

1.8

3.0

0 

27.4.

0 

22.6

61

60.2 

0 

36.0 

3.8

1.0

/2,951 

I 77 

19 

53 

Trace.

37 

2,960 

192 

3,013 

119

7,891

/ 47.4 

\ -7

.3 

1.6

.3 

29.8

2.3 

17.6

62

74.4 

0 

22.8 

2.8

0

1,885 

20 

17 

18 

Trace.

0 

2,170 

120 

1,049 

75

4,822

48.3 

.3

.5 

.9

37.2

2.4 

10.4

63

56.6 

0 

42.2 

1.2

Trace.

ol,749

io 

6.3

} 62.6

0.7 

1,543 

«1, 001

33

4,345.6 

18

"49.4

.3 

.3

Trace. 

28.3

<=21.7

64

67.6 

0 

30.2 

2.2

.01

}3,315

19 

28 

( Trace.

4.9 

3,526 

0 

2,903 

68

8,390.9

[ 48.9 

.3

.8

Trace. 

33.8

0

16.2

65

74.8 

0 

24.4 

.8

0

f 3, 140 

I 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

66

83.6 

0 

11.8 

4.6

.01

a7,090

73 

135

| 613

4.5 

9,566 

c 1,588

44

18,513.5 

0

047.7

.6 

1.7

Trace. 

41.8

c8.2

Reported and calculated as sodium but includes potassium.

c Reported and calculated as carbonate but probably in part bicarbonate.

Coalinga field:

60. Section Seven Oil Co. well 5, sec. 7, T. 20 S., R. 15 E. Sampled by S. H. Hain, October, 1915. 

Analyst, S. C. Dinsmore.

61. American Petroleum Co. well 2 N, sec. 30, T. 20 S., R. 15 E. Water from 1,916 feet, or 3 feet below 

main oil. Sampled by T. J. Crumpton, August, 1912. Analyst, S. C. Dinsmore, November, 

1915.

62. American Petroleum Co. well 21, sec. 30, T. 20 S., R. 15 E. Water from a short distance above 

the producing oil sand ("upper edge water"). Sampled by T. J. Crumpton, August, 1912. 

Anafyst, S. C. Dinsmore, November, 1915.

63. Nevada Petroleum Co. well 1, sec. 20, T. 20 S., R. 15 E. Water from 3,305 feet, or about 25 feet 

below lowest oil. Analyst, Smith, Emery & Co. Authority, Nevada Petroleum Co.

64. Lucile Oil Co. wells 1 and 2, sec. 6, T. 21 S., R. 15 E. Water from sand probably in oil zone.

Sampled by G. S. Rogers, October, 1915. Analyst, S. C. Dinsmore. 

Midway field:

65. Associated Oil Co. well 1, sec. 35, T. 31 S., R. 22 E. Water from 1,495 to 1,727 feet, or about 100 

feet below lowest oil sand. Temperature, 120° F. Sampled by G. S. Rogers, July, 1914. Analyst, Chase Palmer.

66. North American Oil Consolidated Co. well 71, sec. 16, T. 32 S.. R. 23 E. Water probably from 

about 3,200 feet, or below the oil. Analyst, Smith, Emery & Co., March, 1914. Authority, 

North American Oil Consolidated Co.
COMPOSITION OF THE OIL-FIELD WATERS. 77

TABLE 11. Analyses of mixed meteoric and connate water altered by action of oil, from 

wells in the Midway and Sunset oilfields, Cal.

PROPERTIES OF REACTION IN 

PER CENT.

Per cent of rS04 in rSOi+rCl . . .

CONSTITUENTS IN PARTS PER 

MILLION.

Iron (Fe).. .....................

Sulphate (SO4) .................

Chloride (Cl).. .................

Carbonate(COa)................

Bicarbonate (HCOa). ...........

Siltca(Si08)....................

REACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths:

Strong acids: 

Sulphate (rSO4).. ..........

Chloride (rCl)... ............

Weak acids: 

Carbonate (rC08) ...........

Bicarbonate (rHC08 ) .......

67

64.0 

0 

33.2 

2.8

Trace.

} 3,921

37 

41 

,Trace.

i

3,977 

0 

3,855 

136

10,011

] 48.6

.5 

.9

tfrace. 

32.0

0

18.0

68

62.6 

0 

35.4 

2.0

.2

/3,627 

\ 30 

41 

17 

.3 

6.6 

14 

3,608 

0 

3,793 

122

9,333.9

/ 48.8 

I -2

.6 

.4

.1 

31.2

0

18.7

69

76.0 

0 

20.2 

3.8

.01

o3,595

50 

48

| 61.7

3.2 

4,370 

el, 172

47

9,286.9

o48.1

.8 

1.1

Trace. 

38.0

c!2.0

70

77.2 

0 

21.6 

1.2

.01

o5,933

29 

21

1

6 

7,125 

d,784

iii

15,015

049.4

.3 

-.3

Trace. 

38.6

ell. 4

71

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

72

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

73

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 

I .2

.8 

.6

.2 

36.9

0 

12.9

o Reported and calculated as sodium but includes potassium.

e Reported and calculated as carbonate but probably in part bicarbonate.

Midway field:

67. General Petroleum Co. water well 2, sec. 15, T. 32 S., R. 23 E. Water from 1,765 to 1,820 feet, or 

about 150 feet below the oil. Temperature,. 102° F. Sampled by G. S. .Rogers, July, 1914. 

Analyst, S. C. Dinsmore.

68. Crescius Oil Co. water well 6, sec. 25, T. 32 S., R. 23 E. Water from 1,460 feet, or about 50 feet 

below the oil. Temperature, 97° F. Sampled by G. S. Rogers, June, 1914. Analyst, S. C. 

Dinsmore.

69. Standard Oil Co. well 3, sec. 24, T. 32 S., R. 23 E. Water from 1,505 feet, or below tar sand and 

above oil sand. Temperature, 96° to 103° F. Analyst, Standard Oil Co., April, 1909.

70. Standard Oil Co. well 2, sec. 14, T. 32 S., R. 23 E. Water from 2,000 feet below a show of gas but 

about 700 feet above the oil. Analyst, Standard Oil Co., July, 1909.

71. August Water Co. well 3, sec. 31, T. 32 S., R. 24 E. Water from sands between 1,334 and 1,609 

feet, or below the oil. Temperature, 109° F. Sampled by G. S. Rogers, July, 1914. Analyst, 

S. C. Dinsmore. 

Sunset field:

72. Sunset Monarch Oil Co. well F, sec. 26, T. 12 N., R. 24 W. Flowing water from 2,540 to 2,560 feet, 

or about 125 feet below top oil sand. Temperature, 93° F. Sampled by G. S. Rogers, July, 

1914. Analyst, S. C. Dmsmore.

73. Good Roads Oil Co. well 14. sec. 12, T. 11 N., R. 24 W. Flowing water from 3,550 feet, or about 

2,500 feet below the oil. Temperature. 104° F. Sampled by G. S. Rogers, July, 1914. Analyst, 

S. C. Dinsmore.

RELATIONS OF THE TYPES.

Reference has already been made to figure 4, in which are shown 

the broader relations of the several types of water discussed above. 

The chief factors determining the character of the oil-field waters are 

the amount of alteration by the hydrocarbons that they have undergone and the proportions in which connate and meteoric waters have
78 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

entered into their composition. Broadly considered, the first factor 

is a function of the depth, but the second depends on structural conditions and is therefore a function of the geographic position. In 

figure 4 these two factors can not well be distinguished, a-nd therefore 

in the following sections several groups of analyses are presented in 

which the two lines of variation may be studied separately.

VEKTICAL RELATIONS.

Analyses 74 to 77, Table 12, represent four waters occurring in the 

southwestern corner of the Westside Coalinga field. The samples 

were collected at different times from four wells, and are therefore 

not as satisfactory as if taken from one well. However, the four 

wells are located within 1,200 feet of a central point, and as the water 

sands appear to be persistent within this area the four waters may 

be considered as occurring in the same well. Analysis 74 represents 

water from a depth of about 800 feet, and may include some water 

from a sand at 600 feet. Analysis 75 represents a water that corroded 

the casing at 1,160 feet; its exact position is not reported in the log, 

but a study of the logs of neighboring wells reveals a persistent 

water sand which would occur in this well at about 1,100 feet, and 

which is doubtless the source of this water. Analysis 76 represents 

water from a depth of 1,347 feet, or below the tar sands and about 

250 feet above the oil, and No. 77 is the "bottom water" which occurs 

25 feet below the main oil zone. It will be noted that Nos. 74 and

75 are secondary saline waters of the normal group, and that .Nos.

76 and 77 are primary alkaline waters. No. 76 may be referred to 

the modified group and No. 77 to the mixed type of the altered 

group. The sulphate salinity ratio decreases from 80 per cent in the 

highest water to 0.6 per cent in the lowest and the ratio of carbonate 

to sulphate increases from 0.05 in the highest to 90.5 in the lowest.

In order to show the relations of these waters graphically the four 

analyses have been plotted in figure 5, A, as though they represented 

waters occurring in the same well. The vertical scale shows the distance in feet between the water sands and the oil zone. On the horizontal lines representing the water sands are plotted the percentages 

of the radicles in reacting values and the concentration of the water 

in parts per 5,000, and the points thus obtained are connected by 

lines to show the variations of each constituent. A glance at the 

figure is sufficient to show that the most marked changes take place 

near the zone of tar sands or between the second and third waters; 

the two upper waters are very similar and the lowest differs from the 

third chiefly in its higher chloride. The heavy line representing 

sulphate shows the most pronounced and regular variation, decreasing from 38 per cent in the highest water to 0.2 per cent in the lowest.
COMPOSITION OF THE OIL-FIELD WATEES. 79

\ \

Per cent of constituents, m reacting values Per ceht- of coni'tifuents, in reacting values

A B

FIGUHE 5. Variation in chemical character of waters from different depths, showing alterations by 

hydrocarbons. The horizontal lines represent the horizon of the waters and on these lines are 

plotted their analyses. (See analyses 74 to 79, Table 12.) A, Four waters from neighboring oil wells 

in sec. 36, T. 20 S., R. 14 E., Coalinga field. (Note reversal of sulphate and carbonate values as the 

oil zone is approached.) B, Two waters from a well in sec. 27, T. 18 S., R. 15 E., several miles north 

of Coalinga field. (No oil was found to a depth of more than 3,700 feet, and the waters are probably unaffected by hydrocarbons. Note constancy of sulphate and carbonate values.)
80 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

The carbonate line rises from 2 per cent in the first water to 32 per 

cent in the third, and then, owing to the great increase of chloride in 

the bottom water, decreases to 18 per cent, although if the actual 

amount were plotted it would continue to increase. (See analyses 

74-77, Table 12.) Chloride increases only slightly down to the third 

water, but in the lowest shows a marked rise. The alkalies increase 

regularly with depth and the alkaline earths decrease. The concentration shows a slight rise in the second water, a fall in the third, 

and a marked rise in the fourth. The lower concentration of the third 

water is presumably due to the formation of the relatively insoluble 

carbonates of the alkaline earths, which a're precipitated. This also 

explains the loss of alkaline earths and the rise of alkalies in the third 

water; if actual amounts were plotted instead of percentages the 

earths would fall off even more abruptly, whereas the alkalies would 

show little increase. To sum up these variations, alkalies, chloride, 

carbonate, and the concentration value increase with depth, whereas 

alkaline earths and sulphate decrease. The most marked variations 

are exhibited by sulphate and carbonate, and although it happens 

that in this locality chloride also increases greatly in the water beneath the oil, it may easily be shown by comparison with other areas 

that the rise in chloride is a local feature, and has no special significance.

Analyses 78 and 79, Table 12, represent waters encountered at 

370 and 3,700 feet, respectively, in a well drilled for oil several miles 

north of the Eastside Coalinga field. No oil had been encountered 

when the lower water was reached, and it is believed that both waters 

are unaffected by hydrocarbons. These analyses may therefore be 

considered as showing the normal changes that take place with increasing depth. It will be noted that No. 78 is a secondary saline 

water, and that No. 79 is slightly primary alkaline owing to an 

increase in alkalies without a corresponding increase in strong acids. 

The sulphate salinity ratio in No. 78 is 80 per cent and in No. 79, 76 

per cent, ano^ the carbonate-sulphate ratios are, respectively, 0.16 

and 0.13.
COMPOSITION OF THE OIL-FIELD WATERS. 81

TABLE 12. Analyses of ground water at different depths in 'the Coalinga oil field, Cal., 

showing alteration by oil or coal. 

[See fig. 5, p. 79.] '

PROPERTIES OF REACTION IN 

PER CENT.

Primary salinity... . ............

Per cent of rS04 in rS04+rCl . . . 

Ratio of rC03+rHC03 to rS04 ..

CONSTITUENTS IN PARTS PER 

MILLION.

Sodium (Na) and potassium 

(K)a.................. .......

Calcium (Ca) ...................

MaguesiumfMg) ...............

Iron oxide (FejO3 ) and alumina 

(A12 03 ).......................

Sulphate (S04 ).................

Chloride (Cl). . .................

Carbonate (C03 )b. ..............

Silica (SiOs)....;.. .............

Hydrogen sulphide (H2S). . .....

REACTING VALUES IN PER CENT.

Alkalies: 

Sodium (rNa) and potasAlkaline earths:

Strong acids:

Chloride (rCl). ..............

Weak acids: 

Carbonate (rCO3)6. .........

Sulphide (rS):..............

ANALYSIS AS REPORTED.d

Silica...........................

74

59.0 

36.8 

0 

4.2

80.0 

.05

804 

303 

112

14 

2,181 

404 

76

c54

3,948

29.5

12.7 

7.8

38.3 

9.6

2.1

96.76 

38.93 

.66

59.08 

.82 

25.42 

4.99 

.84 

c3.15

230. 65

75

67.0 

18.6 

0 

14.4

67.0 

.26

933 

193 

121

19 

1,673 

606 

282

c249

4,076

33.5

7.9 

8.2

28.7 

14.1

7.6

100.33 

56.81 

1.35

10.12 

20.76 

28.53 

4.54 

1.13 

c 14. 54

238. 11

76

36.2 

0 

50.8 

13.0

27.6 

6.38

717

27 

40

3 

 170 

332 

686

95

2,070 

104

43.5

1.9

4.6

5.0 

13.1

31.9

14.37 

31.99 

56.68

.10 

3.90 

.21 

7.95 

.16 

5.63

120. 99 

6.09

77

63.8 

0 

30.8 

5.4

.6 

90.5

2,872 

75 

44

56 

23 

2,961 

1,435

«67

7,533

47.3

1.4 

1.3

.2 

31.7

18.1

1.90 

286. 00 

126.00

10.90 ""'oo'

3.30 

«3.90

440. 90

78

64.6 

24.0 

0 

11.4

80.0 

.16

544 

124 

82

1,243 

232 

125

57

2,407

32.3

8.5 

9.2

35.3 

9.0

5.7

70.80 

22.37

8.22 

12.13 

23.77

3.33

140. 62

79

91.2 

0 

6.6 

2.2

76.0 

.13

3,000 

28 

19

Trace. 

4,421 

1,040 

355

29

8,892

48-9

.5 

.6

34.6 

11.0

4.4

382. 05 

100-30 

27.54

4.07

"""3." 82' 

Trace. 

1.70

519. 48

80

21.8 

0 

74.4 

3.8

29.4 

' 8.8

526 

13 

2.6

4.6 

74 

130 

400 

83 

18

1,251.2

48.1

1.4 

.5

3.2

7.7

28.1 

11.0

5.84 

12.52 

39.01 

11.85 

.50 

1.54 

Trace. 

.52 

.27 

1.03

73.08

a. Reported and calculated as sodium but includes potassium.

b Reported and calculated as carbonate but probably in part bicarbonate.

c Includes suspended matter.

<* In hypothetic combinations, in grains per U. S. gallon.

74,75,76,77. Waterfrom different horizons in four wells of the Associated Oil Co.,sec.36,T.20 S.,R.14E. 

These wells are all within 1,200 feet of a central point, and the four waters probably occur in the 

same vertical section. Analyst, Smith, Emery & Co. Authority, Associated Oil Co.

74. Water well, 996 feet deep. Water chiefly from about 800 feet, or about 1,000 feet above the oil.

75. Oil well. Water corroded casing at 1,160 feet, and probably occurs in water sand at about 1,100 feet. 

Top of oil sand 1,542 feet.

76. Oil well. Sulphur water from 1,347 feet. Tar sand 1,170 to 1,205; top of oil sand 1,593 feet.

77. Oil well. "Bottom water" from 1,802 feet. Oil sand 1,712 to 1,778 feet.

78. 79. Standard Oil Co. well Domengine 1, sec. 27, T. 18 S., R. 15 E. No. 78 represents water from 370 

feet; No. 79, water from 3,700 feet, at which depth no oil had been encountered. These analyses 

probably represent the normal changes that occur with increasing depth in waters unaltered by 

the oil. Analyst, Standard Oil Co.

80. Water from upper coal mine, sec. 26, T. 20 S., R. 14 E. Water issues from point just above the coal 

bed (in Tejon formation) and is probably unaffected by oil, Analyst, Smith, Emery & Co,

60439° Bull, 653 17 6
82 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

Figure 5, B, shows these two analyses plotted according to the 

scheme followed in figure 5, A, except that the vertical scale used is 

only about half as great. Even on a smaller scale, however, the contrast between the two figures is striking. The percentage values of 

sulphate and carbonate, instead of crossing, run practically parallel. 

The alkaline earths decrease greatly and the alkalies therefore increase. 

The percentage of chloride is about the same in the two waters. The 

concentration figure increases greatly, however; so that all these constituents except the alkaline earths increase in actual amount. 

Analyses of water from other deep wells outside the oil fields on the 

west side of the San Joaquin Valley indicate that these changes are 

representive and that the amount of sulphate does not decrease and 

generally increases with depth. 1 In general, the concentration increases and in many localities chloride shows a marked increase with 

depth, but this does not affect the relative proportions of sulphate 

and carbonate.

The analyses given above show that in the Coalinga field the alteration of the waters as the oil zone is approached is extensive, but in 

the Midway field the changes are less striking. Analyses 81 and 82, 

Table 13, represent waters from the same well at depths of 1,380 

and 1,947 feet, respectively. A gas sand occurs at about 1,810 feet 

and an oil sand a short distance below the lower water, so that the 

section represented is roughly comparable to that shown in the lower 

part of figure 5, A. These waters, however, are of partly connate 

origin and the proportion of sulphate even in the upper water is smallThe properties of reaction show only a slight change, primary 

alkalinity increasing from 28.6 to 31.8 per cent and the sulphate 

salinity ratio decreasing from 2.3 to 0.2 per cent. The carbonatesulphate ratio shows the most pronounced change, from 20 in the 

upper water to 165 in the lower. There is also a marked difference 

in concentration, that of the lower water being over twice that of the 

upper. It is evident that these waters differ in composition along 

the same lines followed, by the Coalinga waters but that the total 

changes are much smaller. In the Midway field water 600 feet apart 

may show only a slight difference in sulphate content, whereas in the 

Coalinga field waters in the same relative positions usually differ 

widely.

i Mendenhall, W. C., Dole, R. B., and Stabler, Herman, Ground water in San Joaquin Valley, Cal.: 

U.S. Geol. Survey Water-Supply Paper 398,1916.
COMPOSITION OF THE OIL-FIELD WATERS. 83

TABLE 13. Analyses of water from different depths in an oil well in the Midway oilfield,

x CaL

PROPERTIES OF REACTION IN 

PER CENT.

Primary salinity..............

Ratio of rCOa+rHCOs torSO*.

MILLION.

(K)a.......................

Calcium (Ca) .................

Magnesium (Mg)..... ........

(AlaOs).............. .......

Sulphate (S0<). ........ ......

Chloride (Cl).... . ............

Silica (SiOa)...............-..

81

68.6

0

28. 6

2.8

2.3

20

1.059

11

9 6

1.7

38

1,125

4-13

12

c 2, 699. 3

82

67.0

0

3-1.8

1.2

.2

165

2,809

26

2.9

8.7

2,920

1,226

17

7, 009; 6

REACTING VALUES IN PER 

CENT.

Alkalies:

Sodium (rNa) and potasStrong acids: 

Sulphate (rSO<)..........

Chloride (rCl).. ...........

Weak acids: 

Carbonate (rCOa) 6........

ANALYSIS AS REPORTEP.d

Sodium chloride. .............

Silica.........................

81

48.6

.6

.8

8

33.5

15.7

3.31

108.40

41.04

1.65

1.92

.10

.71

c 157. 73

82

49.4

.5

.1

.1

33.4

16.5

.76

281.80

121. 80

3.80

.61

1.00

409. 47

a Reported and calculated as sodium but includes potassium.

b Reported and calculated as carbonate but probably in part bicarbonate.

c Potassium, iodide, aiid borate absent.

d In hypothetic combinations, in grains per.U. S. gallon.

81,82. Standard Oil Co. well, sec. 30, T. 32 S., B. 24 E. No. 81 represents water from 1,380 foot and No. 

82 water from 1,947 feet. A small gas sand occurs between the two waters, and an oil sand a short 

distance below the lower. Both samples.taken while drilling and analyzed by Standard Oil Co.

Analyses 83 to 85, Table 14, represent the vertical gradation in the 

Kern River field. As these waters are primary alkaline there is no 

sharp change in character comparable with the change from secondary 

.salinity to primary alkalinity in the waters of the west side, but the 

same order of succession is observed, carbonate increasing and sulphate decreasing as the oil zone is approached. Analysis 86 represents water from a depth of 5,135 feet or over 3,000 feet below 

the main oil zone. Although occurring over 3,000 feet below the 

deepest of the waters just mentioned it is very similar to it in character, showing high alkalies, chloride, and carbonate, and no sulphate. 1 

However, a water encountered at least 2,500 feet above this in the 

same well close to (probably below) the oil zone is very different in 

character; it is a secondary saline brine rather than a primary alkaline 

water, though as would be expected from its position it contains no 

sulphate. So far as is known, this water is much the most concentrated water and is the only brine that has been found in the Kern 

River field. An idea of its composition may be obtained from the 

following partial analysis,2 and the properties of reaction estimated 

from this analysis are as follows: Primary salinity 89.5 per cent, 

secondary salinity 10 per cent, secondary alkalinity 0.5 per cent.

1 Compare analysis 44, Table 7, p. 70, which represents water from a depth of 3,860 feet, or about 3,000 

feet below the oil measures at the northern end of the Midway field.

, ' Mendenhall, W. C., Dole, R. B., and Stabler, Herman, Ground water in San Joaquin Valley, Cal.: 

U. S. Geol. Survey Water-Supply Paper 398, Table 60, p. 294,1916.
84 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, GAL.

Field assay of water occurring between 1,030 and 2,609 feet in Petroleum Development Co.'s 

deep well, sec. 4, T. 29 S.,R.28E.

Parts per million. 

Bicarbonate (HC03 )........................................... 132

Sulphate (S04 )................................................ 5

Chloride (Cl)................................................ 15,100

Total hardness calculated as CaC03 ............................. 2,300

Total solids................................................... 25, 000

Although definite groups of analyses showing the vertical gradation 

in other fields are not available, there is every reason to believe that 

the order of succession is the same. The total extent of the alteration 

may differ in different fields, and the point at which alteration is complete may be higher in some localities than in others, but these are 

merely local variations which remain to be determined in each field. 

In some localities an incompletely altered water may be found below 

the oil measures, but such occurrences are doubtless due to unusual 

geologic conditions. Thus, analysis 30, already discussed, indicates 

an only partly altered water occurring 600 feet below the oil measures, 

but this water is in Cretaceous strata and has probably had a very 

different history from the altered water more closely associated with 

the oil (analysis No. 64). However, as the migration and accumulation of oil in the fields of the San Joaquin Valley has been greatly 

influenced by angular unconformities in the strata, it is conceivable 

that surface water might enter at the outcrop of a lower formation, 

barren of oil, and migrate through it without complete alteration to 

a point below the oil measures. In a region of such complex geologic 

structure some apparent irregularities in the alteration of the water 

are to be expected.
COMPOSITION OF THE OIL-FIELD WATERS. 85

TABLE 14. Analyses of waters from various horizons in the Kern River, Lost Hills, and

McKittrick oilfields, Cal.

PROPERTIES OF REACTION IN 

PEE CENT.

Primary alkalinity. ............

Secondary alkalinity. ...'........

Ratio of rC03+rHCO3 to rSO4 . .

CONSTITUENTS IN PAKTS PEK 

MILLION.

Sodium (Na) ...................

Calcium (Ca). ..................

Iron (Fe)............ ...........

Sulphate (SO*). ................

Chloride (Cl)..... ..:...........

Silica (Si02 )........... .........

REACTING VALUES IN PER CENT.

Alkalies:

Alkaline earths:

Strong acids: 

Sulphate (rSO<).............

Chloride (rCl).. .............

Weak acids:

Bicarbonate (rHCO3 ) .......

ANALYSIS AS REPORTED-^

Iron and alumina. ..............

83'

34.4

0

4.4

61.2

CO C

3

| 22

IS

4.2

.1

91

9.1

0

71

18

127.4

} 19.4

22.2

8.4

10.8

6.4

0

32.8

84

41.6

0

33.0'

25.4

20.2

7

joSl

13

1 9

\}66

12'

35

23

192.2

fa37.3

11.0

1.7

4.2

16.6

c29.2

1.03

3.39

3.01

1.88

.26

.30

1.36

11.26

85

12.2

0

76.2

11.6

8.0

88

«296

20

8.6

<:::::::::

58

<=384

52

826.1

044.2

3.4

2.4

.5

5.6

C43.9

.65

5.56

34.30

2.96

1.75

3.06

48.28

86

58.8

0

40.2

1.0

0

GO

| 1,550

10

1.2

.1

0

1,418

0

1,708

3,821.3

| 49.5

.4

.1

.0

90 4

.0

20.6

87

S7.-6

10.4

0

2.0

5.7

.36

Jo4,773

214

228

} 616

634

7,744

46

13,800

f 043.8

2.2

4.0

2.8

46.2

cl.O

705.65

1 70

40.58

1.35

10.50

33.25

9.36

.92

2.69

806.09

88

94.0

1.6

0

4.4

TVnpft

44.0

o7,635

195

144

621

17

11,946

48

20,470 '

1.3

1.7

Trace.

47.8

c2.2

1,116.23

14.30

1.42

6.85

21.15

22.93

8.93

1.20

2.83

1.195.84

89

72.8

0

24.0

3.2

.6

68.0

<»4,132

38

52

62.7

28

4,768

c 1,513

67

10,598.7

Q48.4

°.5

1.1

.2

36.2

cl3.6

459. 11

139. 32

.71

5.01

1.40

.27

9.30

.16

3.89

619. 17

o Reported and calculated as sodium but includes potassium.

c Reported and calculated as carbonate but probably in part bicarbonate. 

d In hypothetic combinations, in grains per U.S. gallon.

Kern River field:

83. Kern River water at Bakersfield. Mean of 35 analyses of samples collected every 10 davs in 

1906. Analysts, F. M. Eaton and P. L. McCreary (U. S. Geol. Survey Water-Supply P"aper 

237-, p. 5R, 1910).

84. Standard Oil Co. water well, sec. 5, T. 28 S., R. 27 E. Water from 380 to 397 feet. Analyst, Standard Oil Co., October, 1913.

85. Standard Oil Co. well 1, sec. 27, T. 28 S., R. 27 E. Water from 1,990 feet to 2,018 feet or about 

200 feet above tar and oil sands. Analyst, Standard Oil Co., January, 1915.

86. Petroleum Development Co., sec. 4, T. 29 S., R. 23 E. Well 5,135 feet deep. Water Is from brown 

shale, containing shows of oil, but over 3,000 feet below producing oil zone. (U. S. Geol. Survey 

Water-Supply Paper 398, Table 61, p. 294, 1916.) 

Lost Hills field:

87. Lindsay Incorporated Oil Co. well 1, sec. 7, T. 27 S., R. 21 E. Water from 180 feet, and probably 

not affected by oil. Analyst, Smith, Emery & Co.

88. Associated Oil Co. well 3, sec. 13, T. 26 S., R. 20 E. Water probably from a short distance above

the oil. Analyst, Smith, Emery & Co. Authority, Associated Oil Co. 

McKittrick field:

89. Associated Oil Co. well Del Monte 38, sec. 18, T. 30 S., R. 21 E. Water pumped with the oil. 

Analyst, Smith, Emery & Co. Authority, Associated Oil Co. This analysis is typical of the 

water associated with the oil in the McKittrick field.
86 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, GAL.

AREAL RELATIONS.

The oil-field waters vary horizontally as well as vertically, but the 

horizontal or areal variation is due simply to the mingling in various 

proportions of meteoric and connate waters. No matter how effectually connate water may be trapped in a structural trough, it is evident that near the surface of the ground and also around the edges 

of the trough where the rocks outcrop there will be a certain admixture of meteoric water. Although a few very salty waters have been 

found close to the surface (see No. 87, Table 14, p. 85) they are generally confined to lower levels, and a marked increase of alkalies and 

v chlorides with depth appears to be the rule. This phase of the mixing 

of fresh and salt waters has been sufficiently discussed in the preceding 

section, and the gradation from the outcrop toward the center of the 

trough will now be considered. Two phases of this gradation present 

themselves, first, the increase in chloride, which is a factor of simple 

mixing, and second, the change in the properties of the water, which 

is the net result of various chemical reactions. Since the chloride is 

not affected by hydrocarbons it furnishes a simple and convenient 

basis for comparing normal and modified as well as altered waters. 

The properties of reaction, however, furnish a more adequate basis 

for comparison and in studying waters of the altered group are especially valuable.

The examples given below are drawn from the Midway and Sunset 

fields, where it happens that the most complete data are available, but 

similar gradations have been observed in the Coalinga field and. can 

doubtless be worked out elsewhere.

Variation in chloride. Normal connate water contains about 19,000 

parts per million of the chloride radicle and 16,000 parts of other constituents; ordinary surface water contains very little chloride and 

generally less than 3,000 parts of dissolved solids. The figures representing chloride and total solids show the greatest contrast and are 

therefore convenient indices for comparing mixtures of the two types. 

The carbonate figure also shows considerable variation, being very 

low in brine and generally higher in meteoric water.

In the accompanying table are shown a series of partial analyses 

of water from wells near Fellows in the northern part of the Midway 

field. The wells fall roughly along a line about coincident in direction 

with the dip of the strata. In the table they are arranged in order of 

their distance from the outcrop American Oilfield Co.'s well 92 being 

about'1,600 feet from the outcrop and Associated Oil Co.'s well 3 

about 10,000 feet beyond well 92. The analytical figures given for 

the water from the first four wells represent partial analyses made by 

the American Oilfields Co.; the figures given for the water from the 

last,two wells are taken from complete analyses made by Smith,
COMPOSITION OP THE OIL-FIELD WATERS. 87

V

Emery & Co. for the Associated Oil Co. The chloride values are 

accurately determined and are comparable throughout. The figures 

reported for soluble solids in the first four analyses are assumed to 

represent all the constituents except silica and the alkaline earth carbonates, and on this basis are comparable with the figures shown for 

the last two analyses. The "alkalinity" values of the first four 

waters are mutually comparable but do not represent alkalinity in 

the sense used elsewhere in this report; no comparable figures for the 

last two waters are available, but their alkalinity is known to be considerably lower than that of the others.

Partial analyses of water from oil wells near Fellows, Midway field, showing increase of 

salinity with distance from the outcrop.

American Oilfields Co. well 23. .................................. « ........

Parts per million.

Chloride 

(Cl).

400 

2,840 

7,720 

14,480 

17,631 

24,398

Soluble 

solids.

6,630 

8,660 

20,720 

26,480 

28,970 

39,700

"Alkalinity," 

per cent.

0.01300 

.01350 

.01158 

.00625

a See analysis 50, Table 8, p. 73.

In order to show these relations graphically the determinations 

have been plotted in figure 6. In the figure the horizontal scale represents the distance between the wells along a line between American 

Oilfields Co.'s well 92 and Associated Oil Co.'s well 3. All the wells 

fall close to this line except Associated Oil Co.'s well 7, which lies 

about 1,200 feet to the northwest. The figure shows fairly well the 

gradation from an essentially meteoric water to a connate water. If 

an analysis of water from still nearer the outcrop could be added it 

would doubtless show a still smaller amount of solids. On the other 

hand, the water from Associated Oil Co.J s well 3 is somewhat more 

concentrated than sea water and contains a slightly larger amount 

of chloride, and waters from points still farther from the outcrop do 

not show any. further increase.

The remarkably regular increase in chloride and soluble solids 

shown by these analyses is not entirely a horizontal gradation, for the 

waters are not all from the same horizon. .The water in American 

Oilfields Co.'swell 92 probably occurs about 600 feet stratigraphically 

higher than that in the Associated Oil Co.'s wells. This is suggested 

by the slight irregularities.in the curves shown in figure 6, but the 

vertical component is not great enough to detract seriously from the 

significance of this regular and essentially horizontal gradation.

V
88 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

Relations of the mixed type. Besides causing a simple variation in 

the chloride content the mingling of connate and meteoric waters 

leads to a series of reactions between the other constituents and produces corresponding changes in the properties of the waters. These 

changes may be observed in the waters of any one zone along a line 

leading away from the outcrop, but may best be studied in the waters 

of the altered group, whose complete alteration by the oil affords a 

uniform basis for comparison. The fact that the altered waters along 

the western or shallow edge of the Midway and Sunset fields are of 

the chloride-carbonate type, whereas those farther east are secondary 

saline brines, is due to the entrance of meteoric water at the outcrop,

s w. Distance bet-ween we/Js in Feet" NE.

zpoo 6.000 8000

\yfei we// 32 well 73 -well 57 

 American Oilfields Co.-

Sec.JS 7TJ/S. «.22£.

-Associated Oil Co?- 

Sec.JO T.J/S. fl.2J£.

FIGURE 6. Diagram showing increase in salinity *bf waters in the northern part of the Midway field with

distance from the outcrop.

and the gradations that may be traced between this mixed type and 

the brines afford an interesting study of the mixing of meteoric and 

connate waters. The relations and derivation of the mixed type 

may more easily be understood if some of the reactions involved are 

first considered.

The reactions involved in the conversion of a sulphate water into a 

carbonate water, which forms the basis of the vertical gradation 

already described, are discussed on pages 94-99. Let it be assumed 

for the present that the process is a simple substitution of carbonate 

for sulphate. In unaltered sea water sulphate and chloride exceed 

the alkalies in 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
COMPOSITION OP THE OIL-FIELD WATERS. 89

small amount of earths and carbonate ca-n 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 value of alkaline earths balanced by carbonate that can 

be retained represents only a very small percentage of the total concentration value, 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 is 

characterized by 21.1 per cent of secondary salinity, of which 9.2 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 slight, so that if 

the properties are expressed in percentages the value of primary 

salinity will be raised. If it be assumed, first, that the sulphate in 

sea water is entirely removed and an equal value of carbonate introduced, and secondly, that 7.6 per cent, or 2,660 parts per million of 

alkaline-earth carbonates'are lost through precipitation, the properties will change as follows:

Changes in properties of sea water through substitution of carbonate for sulphate.

Normal sea water. .....................................

Same after precipitation of assumed excess of alkaline

Primary 

salinity.

78.6

78.6

85.1

Secondary 

salinity.

21.1

11.8

12.8

Secondary 

alkalinity.

0.3

9.6

2.1

Concentration.

35,000

35,000

32,340

Since these reactions take place after the water has been entrapped 

in the sediments they are of course complicated by many indeterminable factors, and any attempt to reduce them to exact figures must 

be regarded as speculative. There is little doubt, however, that 

the oil-field brines have been derived from connate water by the 

general processes outlined above, as shown by their properties of 

reaction. (See Tables 8 and 9.)

The changes involved in the alteration of a meteoric water are 

similar but more extensive. The chief constituents of the surface 

and shallow ground waters of the fields of the west side are sulphate, 

alkalies, and alkaline earths. (See Tables 1 to 4.) If carbonate 

is substituted for the sulphate in these waters, it may be pre1 Murray, John, and Irvine, Robert, On the chemical changes which take place in the composition of the 

sea water associated with blue muds on the floor of the ocean: Roy. Soc. Edinburgh Trans., vol. 37, p. 481, 

1892-93.
90 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

sunied that a considerable proportion of alkaline earth carbonates 

will be formed and removed by precipitation, leaving the chief constituents of the water alkalies and carbonate. These waters, however, are less concentrated than sea water, and therefore the amount 

of alkaline earths that can be held in solution in the presence of 

carbonate, if expressed as a percentage, will be much greater. The 

alteration of a meteoric water results essentially in a change from 

primary and secondary salinity to primary and secondary alkalinity, 

the percentage of the last property being only moderate. These 

changes are partly shown by the first three analyses in figure 5, A, 

and the complete transition from normal through modified to altered 

waters of meteoric origin by the analyses in Tables 4, 5, and 6.

Altered waters of the mixed type are derived by the mixing of 

primary alkaline waters (reversed type) and brines. It has been 

shown above that if all of the. sulphate is removed from sea water 

and carbonate substituted the resulting brine will still be characterized by a considerable proportion of secondary salinity, which 

must be chloride salinity. The reaction that ensues when a sodium 

carbonate water is added may be written thus:

Secondary salinity-f-Primary alkalinity=Primary salinity+Secondary alkalinity 

CaCl2 + Na2C03 = 2NaCl + CaC03

The addition of a primary alkaline water to a brine increases the 

alkalies without corresponding increase in strong acids and secondary salinity is therefore reduced. Secondary alkalinity may be somewhat increased, as the concentration of the brine is decreased by 

the addition of the'more dilute water, but this change is not likely 

to be pronounced. If a sufficient amount of the sodium carbonate 

water is added it is evident that all the secondary salinity will be 

destroyed and that the water will then be characterized by only two 

properties, primary salinity and secondary alkalinity. (See analysis 

46, Table 8, p. 73.) 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 most of the primary alkaline (meteoric) waters is only about 

3,000 parts; hence, the concentration of the mixed water will be 

some intermediate figure, depending on the proportions of the mixture. 

If the brine component predominates primary salinity and the concentration will be high and primary alkalinity low, but as more and 

more of the meteoric water is added primary alkalinity will increase 

and primary salinity and concentration will decrease. (See analyses 

60, Table 10, p. 76, and 72, Table 11, p. 77.)

The transition from brine to the mixed type is shown in figure 7, 

in which are plotted the reaction properties of the waters from four 

wells along the east-west line that separates the Midway and Sunset
COMPOSITION OP THE OIL-FIELD WATERS. 91

fields. This line is oblique to the strike of the beds and the changes 

are therefore more gradual than they would be along a line normal 

to the strike. The total distance is about 18,300 feet, the wells being 

equally spaced. All the waters occur below the top oil sand and are 

believed to come from the same general horizon.

Complete analyses of the waters are given in Tables 9 and 11 (pp. 74 

and 77). As shown in figure 7, the waters of the two wells near the 

outcrop are primary alkaline, whereas those farther east are brines. 

With 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.

'Distance bzfween wells in feef

FIGURE 7. Diagram showing gradation between waters of the mixed type in the western part of the 

Midway-Sunset field and the brines that occur at the same general horizon in the deeper territory to the 

east. Section extends from SE. } sec. 31, T. 32 S., R. 24 '£., to NE. | sec. 31, T. 12 N., R. 23 W.

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 hi the water farthest 

from the outcrop. The concentration curve shows a steady rise with 

distance from the outcrop, and in the distance covered by the figure 

more than trebles. It will be noted that there is much less difference between the waters of the two wells farthest from the outcrop 

than between those of the .two 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. Between the first well and the outcrop, 

however, the water probably increases rapidly in primary alkalinity 

and near the outcrop passes to the reversed type.
92 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

The belief that this chloride-carbonate water, which is associated 

with the oil in the Westside Coalinga and in the western or shallower 

portion of the Midway and Sunset fields, is in reality a mixture of 

meteoric and connate waters is corroborated by other observations. 

Thus, the average ratios of magnesium to calcium and of sodium to 

potassium in waters of the mixed type are intermediate between those 

in the brines on the one hand and in the chiefly meteoric waters on the 

other. These ratios have been calculated in all the analyses given 

in this report, and the averages for each type are presented in the 

following tables. For the purposes of this comparison it may be 

assumed that all the waters of the normal and modified groups and 

of the reversed type of the altered group are essentially of meteoric 

origin. As practically all these waters contain some of the constituents of connate water, whereas the brines are relatively pure, 

the mixed type would be expected to resemble the essentially 

meteoric waters more closely than the brines. Thus, the average 

ratio of magnesium to calcium in 16 waters of the mixed type is 1.29, 

as against 1.34 in 50 chiefly meteoric waters, and 0.71 in 13 brines. 

Sodium and potassium have been separately determined in only 16 

of the analyses in this report, so that the average ratios are of less 

value. The average sodium-potassium ratio in 6 waters of the 

mixed type is 188, as against 246 in 6 chiefly meteoric waters and 

165 in 4 brines. Although in the deeper waters the individual ratios 

of both magnesium to calcium and sodium to potassium are fairly 

constant, in the upper meteoric waters they show considerable variation; hence if twice as many analyses were included the figures would 

be somewhat different. That the figures given may fairly be considered representative, however, is indicated by the writer's study of a 

large number of analyses not included in this report.

(

rMo\ j^- j in 79 analyses of different types of water from the Coalinga, Midway, and Sunset fields.

Type of water.

Ground water:

Modified ...................:......:...

Mixed. ...............................

Averages:

Coalinga field.

Average 

ratio.

3.08

1.04 

.90 

1.70 

.90 

1.62

1.35 

1.37

Number 

of 

analyses.

2

18 

4 

12 

1 

5

36 

42

Midway-Sunset 

field.

Average 

ratio.

0.90

1.35 

. 1.70 

1.65 

.70 

1.15

1.31 

1.06

Number 

of 

analyses.

5

4 

3 

2 

12 

11

14

37

Both fields.

Average 

ratio.

1.52

1.09 

1.25 

1.69 

.71 

1.29

1.34 

1.23

Number 

of 

analyses.

7

22 

7 

14 

13 

16

50 

79
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 93

Average ratios of sodium to potassium in reacting values in 16 waters' from the 

Coalinga, Midway, and Sunset fields.

Average 

ratio.

246

188

165

204

Number of 

analyses.

6

6

4

16

CHEMICAL RELATIONS BETWEEN WATER AND THE 

HYDROCARBONS.

^ ALTERATION OF WATERS BY THE HYDROCARBONS.

NATURE OF ALTERATIONS.

It has been shown that the waters associated with the oil in the 

San Joaquin Valley oil fields are almost or quite sulphate-free, 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. In regions where sulphates are rare or only locally distributed the alternative hypothesis 

that sulphide has accompanied the oil from below and that sulphate 

is formed by its oxidation may have to be considered, but as this 

condition does not prevail in the oil fields of San Joaquin Valley this 

hypothesis need not be discussed.

^ REDUCTION OF SULPHATE.

The observation that waters associated with oil contain no sulphate 

is by no means new, for it was pointed out in 1882 by Potiiitzin* that 

the waters associated with oil in the Caucasian oil fields contain no 

sulphate, and this has been amply confirmed by later workers there

^ i Potilitzin, A., Zusammensetzung des die Naphta begleitenden und aus schlammvulkanen ausstromenden Wassers (abstract); Deutsche, chem, Gesell. Ber., Band 15, p. 3039-b, 1882,
94 OIL-FIELD WATERS IN SAN JOAQUIN" VALLEY, CAL.

and in other fields. Hofer i mentions this widespread peculiarity of oilfield waters and presents a compilation of 27 analyses of sulphatefree water from various fields in Europe, Asia, and North America. 

However, neither Hofer nor, so far as the writer knows, any other 

writers on this subject have attempted to work out the chemical 

relations of the various types of water in any one field, but present 

merely isolated analyses of "oil-field water," the position of which 

with regard to the oil is generally not stated. The waters differ 

widely in chemical composition, some of them being concentrated 

brines very high in secondary salinity and others closely resembling 

the mixed (carbonate) type found in the San Joaquin Valley fields. 

The mixed type is less common but appears to be characteristic of 

the Russian and Galician fields. The nearly pure alkali carbonate 

water (reversed type) found in the Eastside Coalinga field has apparently not been found elsewhere. Some of the analyses show unusually 

large amounts of iodine and bromine, and several other rare elements 

have been reported, but the common characteristic of all the waters 

examined is the absence of sulphate. In some waters this is so complete that barium salts have been found in the solution. 2

The earlier investigators apparently regarded these sulphate-free 

waters more as chemical curiosities than as normal and reasonable 

phenomena, but the absence of sulphate has since been attributed to 

the reducing action of the hydrocarbons. The reaction between sulphate and organic matter was suggested by Bischof 3 to explain the 

origin of certain sulphur deposits. It is supposed that the sulphate 

is reduced to sulphide, which passes off as hydrogen sulphide, and 

that an equivalent portion of the oil or gas is oxidized to carbon 

dioxide and carbonate. Hofer writes the reaction substantially as 

follows:

CaS04 + CH4 = CaO + H2S+CO2 + H2O 

or

CaSO4 + CH4 = CaS+C02 + 2H20=CaC03 + H2S + H20 

These reactions, however, are hypothetic and are open to several 

objections. It has long been known that sulphate solutions are 

decomposed under some conditions in the presence of organic matter 

with the formation of hydrogen sulphide. 4 It was shown by Meyer 5 

and more definitely by Plauchud,6 however, that this decomposition

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

2 Idem, p. 28.

s Bischof, G., Chemische und physicalische Geologic, 2, pp. 144-164,1851.

«Lersch, B. M., Hydro-chemie, pp. 235-238, Berlin, 1864. Clarke, F. W., The data of geochemistry, 

3d ed.: U. S. Geol. Survey Bull. 616, p. Ill, 1916.

6 Meyer, Lothar, Chemische Untersuchung der Thermen zu Landeck in der Grafschaft Glatz: Jour, 

prakt. Chemie, Band 91, pp. 5-6,1864.

o Plauchud, E., Recherches sur la formation des eaux sulfureuses naturelles: Gompt. Rend., vol. 84, p. 

235, 1877; Sur la reduction des sulfates par les sulfuraires, et sur la formation des sulfures me'talliques, 

naturels: Idem, vol.95,p. 1363,1882. Etard, A., and Olivier, L., De la reduction des sulfates par les 

&tros vivants: Idem, vol. 95, p. 846,1882.
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 95

is due not to the mere presence of dead organic matter but to the 

vital processes of microorganisms. Numerous observers have since 

studied these creatures, whose functions are diverse 1 and whose 

importance from the standpoint of geochemistry appears to be considerable. It has been found that certain bacteria have the function of reducing sulphate to sulphite or thiosulphate and that others reduce 

oxygenated sulphur compounds to hydrogen sulphide. 2 On the other 

hand, certain bacteria can exist only in solutions containing hydrogen 

sulphide, which they oxidize and secrete as sulphur. This sulphur is 

further oxidized in the course of metabolism to sulphate, but the 

excess of sulphur remaining in the organism after death may accumulate to form deposits of crystalline sulphur.3 In general, the sulphideproducing bacteria are anaerobic, being able to exist in the absence 

of air, whereas those which secrete sulphur are probably aerobic. 

The hydrogen sulphide in many natural waters is thus doubtless 

derived from aqueous sulphate solutions by'the action of bacteria.

The action of similar organisms in ocean water has also been 

studied. Van Delden,4 in experimenting with a species that inhabits 

the estuaries on the coast of Holland, finds that these bacteria 

liberate in 27 days 843 milligrams of hydrogen sulphide per liter, 

which represents the reduction of 1,984 milligrams of sulphur trioxide. 

In this experiment he used sea water, to which was added a little 

potassium phosphate and organic matter; in another experiment 

with the same bacteria he used a prepared solution containing 

slightly more sodium chloride arid more sulphate than'sea water, 

and found that in 19 days 1,030 milligrams of hydrogen sulphide, 

equivalent to 2,424 milligrams of sulphur trioxide, were liberated. 

In the latter experiment the amount of sulphate reduced slightly 

exceeds that present in normal sea water. Van Delden notes also 

that the activity of this species increases with the concentration of 

sodium chloride up to 60,000 parts per million, but that the addition of more sodium chloride produces a marked diminution in their 

activity.

Hydrogen sulphide has been repeatedly observed in sea water 

and has been quantitatively determined by several observers. 

Lebedinzeff 5 finds that water from a depth of 8,290 feet in the

1 Winogradsky, Sergius, Ueber Schwefelbacterien: Bot. Zeitung, Nos. 31 to 37,1887.

2 See, for example, Beyerinck, M. W., Ueber Spirillum desulfuricans als Ursache von Sulfatreduction: 

Centralbl. Bakteriologie, Band 1, Abt. 2, pp. 1-9, 49-59,104-114-, 1895. Also Saltet, R. H., Ueber Reduktion von Sulfaten in Brackwasser durch Bakterien: Idem, Band 6, Abt! 2, p. 648,1900.

'For a summary see Stutzer, 0., Die Wichtigsten Lagerstiitten der Nicht Erze, Berlin, 1911; Phalen, 

W. C., Tho origin of sulphur deposits (translation from Stutzer's work): Econ. Geology, vol. 7, pp. 732- 

743,1912.

«Van Delden, A., Beitrag zur Kenntnis der Sulfatreduktion durch Bakterien: Centralbl. Bakteriologie, 

Band 11, Abt. 2, pp. 92-94,113-119, 1903.

6 Lebedinzeff, A., Vorlaufige Mitteilung iiber den chemischen Untersuchungen des Scfrwarzen und 

Asowischen Meeres in Sommer 1891: Soc. Naturalistes & Odessa Trav., vol. 16, fasc. 2, p. 149,1891; abstract 

in Roy. Geog. Soc. Proc., new ser., vol. 14, p. 461,1892,
96 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

Black Sea contains 6,550 parts per million of hydrogen sulphide, 

and Zelinsky 1 has identified in the bottom muds of the Black Sea 

several species of anaerobic bacteria that are very active in the 

formation of hydrogen sulphide. Murray and Irvine 2 report the 

formation of unstable sulphide in sea water associated with the blue 

muds on the floor of the ocean and by a series of analyses show that 

some of the sea water drained from the muds contains only 50 per 

cent as much sulphate as normal sea water. They note a concomitant increase in the alkalinity of the water, due principally to 

the formation of carbonate, and a slight loss of lime, due to the 

precipitation of calcium carbonate. This implies a decrease in 

secondary salinity and an increase in secondary alkalinity, limited 

by the solubility of the calcium carbonate; or, in other words, an 

approach to the oil-field brines along the lines explained .above.

It is therefore well established that sulphate may be reduced by 

bacteria in the presence of organic matter, but the bearing of this 

process on the development of the composition of oil-field waters 

is conjectural. It may be assumed, if desired, that the connate 

water was completely altered by the action of bacteria shortly after 

being entrapped in the sediments, as suggested by the observations 

of Murray and Irvine, but the alteration of the meteoric water is 

more difficult to explain. There is no evidence to show that even 

anaerobic bacteria can continue to exist in the muds after they 

have been covered with a thousand feet or more of other sediments 

and elevated into land, and certainly some time must have elapsed 

after the elevation before meteoric water penetrated to the zone of 

alteration. In fact, the writer is inclined to believe that in some 

localities meteoric waters are percolating down to this zone and are 

being reduced at the present time. Hence, unless it be assumed that 

bacteria are present in the strata to depths of several thousand feet 

the formation of the sulphate-free waters can not be ascribed to 

bacterial action, except perhaps in part.

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

many years, and few attempts have been made to prove it in the 

laboratory. In the anhydrous condition gypsum (CaS04 ) is a very 

stable compound, and it has been found that a temperature of 

about 700° C. is required for its reduction, even with a fairly active 

reducing agent, such as carbon monoxide. 3 In solution, however,

1 Zelinsky, N. [Sulphydric fermentation in the Black Sea]: Russ. Chem. Soc. Jour., vol. 25, pp. 298-303, 

1894; abstract in Chem. Soc. Jour., vol. 68, pt. 2, p. 200, 1894. Andrussow, N., Physical exploration in 

the Black Sea: Roy. Geog. Soc. Geog. Jour., vol. 1, p. 49,1893.

2 Murray, John, and Irvine, Robert, On the chemical changes which take place in the composition of 

sea water associated with blue muds on the floor of the ocean: Roy. Soc. Edinburgh Trans., vol. 37, p. 

481, 1892-93.

si-Iofman, H. O., and Mostowitsch, W., The reduction of calcium sulphate by carbon monoxide and. 

carbon, and the oxidation gf calcium sulphide; Am, Jn§t, MlQi Eng, Bull., pp. 913/-9.g9, 1910.
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 97

sulphate is more readily reduced. The experiments of the earlier 

workers are discredited by the fact that no precautions were taken 

to exclude bacteria, and certain more recent attempts proved unsuccessful, but recently Kharitschoff* has published a note on some 

simple experiments that were 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. Cadmium chloride was used to indicate the formation 

of sulphide. Three samples exposed to direct sunlight for six months 

at ordinary temperatures showed no sign of reduction. Other samples, sealed and heated for 420 hours on a water bath, under which

} conditions a pressure of not less than three atmospheres must have 

been developed, showed a very faint coloration due to the formation 

of a trace of sulphide. In still other samples left open and heated

x for 420 hours at 96° C. some sulphide was formed. A solution of 

magnesium sulphate mixed with kerosene and heated in the open 

for 420 hours underwent somewhat more reduction than the soluA tion 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 necessary to insure complete reduction.

If it be admitted that the reduction of sulphate is accomplished 

directly by the constituents of oil it must still be recognized that the 

reaction as generally written, involving methane, is improbable. 

Methane, being itself a decomposition product, is the most stable 

member of the paraffin series, which are the most inert of the hydroJ carbons; and although .methane becomes much more active at higher 

temperatures and pressures it seems that the reduction of a sulphate

 solution would be accomplished less readily by this hydrocarbon 

than by others. The different members of the hydrocarbon series 

probably react with sulphate solutions in different degree, but this 

phase of the subject has apparently not been investigated. The unsaturated chain compounds, such as the olefines, acetylenes, and terpenes, doubtless behave in different manner from the paraffins, the 

naphthenes, or the aromatic hydrocarbons, not only in the ease of 

reaction but in the stages involved. In the reactions between some 

substances hydrolysis is probably important, and in those between 

other substances the action of oxidizing agents may enter. It is 

quite possible that certain constituents of the oil other than true 

hydrocarbons are active in the reduction of sulphate solutions, 

although for the sake of brevity the term hydrocarbon is used in this 

report to include all oil constituents. In any event, the reaction as 

written by Hofer (p. 94) can be considered only a condensed repre9 '

1 Kharitschoff, K. V., The waters in petroleum wells: Petroleum Rev., vol. 29, p. 368, 1913, 

60439° Bull. 653 17 7
98 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

sentation of the type of change that takes place, the intermediate 

stages in the decomposition of the hydrocarbons on the one hand 

and of the sulphate on the other being as yet unknown.

Just as sulphate by reduction yields sulphide, so sulphide under 

other conditions may oxidize to sulphate. Whether alkaline sulphide is the first product of reduction or not, .the final product is 

hydrogen sulphide, and this gas is readily oxidized to produce free 

sulphur, probably in accordance with the equation

o 2H3S+02 = 2H20+2S

Thus, free sulphur has been found in a number of marine muds, 

where it is doubtless 'formed by the oxidation of hydrogen sulphide 

derived from the sulphate in the sea water.1 Under more strongly 

oxidizing conditions, or in the presence of certain bacteria, the sulphur 

becomes thiosulphate, sulphite, and finally sulphate. The complete reversion of hydrogen sulphide to sulphate is probably not 

widespread in deeply buried strata, but the change to free sulphur, 

which may take place even on the floor of the ocean/ must be taken 

into account. It may also be noted that the oxidation of hydrogen 

sulphide to sulphur or sulphate results in the evolution of much 

heat,2 and if the earth temperatures in oil regions are higher than 

elsewhere, as suggested by Koenigsberger and Muhlberg,3 some of 

the excess may be contributed by this reaction.

FORMATION OF CARBONATE.

In the few published accounts of oil-field waters special stress is 

laid on the absence of sulphate as discussed in the preceding section, 

but no attempt has been made, so far as the writer can learn, to work 

out the relations of the various types of water or to explain the significance of the carbonate. If the reduction of the sulphate is to be 

ascribed to the action of hydrocarbons, however, the formation of 

carbonate is a necessary concomitant, and the presence of unusual 

amounts of carbonate in oil-field waters may be explained by this 

reaction.

The proportion of carbonate formed during the reduction of a 

definite amount of sulphate is not known and can not be determined 

until the stages involved in the reaction have been critically studied. 

Murray and Irvine report that the increase in the alkalinity of sea 

water associated with bottom muds is proportional to its loss in sul1 Buchanan, J. Y., On the occurrence of sulphur in marine muds and nodules, and its bearing on their 

mode of formation: Roy. Soc. Edinburgh Proc., vol. 18, p. 17,1890-91; Clarke, F. W., The data of geochemistry, 3d ed.: U. S. Geol. Survey Bu|l. 616, p. 514,1916.

2 Beeker, G. F., Geology of the quicksilver deposits of the Pacific slope: U. S. Geol. Survey Mon. 13, 

p. 254,1888. -

3 Koenigsberger, J.,and Muhlberg, M., tJber Messungen der geothermischen Tiefenstufe: Neues Jahrb., 

Beilage Band 31, pp. 107-157,1911.
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 99

phate, but this observation merely indicates that the two changes are 

the result of the same process and does not throw much light on the 

proportions involved. In the transition from normal to altered 

waters in the oil fields the increase in carbonate is roughly proportional to the decrease in sulphate, but the loss by precipitation of 

alkaline-earth carbonates prevents the deduction of exact figures. 

The assumption made on page 88 that for the value of sulphate removed from the water an equivalent value of carbonate is introduced, is perhaps the best that can be made at the present time and 

is fairly adequate if the water alone is considered. As a matter of 

fact, however, the waters in the zone of alteration contain sufficient 

half-bound carbon dioxide to allow the formation of bicarbonate 

almost exclusively, and in addition many of these waters contain 

considerable free carbon dioxide. The amount of free and half-bound 

carbon dioxide in the zone of alteration seems disproportionately large 

in relatioA to the amount of hydrogen sulphide, even if the ready 

oxidation of hydrogen sulphide is taken into account.

The apparent disparity between the total amount of carbon 

dioxide formed and the amount of sulphate removed may be due to 

the fact that all the carbon dioxide is not derived from the oxidation 

of hydrocarbons. Several reactions are known by which carbonate 

may be derived from inorganic sources. Hilgard * finds that a 

solution containing free carbon dioxide in the presence of sodium 

sulphate dissolves calcium carbonate and forms sodium bicarbonate 

and a precipitate of gypsum. ' This reaction would partly explain 

the disappearance of sulphate and the formation of carbonate, but 

it would not account for the formation of hydrogen sulphide. If it 

is assumed, however, that the hydrogen sulphide is derived through 

the reduction of sulphate, the presence of free carbon dioxide may 

be explained by the following reaction, first investigated by Be'champ :2

CaC03 + 2H2S = Ca(SH) 2 + H20 + C02 .

Under other conditions hydrogen sulphide may unite with calcium 

carbonate to form calcium sulphate and sulphur.3 It is evident, 

therefore, that the disappearance of sulphate and the formation of 

carbonate may be the net result of several reactions. As the strata 

in the oil fields of the San Joaquin Valley do not contain much 

calcium carbonate, the reactions just discussed have probably not 

entered largely into the development of the chemical character of 

the waters, but the possibility that they have played some part 

should be duly considered.

1 HHgard, E. W., The geologic efficacy of alkali carbonate solution: Am. Jour. Sci., 4th ser., vol. 2, pp. 

100-107,1896. 0

2 Bechamp, A., Rcchcrchcs sur Pdtat du soufre dans les eaux min6ralcs sulfurees: Annalcs chimio ct 

phys., 4th ser., vol. 16, p. 234, 1869. 

8 Spezia, G., Siill' origine del solfo nei giacimenli solflferi della Sicilia, Torino, 1892.
100 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. 

PEODUCTION OF GASES.

Whatever the reactions controlling the character of the oil-field 

waters may be, it is clear that sulphide, free hydrogen sulphide, 

carbonate, bicarbonate, and free carbon dioxide are formed. The 

particular significance of the gases hydrogen sulphide and carbon ^ 

dioxide will be briefly considered. /

Although the sulphide radicle is probably, first formed during the 

reduction of sulphate, it is ordinarily so unstable that hydrogen ' 

sulphide may be considered the final product. As this gas is found 

in many of the waters above the oil measures, and as these waters 

still contain some sulphate, it is probable that they are undergoing ^ 

alteration at the present time. The strong odor of hydrogen sulphide 

may readily cause overestimation of the amount present in a water. 

The greatest amounts that have come to the writer's attention, which v 

are reported in waters from the Eastside Coalinga field, do not exceed 

350 parts per million, and few waters carry more than 50 parts. As 

the complete reduction of 10 parts of sulphate would yield 3.5 parts < 

of hydrogen sulphide, it is evident that either the sulphate in- the 

upper waters is not all reduced directly to hydrogen sulphide or else the 

hydrogen sulphide is being remove^ from the solution nearly as 

rapidly as it is being formed. Some of it may unite with iron to 

form iron sulphide, which is precipitated. A small amount of hydrogen 

sulphide has been found in some of the hydrocarbon gas, but the total 

quantity accounted for in this way, is not great.

As hydrogen sulphide readily oxidizes to sulphur, even under 1 

very feebly oxidizing conditions, considerable amounts of it are v 

doubtless oxidized to sulphur and so removed by precipitation from 

the waters above the oil measures.1 . As < the strata above the oil \ 

measures have not been examined for sulphur this hypothesis can 

not be definitely proved, but commercial deposits of sulphur have 

been found near the south end of the Sunset field, in sec. 21, T. 11 

N., R. 23 W., in pockets and fissures in the McKittrick formation, 

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 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

1 The precipitation of sulphur by the oxidation of hydrogen sulphide is discussed in detail by Walter ^ 

F. Hunt (Origin of the sulphur deposits of Sicily: Econ. Geology, vol. 10, pp. 543-579,1915).
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 101

disseminated sulphur are not uncommon along the western edges 

of the Coalinga and Midway-Sunset fields, and it seems probable that 

these accumulations have been derived from sulphate by the reducing 

action of hydrocarbons.

The other important gaseous product of the reaction between 

sulphate and the hydrocarbons is carbon dioxide. As already 

stated, there is almost invariably sufficient carbonic acid to form 

bicarbonate exclusively in the waters in the zone of alteration, and 

in addition many of these waters contain a dissolved excess of free 

carbon dioxide. Unfortunately, the few determinations that have 

been made of the quantity of free carbon dioxide give no idea of the 

. amount present in the water underground. The writer has seen 

several waters so heavily charged that they effervesced when they 

were brought to the surface, and the dissolved gas may cause some 

waters to rise or flow. Free carbon dioxide is present also in many of 

the modified waters above the zone of alteration, but it has not been 

observed in the normal waters, in many of which a deficiency of 

carbon dioxide and the consequent presence of some normal carbonate 

are observable.

The hydrocarbon gas of many of the California fields contains a 

considerable proportion of carbon dioxide, much of which, in the 

writer's opinion, has probably been formed in the same manner as 

the, free, half-bound, and combined carbonic acid associated with 

the oil-field waters. In general, the gas in the shallower western 

portions of the Coalinga and Midway-Sunset fields contains more 

carbon dioxide than that in the deeper eastern portions. In other 

words, the natural gas near the outcrop generally contains more 

carbon dioxide than that several miles away. This is to be expected 

if the carbon dioxide is formed by the interaction of the sulphate 

water and the hydrocarbons, for most of the sulphate water enters 

the strata at their outcrops and it is therefore in this locality that the 

reaction should be most vigorous. The percentage of carbon dioxide 

in the gas generally ranges between 3 and 25, but the gas from a 

well about 600 feet deep in sec. 22, T. 19 S., R. 15 E., in the Eastside 

Coalinga field, contains 49 per cent of carbon dioxide. As carbon 

dioxide is inert it acts as a diluent in natural gas and lowers its 

heating value. The following table shows analyses of gas from wells 

in the Coalinga, Midway, and Sunset fields. 1 Analysis 7 represents 

gas from the deep eastern part of the Midway field; it will be noted 

that the carbon dioxide is low in this gas, and a number of other 

analyses of gas from the same locality show still smaller amounts.

1 A few other analyses are given by I. C. Alien and W. A. Jacobs (Physical and chemical properties of the 

petroleums of the San Joaquin Valley of California: U. S. Bur. Mines Bull. 19, p. 56,1912)
.102 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

Analyses of natural gas from Coalinga, Midway, and Sunset fields, Cal.

Carbon monoxide. ............................

Ethane........................................

Heating value (British thermal units per cubic 

foot).. . .....................................

1

5.1

1.1

92.8

.5

99.5

2

11.1

88.0

.9

.0

100.0 

037

3

34.2

.9

.3

61.8

.7

2.1

100.0 

663

4

20.0

.0

74.7

4.4

.9

100.0 

904

5

1Q 7

.0

73.8

5.7

.8

100.0 

892

6 .

20.0

.0

62.5

16.4

1.1

100.0 

971

7

7.6

.0

76.5

15.2

.7

100.0 

1,097

Coalinga field: '

1. Well in sec. 11, T. 19 S., R. 15 E. Analyzed by Kern Trading & Oil Co.

2. Several wells in sec. 25, T. 20 S., R. 14 E. Analyzed by U. S. Bureau of Mines. (Bur. Mines Bull. 

19, p. 56, 1912.)

3. Well in sec. 36, T. 20 S., R. 14 E. Analyzed by Smith. Emery & Co. Authority, Associated Oil Co. 

Midway-Sunset fields (samples 4,5,6, and 7 collected by G. S. Rogers in July, 1914, and analyzed by Q. A. 

Burrell, of the Bureau of Mines):

4. Well 5, Hale-McLeod Oil Co., sec. 8. T. 32 S., R. 23 E.

5. Well 6, Chanslor-Canfleld Midway Oil Co., sec. 31, T. 31 S., R. 23 E.

6. Well 5, Spreckles Oil Co., sec. 32, T. 12 N., R. 23 W.

7. Well 5, Honolulu Oil Co., sec. 6, T. 32 S., R. 24 E.

ALTERATION OF HYDROCARBONS BY WATER.

Despite the close association of petroleum and water in most oil 

fields the chemical relations of the two have apparently never received much attention. Many oil men have develop'ed from personal observation opinions concerning the effect of water on petroleum, but these opinions differ widely and little attempt has been 

made to corroborate them in the laboratory. In fact, petroleum 

chemists have been occupied so largely in working out the complex 

constitution of petroleum and the processes of refining it that we 

know little of the effect on petroleum of any of the substances with 

which it comes in contact underground. The great differences between petroleum in different regions are doubtless due largely to 

differences in the composition of the original organic matter and to 

differences in age and degree of metamorphism; but some of these 

broader differences, as well as most of the minor variations in the 

character of the oil from any one field, are probably due to the 

local action of natural agents. Of these oxygen and sulphur are 

probably among the most important.

When oil is exposed to the air for some 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 a so-called paraffin 

oil for several hours the oil becomes black and asphaltic.1 Similarly, if solid paraffin or a paraffin oil is digested with sulphur it 

becomes black and asphaltic,2 or if a light asphaltic oil of the type

1 Jenney, W. P., On the formation of solid oxidized hydrocarbons resembling natural asphalts by the 

action of air on refined petroleum: Am. Chemist, vol. 5, p. 359,1875.

»See KQhler, H., Die Chemie und Technologic der natiirliehen und kiinstlichen Asphalte, p. 119, Braunschweig, 1904.
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 103

'

produced in the Buena Vista Hills is used it also becomes heavier and 

more viscous and passes to a substance resembling solid asphalt. 

The chemical reactions involved in this change are probably of two 

kinds. A part of the sulphur may combine with certain oil constituents to form simple sulphur compounds or complex sulphur 

derivatives; another portion may unite with some of the hydrogen 

of the oil and pass off as hydrogen sulphide. By the loss of hydrogen 

a condensation or polymerization of the hydrocarbon molecules is 

effected, and this change is reflected in the increase in the gravity of 

the oil itself as it approaches solid asphalt. Oxygen acts in a similar 

way; some of it may be taken into combination to form complex 

acids or phenols and part of it may unite With the hydrogen of the 

oil to form water.1 Oxygen has been determined in so few analyses 

of oil from the San Joaquin Valley fields that its relation to the 

gravity of the oil, except in a very broad way, is not known; but 

the percentage of sulphur has been determined in a great many 

samples and appears to bear a fairly constant relation to the gravity 

of the oil. If more than 0.75 per cent of sulphur is present the specific 

gravity of the oil is generally greater than 0.945 (18° Baum6). The 

sulphur content of oils of 0.985 to 1.000 specific gravity (12° to 10° 

Baum6) is usually 1 per cent or more, whereas that of oils of 0.875 

to 0.905 gravity (30° to 25° Baum6) is generally less than 0.50 per 

cent.2

That oxygen and sulphur may be important agents in determining 

the character of petroleum is evident from the likelihood that the oil 

in its migration will encounter one or both of these common elements 

in some available form. Oxygen is probably the less important under 

ordinary conditions, but in some places the oil doubtless derives oxygen from oxygenated waters, and in others it may possibly be contributed locally by oxidizing agents such as manganese dioxide. The 

action of sulphur is probably more widespread, and sulphur is believed 

to be afforded abundantly by the reduction of the sulphate waters. 

There are other possible sources of sulphur, but they need not be considered here.

It is evident that in any one field the action of both oxygen and 

sulphur on the oil will be more or less localized, since ordinarily the 

quantity of these substances available is insignificant as compared 

with that of the petroleum. Most of the oil in the San Joaquin

1 Mabery, C. F., and Byerly, J. H., The artificial production of asphalt from petroleum: Am. Chem. 

Jour., vol. 18, p. 141,1896. See also Hausmann, J., and Pilat, 8., Studien iiber die Oxydation dor Petrolkohlenwasserstoffe: Gong, internat. p6trole Compt. rend. sess. 3, p. 378,1907.

* Analyses of oil from the oil fields of San Joaquin Valley are given in the following publications: Arnold, 

Ralph, and Andcrson, Robert, Geology and oil resources of the Coalinga district, Cal., with a report on the 

chemical and physical properties of the oils, by I. C. Alien: U. S. Qeol. Survey Bull. 398, pp. 264-272,1910. 

Alien,!. C.,and Jacobs, W. A., Physical and chemical properties of petroleums of the San Joaquin Valley 

of California: Bur. Mines Bull. 19,1912. Alien, I. C., Jacobs, W. A.,CrossfleId, A. S., and Matthews, R. R., 

Chemical and physical properties of the petroleums of California: Bur. Mines Tech. Paper 74,1914.
104 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL. '.-X

Valley fields has migrated up from lower formations, and there is 

reason to believe that some of the variation in its composition and 

properties is the result of changes that have taken place during this 

migration. The free chemical energy of reacting substances and the 

tune of contact are potent factors in chemical change, and these factors 

should be recognized in accounting for variations in the properties of ^.v 

oil that has migrated. An oil that is the first to traverse a given ^ 

course comes in contact with reacting substances at their highest 

potential, and therefore becomes changed more radically than does 

the oil that follows it at the same rate. As soon as these reacting 

substances have become exhausted, then oil may pass them unaffected. 

Again, oil that moves with extreme slowness and remains a very long ^ 

time in contact with reacting substances ma'y undergo changes just as 

marked as though it had moved more rapidly in a new channel. In 

general, therefore, that portion of the oil which migrated first or 

farthest will be the most altered. Moreover, the oil nearest the surface or nearest the outcrop of the oil-bearing zone may be further 

altered by fresh supplies of descending sulphate waters. Therefore, ; 

the oil around the upper edges of the main body should as a rule be 

the most altered or, in other words, the heaviest and most asphaltic. 

This reasoning is well borne out by the variations in the gravity 

of the oil in the valley fields. In the deeper portion of the MidwaySunset field, for example, the specific gravity of the oil ranges between 

0.933 and 0.875 (20° and 30° Baume*), but as the outcrop is approached the oil becomes heavier and most of the wells nearest the 

outcrop produce oil of specific gravity about 0.985 to 0.972 (12° to ^ 

14° Baum6). A part of this difference is probably due to the escape 

of the more volatile'constituents of the oil in the zone along the outcrop, but variation in gravity several miles away from the outcrop 

can hardly be explained in this way. Furthermore, as a general rule, 

to which there are local exceptions, the highest producing oil sand 

carries heavier oil than the sands below. In portions of the Coalinga, 

Midway, and Sunset fields the producing oil sands are overlain at a 

distance of several hundred feet by the tar-sand zone, which contains 

sands partly impregnated with a very heavy, viscous tar. Some of 

the sands in .this zone carry water of the modified type (sulphur 

water), and most of the tar sands become water bearing farther down 

the dip. So far as the writer knows this very heavy tar has never 

been analyzed, but the analyses of several samples o¥ oil of 0.993 

(11° Baume') gravity show about 1.15 per cent of sulphur, and it 

may be presumed thai the tar carries at least as much as this. In a 

general way the tar-sand zone marks the farthest limit of migration 

of the oil. It has been observed that oil which has migrated for 

some distance into sands that lie in angular unconformity with the
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 105

main oil zone generally becomes heavier with distance from the main 

body and finally passes to tar. Purely on the basis of field evidence, 

therefore, it would appear that among the important factors influencing the gravity of the oil are the distance that the oil has migrated, 

its present distance from the outcrop or its depth below the surface, 

and the extent to which it is or has been subject to contact with 

waters, especially meteoric (sulphate) waters.

There seems little doubt therefore that the local variations in the 

character of the oil are in part, at least, due to the action of sulphur 

and probably also of oxygen. Sulphate waters descending from the 

surface are to a large extent altered in the zone of tar sands, and the 

tar itself is thereby rendered still more asphaltic. To some extent, 

therefore, the tar sands may be conceived as protecting the main 

body of oil in the sands below. The same process goes on near the 

outcrop, although how far descending meteoric waters have affected 

the maui body of the oil since it attained its present position is a 

matter of conjecture. It seems more reasonable to suppose that the 

oil which migrated first and farthest was considerably altered by the 

water that had previously occupied the sands, and that most of its 

alteration took place before it had come to rest in its present position.

SOLUBILITY OF PETROLEUM CONSTITUENTS IN WATER.

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.

The solubilities of some of the simple gaseous hydrocarbons have 

been investigated, with the results shown in the following table. 

The solubility decreases with increasing temperature, and at 40° C. 

(104° F.) may be only two-thirds to three-fourths of the solubility 

at 20° C. (68° F.). The solubility is generally decreased by the 

presence of mineral salts in the water but is increased to some extent 

by pressure.
106 OIL-FIELD WATERS IK SAtf JOAQUlN VALLEY, CAL.

Solubility of certain gaseous hydrocarbons in water. 

[At 20° C.and 760 millimeters pressure, except propane, which is at 17.8° C. and 753 millimeters pressure.]

Name. ' Formula.

CH4.......

CaH6......

CsSs......

C4Hio......

C2H4......

C3H6 ......

Volumes

soluble

in 100

volumes

of water.

3.31

4.72

6.50

0

12.2

22.1

Authority.

Winkler.o

Do.

WinVlnr d

a Winkler, L. W., Die Loslichkeit der Gase in Wasser: Deutsche chem. Gesell. Ber., Band 34, pp. 1417- 

1421,1901.

6 Lebeau, Paul, Sur quelques proprie'tes physiques du propane: Compt. Rend., vol. 140, pp. 1454-1456, 

1905.

c Frankland, Edward, Ueber die Isolirung der organischen Radicale: Annalen der Chemie, Band 71, 

p. 171,1849. (Frankland states that butane is insoluble in water, but it is desirable that this early work 

be checked with the more refined methods now in use.)

d Winkler, L. W., unpublished data cited by Landolt-Bornstein, Physikalisch-chemische Tabellen, 

p. 604,1905.

e Von Than, Carl, Der Absorptionscoefflcient des Propylengases: Annalen der Chemie, Band 123, p. 187 

1862.

Methane and ethane are the predominating constituents of most 

natural gas, and water which has been in contact with gas is therefore 

likely to contain these hydrocarbons in solution. Propane has been 

found in some gas, but propane and butane are more commonly 

associated with light paraffin oil. Ethylene and perhaps propylene 

may occur in natural gas but are not common.

The hydrocarbons dissolved in the California oil-field waters are 

doubtless chiefly methane and ethane. Their presence in the water 

flooding an oil well is of little value in determining the source of that 

water, as they are rapidly soluble and may be taken up by the-water 

while it is being raised to the surface. Their presence in water from 

a wildcat well in which no oil or gas has yet been found might be 

taken merely as a suggestion of the proximity of petroleum, but 

certainly could not be considered conclusive evidence. Methane in 

particular is so widely distributed that its presence in a water has 

little significance; ethane and ethylene are more generally associated 

with petroleum deposits and therefore have somewhat greater diagnostic value. The presence of propane would be still more significant, 

but as this hydrocarbon is not common in California oil or gas it 

would seldom be a factor in practical work.

The more complex hydrocarbon derivatives that are soluble in 

water are chiefly compounds containing oxygen, the commonest of 

which are probably the naphthenic acids. All the waters near the 

oil zone in the San Joaquin Valley fields are alkaline, and the presence 

of organic acids may be determined by acidulating the water. Organic 

acids if present hi moderate amounts appear as a milky precipitate, 

but in some waters are present in so large amount that they separate 

out hi large oily globules. Many of the waters near the oil measures 

or in the diatomaceous shale below respond to this reaction.
CHEMICAL RELATIONS BETWEEN WATER AND HYDROCARBONS. 107

The naphthenic acids are the oxygen derivatives of the naphthenes 

(polymethylenes) and have the general formula CnH2n_202 . These 

compounds were observed by Hell and Medinger l in 1874, and in 

1890 Aschan 2 studied them in detail and gave them the name naphthene carboxylic acids. The naphthenes are prominent constituents 

of much of the Russian, Galician, and Roumanian oil, and when such 

oil is exposed to the air, especially in sunlight, the acids tend to 

form.3 These acids have been observed in waters associated with 

the Russian oil and have been studied by Kharitschoff,4 who in recent 

years has published a number of papers on their properties and nature. 

Inasmuch as the naphthenes are, according to Mabery and Hudson,5 

important constituents of the California and other American oils, it 

is probable that naphthenic acids are to be found in the water associated with these oils also. Fatty acids have been reported in oil-field 

waters by several of the earlier investigators,0 but their identification 

has since been questioned. However, Thompson 7 has more recently 

reported fatty acids (probably oleic and palmitic acids) in the waters 

from wells in the Grosny district, Russia. Kharitschoff,8 in waters 

from the same locality, reports carbonates of ammonia and the 

amines, and Schidkoff 9 reported in the oil itself small quantities of 

formic and oxalic acids. Hydroxyl derivatives of the nature of 

phenols have been reported in California and other oils,10 and these 

compounds may also be present in the oil-field waters. However, 

the naphthenic and perhaps the fatty acids, which may be grouped 

under the general term petroleum acids, are probably the commonest 

petroleum derivatives in oil-field waters. In alkaline waters these 

acids are doubtless present as alkali salts rather than as free acids.

So far as the writer knows, no attempt has been made to study or 

even to determine quantitatively the petroleum acids in California 

oil-field waters, although, as already stated, several chemists have 

detected them qualitatively. It has been suggested that the presence

i Hell, C., and Medinger, E., >Ueber das Vorkommen und die Zusammensetzung von Sauren<im Robpetroleum: Deutsche chem. Gesell. Ber., Band 7, pp. 1216-1223, 1874; Ueber die Oxydation dor im 

Eohpetroleum enthaltenden Saure, CnHaiOa: Idem, Band 10, pp. 451-456,1877.

' Aschan, 0., Ueber die in dera Erdol aus Baku vorkommenden Sauren von niedrigerem Kohlenstoffgehalt: Deutsche chem. Gesell. Ber., Band 23, pp. 867-875, 1890; Band 24, pp. 2710-2724,1891; Band 25, 

pp. 3661-3670,1892.

8 Ostrejko, R. A., Influence of sunlight and air on petroleum products (abstract): Soc. Chem. Ind. 

Jour., pp. 26, 345, and 645,1896.

< KharitschofE's papers appeared mostly in Russian journals, but adequate summaries of them are 

given in the Chemical Abstracts and in the Journal of the Chemical Society of London.

5 Mabery, C. F., and Hudson, E. J., On the composition of California petroleum: Am. Acad. Arts and 

Sci. Proc., vol. 36, pp. 255-283,1901.

«Potilitzin, A., Zusammensetzung des die Erdol begleitenden-und aus Schlammvulkanen ausstrb'menden 

Wassers (abstract): Deutsche chem. Gesell. Ber., Band 16, p. 1395-a, 1883.

' Thompson, A. B., Oil fields of Russia, p. 93, London, 1908.

s Kharitschoff, K. V., Ueber die Analyse des Wassers aus den Bohrlochern des Grosnyschen Bezirkes: 

Chem. Centralbl., vol. 78, p. 295,1907.

»Schidkoff, N., Acid content of Grosny petroleum ,and derivatives (abstract): Soc. Chem. Ind. Jour., 

vol. 18, p. 360,1899.

10 Mabery, C. F., The composition of American petroleum: Am. Chem. Soc; Jour., vol. 28, p. 426,1906.
108 OIL-FIELD WATERS IN SAN JOAQITIN VALLEY, CAL.

or absence of these substances in a water may serve to determine 

whether the water is from a horizon very near the oil zone or far 

above it, but the validity of such a distinction obviously depends 

on the ease and rapidity with which the 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. In refining oil the 

naphthenic acids are usually removed by the addition of caustic 

soda, for the alkali salts of these acids are readily soluble in water. 

The alkaline-earth salts of the naphthenic acids are somewhat less 

soluble. Hence, when alkali carbonate water of the type associated 

with the hydrocarbons in many parts of the San Joaquin Valley 

fields is brought in contact with oil containing petroleum acids it 

may be inferred that alkali naphthenates or soaps will readily form 

and go into solution. The oil-field brines, however, contain no 

alkali carbonates and only small quantities of alkaline-earth carbonates, and the rapid formation of organic salts in these waters 

would probably be less common. In washing the ether solutions of 

the acids Holde 1 uses a concentrated solution of sodium sulphate in 

order to avoid dissolving the acids. As the acids are thus practically insoluble in strong solutions of sodium sulphate, and as 

most of the shallower oil-field waters are essentially solutions of 

sodium sulphate and chloride, it seems probable that brief contact 

of a shallow water with the*oil would not suffice for the solution 

of these organic compounds.

It may therefore be inferred that alkali carbonate waters which 

occur near the oil zone or which have been mixed with the oil before 

being raised to the surface, are most likely to contain salts o£ the 

petroleum acids; that brines may or may not contain these compounds, and that normal top waters rarely contain them unless they 

have been allowed to stand in contact with the oil for some time. 

When oil stands exposed to the air, as in a sump, it is probable that 

naphthenic acids are formed by oxidation; hence most sump water, 

especially if it be of the alkali carbonate type, probably contains 

petroleum acids. Water which has been intimately mixed with oil 

in the form of an emulsion is also more likely to contain them. For 

these reasons it would seem that the value of petroleum acids as 

indicators of the original position of a water with respect to the oil 

zone is open to question. The rapidity with which they are extracted 

by different types of water must be investigated before their evidence 

can be positively relied on.

i Holde, D., and Mueller, E., TMe examination of hydrocarbon oils, p. 232, New York, 1915.
VALUE OF WATER ANALYSES TO OIL OPERATOR. 109

Those who desire to examine oil-field waters for petroleum acids 

may find the following simple test of value. This test, which depends 

on the green color of copper naphthenates, was recently devised by 

Kharitschoff.1

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. 

The filtrate is added with 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 shows the presence of petroleum acid in the tested water, and the degree of coloration allows to 

judge of its quantity.

VALUE OF WATER ANALYSES TO THE OIL OPERATOR.

Much of the foregoing discussion of the chemical relations of water 

and oil is necessarily hypothetic, owing to the unfortunate lack of 

chemical experimentation bearing on the subject, and although for 

the sake of simplicity only one broad hypothesis has been presented 

it is realized that discussjon is by no means closed. However, the 

conjectural nature of the conclusions advanced do not affect the 

validity of the main facts presented in this paper, which relate to 

the composition and chemical properties of the oil-field waters themselves. There is no question that the normal ground waters are 

very different from those close to or below the oil measures, and that, 

broadly speaking, the horizon at which a water occurs is indicated 

by its chemical composition. According to the few analyses published the water associated with the oil in most oil fields is characterized by the absence of sulphate, but probably in few regions do these 

waters present such marked contrast with the shallower waters as in 

the San Joaquin Valley, in which sulphate is especially abundant. 

It would seem peculiarly unfortunate therefore if the operators do 

not take advantage of these favorable conditions to use the character 

of the water as a general index of its horizon, for the need for some 

easy means of determining the source of the water flooding a well is 

yearly becoming more pressing.

The gradations between the strong sulphate waters near, the surface and the sulphate-free water near the oil measures have already 

been described. There is little question that in all the San Joaquin 

Valley fields the same order of change from the surface downward is 

to be observed, but the total extent of the change and the point 

above the oil at which it becomes complete are subject to variation. 

In the Westside Coalinga field all the data at hand indicate that the 

alteration of the water is not complete until the oil measures are 

reached, whereas in the Midway and Sunset fields completely altered

i Kharitschoff, K. V., Petroleum acids in boring waters: Petroleum Rev., vol. 28, p. 380,1913.
110 OIL-FIELD WATERS IN SAW JOAQUIN VALLEY, CAL.

waters are found several hundred feet above the oil zone. In these 

fields, moreover, waters containing only small amounts of sulphate 

are found comparatively near the surface, and the change in the 

character of the water with depth is therefore less marked. It may 

be inferred by analogy that similar conditions exist in the Lost Hills 

fields and in the other structures of this type which are believed to 

contain oil. In the Eastside Coalinga field very different conditions 

prevail, and all gradations from a pure sulphate water to a pure carbonate water may be observed. At the same time the waters near 

the oil measures in this field generally contain some sulphate, and 

may in fact contain more than the waters 500 feet above the oil hi 

the Midway and Sunset fields. These local variations do not affect 

the broad principles involved, but they are evidently of great practical importance, and only general conclusions can be drawn from an 

analysis until these variations have been worked out in the area in 

which the water occurs.

In .order to work out the detailed changes between successive 

water sands in each area it is necessary that as many reliable analyses 

as possible be placed on record. The analyses given in this report 

are sufficient to show the general type of the chemical changes that 

take place, but they are not intended to constitute a description of 

local conditions. It is believed by the writer that within small areas 

the chemical character of water from the same horizon is sufficiently 

constant to justify correlations on the basis of the analyses, and 

hence that when a sufficient number of analyses of reliable samples 

have been collected and made available for comparison the horizon 

of an unknown water may be closely estimated. Thus, one of the 

larger companies in the Midway field is making a practice of collecting 

water samples while drilling the well and preserving the samples, or 

analyses of them, for future reference. If the well later "goes to 

water" a sample of this water is analyzed and the analysis is compared with those of the waters encountered while drilling. A marked 

difference in composition between the waters first above the oil 

measures and the water flooding the well is taken to indicate that the 

water flooding the well is from strata below the oil or that it has invaded the oil sand at some other point and has migrated to the well. 

This use of water analyses is a matter of simple comparison and depends only remotely on the principles involved in the variation in the 

water as it approaches the oil zone. In the Midway-Sunset' 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, it is probable 

that this method will be essential in the accumulation of an adequate 

amount of data regarding the character of the water in the 500 feet 

or so on either side of the oil measures. In the Westside Coalinga
VALUE OF WATER ANALYSES TO OIL OPERATOR. Ill

field, however, fairly accurate estimates of the horizon of the waters 

can often be made on the basis of much less complete information.

A factor which might militate against the success of this method 

in some regions is the possibility that a flow of water may change in 

character during lapse of time. Wben«Large quantities of water are 

removed by one well from a sand, water which may be different in 

composition is drawn toward the well from distant parts of the sand. 

The variation in character is most noticeable when the water withdrawn from the sand is salty and is being replaced by fresh water, 

which enters at the outcrop. Replacement by fresher water is of 

course most likely t'o take place in shallow sands, and in general 

little or no change hi character takes place in flows from deep-lying 

sands.1 This condition should hold especially in the oil fields, where 

usually no effort is made to produce water from the deeper sands 

and where their normal contents are therefore disturbed as little as 

possible. Changes in the concentration of the water may be observed, but the relative proportions of the several constituents probably remain about constant, unless a considerable circulation is 

set up.

The variations in the chemical character of the waters as oil is 

approached may also be used as a guide in wildcatting. In many 

prospect holes this evidence will probably be put to little practical 

use, for marked changes in the character of the water generally do 

not occur more than a few hundred feet above the first showings of 

tar or gas. Contingencies may readily arise, however, in which 

corroborative evidence of the probable presence of hydrocarbons 

below will be of value. For example, if a well reaches a depth of 

4,000 feet, and there encounters water very similar in character to 

that near the surface, and if at this point serious drilling difficulties 

involving great extra expense are encountered, the advisability of 

proceeding farther may be questioned. On the other hand, if the 

water at this depth contains no sulphate ,the prospect of finding oil 

a short distance below is decidedly more encouraging. It should be 

pointed out, however, that commercial quantities of oil or gas may 

not be necessary to produce an altered water. The writer has a 

number of analyses of water from prospect wells of the Standard 

Oil Co. in southern California, and although the water in all the 

wells which produced commercial quantities of oil'is sulphate-free, 

that in several wells which gave only shows of oil also contains only 

small amounts of sulphate. However, in other unsuccessful wells 

the deep water, so far as the tests have been applied, contains more 

sulphate than the water near the surface. As far as commercial 

quantities of the hydrocarbons are concerned it seems probable that

» Sanford, Samuel, Saline artesian waters of the Atlantic Coastal Plain: U. S. Gcol. Survey Water-Supply 

Paper 258, p. 85,1910.
112 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

,<

when the evidence of the water is adverse it can be taken with more 

assurance than when it seems favorable.

The remarks in the preceding paragraph concerning the use of 

water analyses in prospecting are intended to apply only to the San t - 

Joaquin Valley region. If tfie writer's conception of the principles 

involved is correct, then, as oil is approached, similar variations in 

the character of the water should occur also in other regions. So 

far as is known, however, these variations have never been studied 

elsewhere, and in advance of definite knowledge it must be recognized 

that an extension of this method to other regions is based wholly on 

theory.

In using water analyses to predict conditions in unexplored dis- ^ 

tricts a complication arises from the fact that the rate of change in 

the composition of the waters and the distance above the oil measures 

at which sulphate disappears are different in different areas. The 

chemical character of the oil itself may be involved in these differ- j 

ences, but observations in the San Joaquin Valley fields indicate 

that stratigraphic and structural conditions are of prime importance. ^ 

If the bedding is sufficiently irregular to permit transverse migration 

of either the water or the hydrocarbons the water may be considerably altered some distance above the main body of oil.. If the 

course of the water is influenced by fault planes or unconformities 

the variatipns in its character may be irregular. Structural conditions influencing the freedom of circulation are also very important, * 

for they determine in a measure the quantity of sulphate that is 

brought down to be acted upon by the oil. In other words, a given 

quantity of oil may be able to reduce the sulphate in a large body of 

stagnant water, but if the water is in circulation and fresh supplies of 

sulphate are constantly penetrating to the oil measures the reduction 

may not be complete. Hence, if structural conditions in the area V 

in question are such as to prevent circulation, a high concentration 

of chloride is to be expected; sulphate will probably be present in 

rather small amount even in the shallower waters and may be entirely 

absent in the waters several hundred feet above the oil zone. If, on 

the other hand, the circulation is relatively free and the outcrop of 

the beds not far distant, chloride will probably be low and a consid- * 

erable concentration of sulphate may be present in the waters close 

above the oil measures. ' ,

In comparing the analyses of two different waters all the constituents must be taken into account; their relative values as criteria 

for comparison have been indicated elsewhere. General comparisons 

may be made of analyses reported in hypothetic combinations, but ^ 

much more satisfactory results are obtained if the analyses are recalculated and the comparison made on the basis of the reacting values 

of the radicles themselves. The practice of attempting to estimate
SUMMARY OF CONCLUSIONS. 113

the horizon of a water on the basis of a partial analysis can not be too 

strongly 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 as a means of distinguishing or correlating 

waters, chiefly because this constituent can readily be detected by its 

odor or by its ability to darken a silver coin immersed in the water. 

As many top waters contain hydrogen sulphide, whereas the waters 

below the oil contain it only in some localities along the border of 

the fields, this simple test may sometimes be of value. £)wing to 

the ease with which hydrogen sulphide is oxidized, however, it can 

not be regarded as a very stable constituent of the water and its 

value as a criterion for comparison is limited. A complete analysis 

is always the most satisfactory. In conclusion, it may be reiterated 

that an analysis is of no value in comparison unless the sample is 

properly taken and the analytical work accurately performed, for 

otherwise very misleading conclusions may be drawn.

SUMMARY OF CONCLUSIONS.

Water-bearing sands are generally encountered above, below, and, 

in many places, in the oil measures in the oil fields bordering the San 

Joaquin Valley. The strata are lenticular and the correlation of 

individual beds except within limited areas is impracticable. The 

high pressure of the water in many of the sands renders it difficult 

to prevent the water from invading the oil sands and thus greatly 

reducing their productivity.

Some of the ground waters are as salty as ocean water, but others 

are fresh. This difference is believed to be the result of'difference in 

freedom of circulation, which is controlled chiefly by the geologic 

structure. Where the structure prevents free circulation the ground 

water is salty, but where it does not and circulation is relatively free 

meteoric water has entered the beds and replaced much of the strong 

chloride water originally present. The ground water near the surface 

and near the outcrops of the beds is comparatively fresh, but the 

content of chloride generally increases with depth and with distance 

from the outcrop. The deeper waters trapped in structural'troughs, 

like the Midway syncline, closely resemble ocean water in most 

respects and are believed to be only slightly altered connate water or 

fossil sea water.

The surface waters and shallow ground waters and also the deeper 

ground waters outside the oil fields on the west side of the San Joaquin Valley contain much sulphate. In the oil fields, however, the 

content of sulphate decreases with depth and ground waters near and 

60439° Bull. 653 17 8
114 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, CAL.

in the oil measures are practically free from sulphate. This decrease 

in sulphate is attended by a corresponding increase in carbonate, and 

in districts in which chloride is not abundant the waters near the oil 

measures are nearly pure carbonate waters. Where chloride is the 

predominating acid radicle, even in the shallower waters, carbonate 

is unimportant, and the chief change in character with depth is due 

to the disappearance of the sulphate. Sulphide and hydrogen sulphide appear near the horizon at which sulphate begins to decrease 

and are present in many of the waters above the oil measures, but the 

complete disappearance of the sulphate and of the sulphide are coincident. The amount of sulphide in the deeper waters is roughly proportional to the amount of sulphate in the waters directly above 

them, or nearer the surface.

Calcium and magnesium predominate in many of the surface waters, but sodium and potassium greatly predominate in the deeper 

waters. Most of the waters associated with the oil are therefore 

variously proportioned mixtures of solutions of alkaline carbonates 

and chlorides, the proportion of carbonate depending chiefly on the 

extent to which meteoric water is able to enter at the outcrop. Besides the change in character with depth the oil-field waters therefore 

exhibit progressive variations with distance from the outcrop, the 

predominantly carbonate waters being found near the outcrop and 

the predominantly chloride waters farther away. The final stage in 

this gradation is represented by the very salty waters, which are 

believed to be connate. Coincident with these changes in composition is a great increase in the total amount of dissolved solids.

The decrease of sulphate, appearance of sulphide, and increase of 

carbonate in the waters as the oil zone is approached all point to 

reactions between the oil-field waters and constituents of the oil or 

gas. It is probable that sulphate is reduced to sulphide by certain 

oil constituents whose carbon is simultaneously oxidized to products 

which eventually yield carbonate, though the stages involved,in these 

reactions and the conditions under which they take place are not yet 

understood. These reactions not only alter the character of the 

waters but they also produce the gases carbon dioxide and hydrogen 

sulphide. Carbon dioxide, presumably thus produced, occurs in the 

natural gas of these fields in amounts ranging from 5 to more than 

30 per cent. The greatest proportions of carbon dioxide are usually 

found in gas near the outcrop, where sulphate water can most readily 

enter the beds and where the reaction would naturally be vigorous. 

A large part of the hydrogen sulphide formed is probably changed to 

sulphur, some of which apparently reacts again with the oil to make 

it heavier and more asphaltic. It is significant that the oils contain-
SUMMARY OF CONCLUSIONS. 115

ing the largest proportion of sulphur are in general the heavy oils 

close to the surface or to this outcrop of the oil measures.

The marked differences in chemical composition between the waters 

close to the oil measures and those at higher levels are believed to 

afford a means of estimating the position of a water with respect to 

oil. This knowledge should be useful in determining the source of 

water flooding an oil well and also in prospecting for oil or gas. The 

distance above the oil measures at which the marked changes in the 

composition of the water occur depends on local conditions, which 

remain to be determined in each field. The order of change, however, 

has been found to be uniform, and it is believed that the use of analyses in estimating the position of a water with regard to the oil will 

prove valuable to those engaged in the exploitation and development 

of the California oil fields.

List of water analyses.

Coalinga field: 

Acorn Oil Co. ...................

California Oil & Gas Co .........

California Oilfields (Ltd.) .......

Coalinga Homestake Oil Co .....

Diaz Creek. .....................

Kern Trading & Oil Co. .........

Lucille Oil Co.. .................

Nevada Petroleum Co. ..........

Ozark Oil Co....................

PremierOil Co..... .......

Record OilCo...................

Santa Rosa Oil & Development

Co. 

Section Seven Oil Co. ...........

Standard Oil Co........... ......

Traders Oil Co.. ................

Union Oil Co.. ...................

WellNo.l. ...............

WellNo.2N...... ........

WellNo. 21. ..............

Water well... . ............

Oil well.. ....... ..........

Oilwell........ ...........

Oilwell...................

WellNo.2..... ...........

WellNo. 16. ..............

WellNo. 16....... ........

WellNo. 37... ............

WellNo. 5... .............

WellNo.l................

WellNo. 15......... ......

WellNo. 31...... .........

Oilwell...................

Oilwell...................

Oilwell...................

Oilwell...................

Water well. ...............

Oilwell...................

Oilwell...................

Oilwell...................

WellNo.l................

WellNo.3........ ........

WellNo.3........ ........

WellNo. 3................

WellNo. 5................

Water well. ...............

WellNo. 5... .............

Domengine No. 1.... ......

Water well No . 3. .........

Oilwell...................

Water well No. 2. .........

La VistaNo.4. ...........

Sec.

2

30

30

36

36

36

36

18

6

10

14

26

27

29

34

34

34

2

26

26

35

11

13

15

25

25

25

6

20

30

26

94

22

12

7

27

27

28

36

36

24

4

Locatio

T.

20 S.

'208.

20 S.

20 S.

20 S.

20 S.

208.

20 S.

21 S.

19 S.

19 S.

19 S.

19 S.

198.

198.

19 S.

198.

208.

208.

208.

198.

198.

208.

208.

208.

208.

208.

208.

20 S.

21 S.

208.

20 S.

208.

198.

198.

218.

20 S.

18 S.

188.

198.

19 S.

198.

208.

208.

a.

R.

14 E.

15 E.

15 E.

HE.

14 E.

14 E.

14 E.

15 E.

15 E.

15 E.

15 E.

15 E.

15 E.

15 E.

15 E.

15 E.

15 E.

15 E.

14 E.

14 E.

14 E.

15 E.

15 E.

14 E.

14 E.

14 E.

14 E.

14 E.

14 E.

15 E.

15E.

15 E.

14 E.

14 E.

15 E.

14 E.

15 E.

15 E.

15 E.

15 E.

15E.

15 E.

14 E.

15 E.

Analysis No.

46

61

62

74

75

76

77

10

12

 15

16

27

35

34

40

36

41

39

29

80

2

37

42

19

43

22

OO

24

1

64

63

20

91

is

17

30

60

7S

79

38

9

11

28

70

76

76

Q1

01

Q1

81

r.Q

10

(19

02

«6

fiQ

flQ

70

09

70

09

06

Q1

57

09

70

Pi9

70

M

03

03

57

fi9

02

02

02

fift

01

D|

59

69

en

CQ

66
116 OIL-FIELD WATERS IN SAN JOAQUIN VALLEY, GAL. 

List of water analyses Continued.

Owner.

Midway and Sunset fields:

Good Roads Oil Co..............

Honolulu Oil Co ................

Kern Trading & Oil Co..........

Midway Northern Oil Co. .......

M.J.&M.M.OilCo..... .......

North American Oil Consolidated Co. 

Potter Oil Co.. ..................

San Emigdio Creek Q. ...........

Standard Oil Co.. ...............

Stratton Water Co. .............

Sunset Security Oil Co ..........

Union Oil Co.... ................

Other fields: 

Associated Oil Co. ..............

Lindsay Incorporated Oil Co. ... 

Petroleum Development Oil Co. 

Standard Oil Co.................

Designation.

WellNo.l. ......:........

Pioneer Midway No. 7 .... 

WellNo.2......:.........

California Amalgamated 

Well No. 2. 

California Amalgamated 

Well No. 3.

WellNo.14...............

WellNo.6................

Oil well.... ...............

WellNo.6. ...............

Oil well.. .................

WellNo. 5. ...............

Well M.J.6......... ......

WellNo. 71. ..............

WellNo.2................

WellNo.6. ...............

WellNo.6. ...............

WellNo. 7. ...............

WellNo. 2. ...............

WellNo. 3. ...............

WellNo. 3. ...............

WellNo.l................

WellNo.l................

WellNo.l................

WellNo. 3........ ....... :

WellF.. ..................

WellNo.l................

WellNo. 38. ..............

Well No. 3.. ..............

WellNo.l................

Oil well.. ...... ...........

Water well. ................ 

WellNo.l................

Location.

Sec.

35 

30 

32 

35

31

29 

25 

18 

9 

15 

12 

10 

23 

31 

28 

28 

32 

32 

36 

16

15

22 

12 

12 

14 

20 

24 

28 

30 

30 

7 

26 

29 

13 

5

18 

13 

2

7 

4 

5 

27

' T.

318. 

218. 

318. 

328.

328.

UN.

328. 

318. 

318. 

328. 

UN 

328. 

ION. 

12 N. 

318. 

318. 

12 N. 

12 N. 

12 N. 

328.

31 S.

31 S. 

32 S. 

328. 

328. 

328. 

328. 

328. 

328. 

328. 

328. 

12 N. 

UN. UN.

318.

308.' 

268. 

308.

27 S. 

29 S. 

28 S. 

288.

a.

22 E. 

23 E. 

23 E. 

23 E.

24 E.

24 W. 

23 E. 

22 E. 

22 E. 

23 E. 

24 W. 

24 E. 

23 W. 

23 W. 

23 E. 

24 E. 

23 W. 

23 W. 

24 W. 

23 E.

22 E.

23 E. 

23 E. 

23 E. 

23 E. 

24 E. 

23 E. 

24 E. 

24 E. 

24 E. 

23 E. 

24 W. 

23 W. 

24 W. 

25 E.

21 E. 

20 E. 

21 E.

21 E. 

28 E. 

27 E. 

27 E.

Analysis No.

65 

50 

49 

26

71

5 

68 

4 

44 

67 

73 

51 

6 

57 

47 

32 

14 

58 

56 

66

45 

7 

48 

25 

53 

70 

54 

69 

55 

81 

82 

31 

72 

59 

53 

13

89 

88 

3 

83 

87 

86 

84 

85 

52

Page.

76 

73 

73 

63

77

57 

77 

57 

70 

77 

77 

73 

57 

74 

73 

66 

59 

74 

74 

76

70 

57 

73 

63 

74 

77 

74 

77 

74 

83 

83 

66 

77 

74 

74 

59

85 

85 

57 

85 

85 

85 

. 85 

85 

73

a San Emigdio Land Grant. i> Bakersfield.
INDEX.

A. Page.

Absorptive capacity of various rocks......... 13.

Acids, petroleum, nature and occurrence of. 100-109 

petroleum, test for....................... 109

Acknowledgments for aid.................... 6-7

Alkalies, distribution and significance of..... 41-42

Alkaline earths, distribution and significance

of................................ 42-43

Alkalinity, primary and secondary, use of the

terms............................ 38

Alteration of hydrocarbons by water....... 102-105

Alteration of waters by hydrocarbons....... 50-52,

93-102 

Altered waters, analyses of............... 67-77,85

limits of................................. 52

position of............................... 52

use of term.............................. 51

Aluminum, distribution and significance of.. 46 

Aluminum and iron, method of determining.. 32 

Ambrose, W. A., acknowledgment to........ 7

Analyses of waters, alphabetical list of, by

fields.......................... 115-llC

need for................................. 7-8

sourcesof................................. 40

value of, to the oil operator............' 109-113

Analysis, constituents to be determined by... 31-32 

statement of............................. 32-35

B.

Bacteria, decomposition of sulphate by...... 94-96

Barium, occurrence of.................^..... 94

Bicarbonate, reported as carbonate.......... 47

See also Carbonate. 

Boron, occurrence of......................... 47

" Bottom water," use of term................ 17

Brine, analyses of........................ 71-74,85

effect of adding primary alkaline water to. 90 

Brines, average concentration of............. ,90

Bromine, occurrence of...................... 47,94

Brown, W. E., acknowledgment to.......... 7

 Buena Vista Hills, ground water in.......... 28-29

Bush, R. D., acknowledgment to............ 7

C.

Calcium, ratio of, to magnesium in different

types of water................... 43,92

See also Alkaline earths. 

Calcium carbonate, action of carbon dioxide

and sodium sulphate on......... 99

Calcium sulphate, reduction of.............. 96

Carbon dioxide, formation of.............. 101,114

Carbonate, distribution and significance of... 6,

44-45,114 

formation of............................. 98-99

source of................................. 11

substitution of, for sulphate...........

Carbonate-sulphate ratio, use of... .......... 48-49

Chloride, distribution and significance of.... 44,114

variation in............................. 86-87

Circulation, conditions governing............ 14

Classification of waters....................... 41-52

Coalinga oil field, ground waters in.......... 26-27

location and importance of.............. 8

Colloids, presence of......................... 31-32

Comparison of waters, criteria for............ 48-49

Concentration of waters, variation in........ 40

Conclusions........................... 5-G, 113-115

Connate water, characteristics of............. 50

mixing of meteoric waters with.......... 80

predominance of alkalies in.............. 42

probable migration of................... 61

Cretaceous rocks, oil in...................... 10

Crumpton, T. J., acknowledgment to........ 7

D.

Dearin, J. H., acknowledgment to........... 7

Depth o.f water-bearing rocks................ 16

Dinsmore, S. C., acknowledgment to........ 7

Dole, R. B., acknowledgment to............. 7

Drainage of San Joaquin Valley............. 9

E.

Eastside Coalinga field, ground waters in.... 27

position of............................... 26

"Edge water,'' use of term.................. 17

Elliot, J. E., acknowledgment to............ 7

Equivalents for analytical units............. 33

F.

Faulkner, E.G., acknowledgment to........ 7

Fellows, Midway field, partial analyses of oilwell waters from................. 87

Flow of water, change in character of........ Ill

G.

Gas pressure, nature of...................... 18-19

Gases, production of....................... 100-102

Gaylord, E.G., acknowledgment to......... 7

Geography of San Joaquin Valley............ 9

Geology of San Joaquin Valley............... 9-11

Gravity of oil, variation of, with depth.... 104M05

Greer, W. A., acknowledgment to........... 7

Ground water, altered, analyses of........ 67-77,85

depth to................................. 16

lower limit of........................... 16

mineral matter dissolved in.............. 20

modified, analyses of................. 64-66,81

normal, analyses of................... 58,59-63

reversed type of, analyses of.......... 67-70,85

salt, origin of............................ 20-23

time when entrapped.........."...... 24-25

117
118 INDEX.

H.

Hardness, chemical basis of.................. 38

Head of ground waters, decrease of.......... 17-18

low, reasons for......................... 15-16

range of................................. 17

Hern, J. J., acknowledgment to.............. 7

Hydrocarbons, alteration of, by water..... 102-105

alteration of waters by.................. 93-102

reduction of sulphate by................. 96-97

solubility of, in water.................. 105-109

Hydrogen sulphide, detection of............ 113

formation of........................ 45,46,100

occurrence of, in ocean water............ 95-96

oxidation of............................. 95,98

II ydrostatic pressure, nature of.............. 18

Iodine, occurrence of......................... 47,94

Ionic form, conversion of analyses to......... 34-35

conversion of analyses from, to reacting

values........................... 35-37

Iron, distribution and significance of......... 46

Iron and aluminum, method of determining. 32

J. 

Jurassic rocks, nature and distribution of.... 10

K. 

Kern River oil field, ground water in........ 29

location and importance of............... 8

water pressure in........................ 19

Kern Trading & Oil Co., water analyses from. 40 

Kharitschoff, K. V., test for petroleum acids

by............................... 109

Kirwan, M. J., acknowledgment to.......... 7

L.

Lenses, sand, three classes of.............. 14,15-16

Lombard!, M. E., acknowledgment to........ 7

Lost Hills field, ground water in............. 27

M.

McKittrick field, ground water in............ 27-28

Magnesium, ratio of, to calcium in different

types of water................... 43,92

See also Alkaline earths. 

Magnesium sulphate, reduction of........... 97

Meteoric water, characteristics of............ 50

concentration of......................... 90

Methane, inactivity of....................... 97

solubility of............................. 106

source of, in waters...................... 106

Midway-Sunset oil field, ground water in.... 28-29

location and importance of............... 8

range of altered water in................. 7-8

Midway Valley, ground water in............ 28

Migration of oil, changes during.............. 104

Mineral solids, amount of.................... 47

Minerals, presence of, in ground water....... 29-30

Mixed type of ground water, analyses of.. 75-77,85 

relations of.............................. 88-93

Modified water, limits of..................... 52

position of. '. .............................. 51-52

use of term.............................. 50-51

N.

Naphthenic acids, nature and occurrence of. 106-109 

Natural gas, composition1 of................ 101-102

Nitrate, occurrence of........................ 47

Page. 

Normal water, limits of.....................: 52

position of............................... 51

use of term.............................. 50

O. 

Ocean water, analysis of..................... 73

reduction of sulphate in................. 95-96

O'Donnell, T. A., acknowledgment to....... 7

Oil, indications of, from character of waters.......................... 6,109-113

pressure of water on..................... 12

source of................................. 10

See also Hydrocarbons. 

Oil fields, location and importance of........ 8

Oil wells, top water from, analyses of..... 58,59-63

Orcutt, W. "W., acknowledgment to......... 7

Organic matter, omission of, from analyses.. 47-48 

Outcrop, changes in waters with distance

from............................. 90-91

Oxygen, action of, on oil................... 102-105

P. 

Pack, R. W., acknowledgment to............ 6

Paine, Paul, acknowledgment to............ 7

Palmer, Chase, acknowledgment to.......... 6-7

Petroleum constituents, solubility of, in

water.......................... 105-109

Petroleum Development Co.'s well, field

assay of water from.............. 84

Potassium, method of determining.......... 32

ratio of, to sodium in different types of

water............................ 92,93

retention of, by soils..................... 42

See also Alkalies. 

Pressure. See Head. 

Propane, significance of, 'in waters........... 106

Properties, reactive, determination of........ 37-40

R. 

r, use of the symbol.......................... 36

Radicles, factors for calculating.............. 34

recalculation of.......................... 34-35

Reacting values, calculatipn of.............. 35-37

Reaction, properties of, determination of.... 37-40

Reaction coefficients, use of................. 36-37

Relations areal, of the types................ 86-93

vertical, of the types.................... 78-85

Requa, M. L., acknowledgment to........... 7

Reversed type, use of term.................. 51

Rock pressure, nature of.................... 18

S. 

Salinity, chloride, and sulphate, ratio of..... 40

Salinity, primary and secondary, use of the

terms........................... 38

Salt, distribution of, in ground waters....... 6,113

influence of, in the genesis of petroleum... 25 

Salt waters, origin of..................... 20-23,26

Samples of water, collection of............. 8,30-31

Sands, dry, danger of water from............ 15

dry, nature of........................... 15-16

oil, geologic structure of.................. 10-11

oil and water, relative positions of....... 16-17

unfounded distinctions between..... 13

texture of, influence of................:.. 13

water below oil in....................... 17

water, correlation of..................... 16

Shallow-well waters, analyses of.......... 58,59,85

Silica, distribution and significance of....... 47

Silver coin, detection of hydrogen sulphide by 113
INDEX. 119

Sodium, method of determining............. 32

ratio of, to potassium in different types of

water........................... 92,93

See also Alkalies. 

Sodium sulphate, reduction of, experiments

on.............................. 97

Sodium sulphide, occurrence of.............. 46

Stabler, Herman, acknowledgment to....... 6-7

Standard Oil Co., water analyses from....... 40

Starke, E. A., acknowledgment to.......... 7

Structure, relation of, to distribution of salt

water........................... 23-25

Sulphate, content of, in ocean water......... 44

distribution and significance of. 6,43-44,113-114 

gradation of, in depth................. 109-110

reduction of............................. 93-98

source of................................. 11-12

substitution of carbonate for............ 88-89

Sulphate-free waters, occurrence of.......... 93-94

Sulphide, distribution and significance of.... 4,5-46

oxidation of............................. 98

Sulphur, action of, on oil.................. 102-105

formation of, from hydrogen sulphide ...................... 95,98,99,100-101

Sulphur waters, position of.................. 46

Surface waters, analyses of............... 55-57,85

Synclines, salt water in..................... 23-24

T. Page. 

Temperature, range of....................... 19

use of, in prospecting.................... 19-20

Tertiary formations, nature and distribution

of............................... 10

"Top water," use of term................... 17

Tough, F. B., acknowledgment to........... 7

Types of ground water, areal relations of.... 86-93

vertical relations of...................... 78-85

V.

Van der Linden, B. H., acknowledgment to. 7 

Volatile matter, omission of, from analyses.. 47-48

W. 

Wallace, W. M., acknowledgment to....... 7

Water, connate, kinds of.................... 21

connate, use of term..................... 21-23

determination of source of............... 6,8

difficulty with, in oil wells.............. 5

ground,circulation of.................'.. 11-12

pressure of 1,000-foot column of.......... 15

salt, association of, with petroleum...... 25-26

distribution of, governed by structure 23-25 

Wells, water, causes of pressure in........... 18

Westside Coalinga field, constancy of conditions in.......................... 7

ground waters in ........................ 27

position of............................... 26

o