RI

bureau of mines

report of investigations 5642

OIL RECOVERY AND FORMATION DAMAGE

IN PERMAFROST, UMIAT FIELD, ALASKA

By Oren C. Baptist

1910

THE BUREAU OF TN ANNIVERSARY

UNITED STATES DEPARTMENT OF THE INTERIOR
OIL RECOVERY AND FORMATION DAMAGE

IN PERMAFROST, UMIAT FIELD, ALASKA

By Oren C. Baptist

, , ~ , * ~report of investigations 5642

UNITED STATES DEPARTMENT OF THE INTERIOR

Fred A. Seaton, Secretary

BUREAU OF MINES

Marling J. Ankeny, Director
Baptist, Oren C

Oil recovery and formation damage in permafrost, Umiat

Field, Alaska. [Washington] U. S. Dept. of the Interior, Bureau of Mines [1960]

ii, 22 p. illus., maps, tables. 27 cm. (U. S. Bureau of Mines.

Report of investigations, 5642)

Bibliography: p. 22.

i. Oil fields-Alaska-Umiat Field. I. Title. (Series)

[TN23.U7 no. 5642] 622.06173

This publication has been cataloged as follows:

U. S. Dept. of the Int. Library

--
CONTENTS

Page

Summary and conclusions.................................... 1

Introduction............................................... 2

Acknowledgments .................................... .. 3

Nomenclature... ........................................... 5

Reservoir characteristics and conditions...t ............... 5

Producing sands ....... ...... .................. 5

Formation temperatures ............................ 6

Reservoir pressures ................................... 7

Evidence of well damage .............................. 7

Experimental methods and procedures........................ 8

Samples analyzed................................... 8

Crushed samples ..................................... 8

Plug samples....... . ... .............................. 9

Radial samples ..... .................. 10

Discussion of results .............................. 12

Clay mineral identification ......................... 12

Formation damage related to clay swelling or

permafrost....... ................................. 14

Reduction of oil permeability and oil recovery due

to freezing of interstitial water................. 18

Oil recovery by depletion drive under permafrost

conditions .. ...... ......... ........ 19

References................................................................ 22
ii

ILLUSTRATIONS

Fig Page

1. Map of Umiat area showing location of wells ......... 4

2. Diagram of apparatus used to determine oil recovery

under simulated permafrost conditions............. 10

3. Diagram of cell of apparatus used to determine oil

recovery under simulated permafrost conditions..... 11

4. Relation of water permeability to gas permeability... 16

5. Relation of gas permeability to irreducible-water

and irreducible-brine saturations ................. 16

6. Average relation of gas permeability to irreduciblewater saturations, Umiat and four reservoir sands

in Wyoming ............................ 16

7. Average relation of saturation pressure to oil

recovery at 26° F ...... ........ .................... 21

TABLES

1. Summary of permafrost data........................... 6

2, Summary of X-ray diffraction results.... .... ,... 13

3. Physical properties and swelling capacity of upper

and lower Grandstand sands and sands in the Ninuluk

and Chandler formations............................ 15

4. Oil-recovery experiments, solution-gas expansion

followed by gas drive, temperatures 260 and 75° F.. 19

5. Oil-recovery experiments, solution-gas expansion

from three saturation pressures, temperature 26° F. 20
OIL RECOVERY AND FORMATION DAMAGE IN PERMAFROST,

UMIAT FIELD, ALASKA2/

by

Oren C. Baptist 2/

SUMMARY AND CONCLUSIONS

Umiat field contains the largest accumulation of oil discovered so far in

Naval Petroleum Reserve No. 4 in Arctic Alaska. The Umiat anticline was

tested with 11 wells; 6 produced oil in varying quantities. Behavior of the

wells during testing was unpredictable. For example, one well was abandoned

as a dry hole after all tests failed to recover any oil, yet an offset well,

only 200 feet from the dry hole, produced 400 barrels of oil a day. The main

oil reservoirs are less than 1,000 feet deep and are in the permanently frozen

zone (permafrost). Reservoir pressures are low, and most primary production

will be by expansion of gas-in-solution in the oil.

Because of the unusual reservoir conditions and the difficulties encountered in drilling and completing the wells, the Department of the Navy asked

the Federal Bureau of Mines to make laboratory studies of the reservoir sand

to determine the cause of well plugging and to provide laboratory information, to be used as an aid in estimating oil recovery from frozen reservoir

rocks under solution-gas expansion from low-saturation pressure conditions.

Core samples were tested in the laboratory to determine the physical

properties, clay content, and capillary behavior of the sands and their susceptibility to water damage. Larger core samples were tested under simulated

permafrost conditions to determine the effect of freezing of interstitial

water on oil recovery and the effect of gas-oil ratio on oil recovery, when

the oil is produced by solution-gas expansion from low saturation pressures.

Also determined were the effects of freezing of interstitial water on relative

permeability to oil and on oil recoverable by gas drive after solution-gas

expansion. The major results and conclusions are discussed.

Severe formation damage noted in some wells was not due to swelling

clays, as supposed previously. No swelling clays were found in the 36 sandstone samples examined by X-ray diffraction methods. Other laboratory tests

confirmed that the reservoir sands have only low to moderate sensitivity to

1/ Work on manuscript completed February 1960.

2/ Supervising petroleum engineer, Bureau of Mines, Laramie, Wyo.
2

water. Laboratory results supporting these conclusions are summarized as

follows: The predominant clay minerals are illite and kaolinite; the bulkswelling capacity of the crushed sample is low, the ratio of water permeability to air permeability indicates moderate water sensitivity, and the position

of the average curve showing the relation of air permeability to irreducible

water saturation is that of sand having moderate sensitivity.

The failure of some wells to produce now seems to be the result of increased water saturation in the permafrost. Warm mud used in drilling the

wells apparently thawed the surrounding formation and allowed water filtrate

from the mud to invade the sand. When mud circulation ceased before a formation test, the invaded zone cooled rapidly, and the invading water soon froze,

effectively plugging the sand.

Comparison of laboratory tests at temperatures of 26°, 70°, and 75° F.

shows that freezing of interstitial water reduces both oil flow and oil recovery more than that due to increased oil viscosity. Freezing of interstitial water increases the volume of the water by several percent, thus reducing

effective permeability to oil. It is not clear if this increase in immobile

saturation, resulting from the freezing of water, also causes the decrease in

oil recovery.

Recovery tests were made at 26° F. with the oil originally gas-saturated

at 50, 100, and 150 p.s.i.g. Since the gas-oil ratio was directly proportional to saturation pressure, oil recovery also should have been directly

proportional to pressure if all the gas released from solution were equally

effective in displacing the oil. However, this was not true. Increasing the

saturation pressure by 200 percent (from 50 to 150 p.s.i.g.) increased the oil

recovery by only 55 percent (from 29 to 45 percent of initial oil).

The first gas released from solution expands as the pressure is lowered

below the saturation pressure and displaces an equal volume of oil by pistonlike action, whereas the gas released after a high gas permeability is obtained displaces very little oil by viscous drag. Also, a small mass of gas

released at low pressure expands to a large volume so that enough gas is available at low saturation pressures to complete the pistonlike-action phase of

production and still have enough gas to produce additional oil by viscous

drag. Consequently, a substantial recovery of oil can be expected from the

Umiat field by using the depletion-drive method, even though the reservoir

pressures are unusually low.

INTRODUCTION

President Harding created Naval Petroleum Reserve No. 4 in 1923 by

Executive Order. This reserve, which has an area of 37,000 square miles, lies

in northwestern Alaska between the Brooks Range and the Arctic Ocean.

The Department of the Navy, Office of Naval Petroleum and Oil Shale

Reserves, conducted an extensive exploration program from 1944 through 1953

to appraise the oil potential of Naval Petroleum Reserve No. 4 and surrounding
3

3'

area (12, p. 1).- This exploratory program located several structures having

good petroleum possibilities, and several were tested with one or more wells.

The largest accumulation of oil discovered was in the Umiat field, where estimates of recoverable reserves range from 30 to over 100 million bbl. (5, 10);

the average of these estimates is about 70 million bbl. (12, pp. 135 and 147).

The Umiat field is close to the eastern boundary of the Reserve, (the

Colville River) on the Arctic Coastal Plain, about midway between Brooks Range

and the Arctic Ocean. Umiat is about 180 miles southeast of Point Barrow, one

of the two permanent settlements in the Reserve and the main supply point

during the exploratory program.

4/ The Umiat structure was tested by drilling 11 wells (see fig. 1);~ 6

produced oil in varying amounts. The first three wells were drilled with conventional rotary methods, using water-base mud. Good shows of oil were noted

in cores from two wells, yet the hole was repeatedly bailed dry without yielding either oil or water. Later wells were drilled with cable tools, using a

strong brine as drilling fluid; these wells produced considerably more oil

than those drilled with the rotary rig.

Oil was found at depths of 275 to 1,100 feet. The depth to the bottom of

the permafrost ranges from 770 to 1,055 feet, and most of the oil is in the

permafrost. Reservoir pressures are very low, the oil contains very little

gas, and the sands are supposed to contain large amounts of montmorillonite

clay, which swells when contacted with fresh water (, 6).

Because of unusual reservoir conditions in the Umiat field and difficulties encountered in testing and completing the wells, the Navy asked the

Bureau of Mines to make laboratory studies which would assist them in developing the field and in estimating petroleum reserves. The main objectives of

this test program were to determine the cause of plugging in the wells drilled

with rotary tools and to estimate oil recovery from frozen sand by depletion

drive when the oil is gas-saturated at low pressures. This report gives the

results of these studies, discusses the results, and postulates the mechanism

responsible for severe well damage observed in several wells in the Umiat

field.

ACKNOWLEDGMENTS

Special acknowledgment is given to the late Ralph H. Espach, former Chief

of the Branch of Petroleum, Bureau of Mines, Region III, who initiated the

work and sampled cores stored at Fairbanks, Alaska.

3/ Underlined numbers in parentheses refer to items in the bibliography at

the end of this report. Page references refer to pages in items and not

in this report.

4/ Well 1, a dry hole, is not shown in figure 1. This well is near the axis

of the anticline, about 3 miles west of the western boundary of the map.

Map adapted from Geol. Survey Prof. Paper 305(b), 1958 (6).

5

NOMENCLATURE

The following symbols, definitions, units, and abbreviations are used in

this report:

Ki - Permeability to helium gas, using the Klinkenberg method (determining the apparent permeability at three or more mean pressures and

extrapolating these values to a value at infinite mean pressure,

millidarcys (md.)).

Ka - Permeability to air, determined at only one mean pressure,

millidarcys.

Kw - Permeability to distilled water containing 25 p.p.m. mercuric

chloride as a bactericide (), millidarcys.

IWS - Irreducible water saturation, determined in plug samples by the

semipermeable-barrier method, sometimes called the capillarypressure or restored-state method, percent of pore volume.

IBS - Irreducible brine saturation, determined in radial samples by

flowing crude oil through brine-saturated samples until no more

brine is produced. The brine contained 3,300 p.p.m. sodium

chloride - thought to be close to the total salinity of the Umiat

formation water, percent of pore volume.

RESERVOIR CHARACTERISTICS AND CONDITIONS

Producing Sands

The main oil-producing zones in the Umiat field are sandstones in the

Grandstand formation of Cretaceous age. These light to medium gray sandstones

are 5 to 100 feet thick and are composed mostly of subangular to subrounded

grains of quartz and dark rock fragments, with some mica and carbonaceous material. The composition of the rock varies from slightly silty to shaly; very

little of it is calcareous. The main sandstone beds are commonly massive, but

few have laminae of siltstone and claystone (6).

The uppermost sandstone bed in the Grandstand formation is usually 50 to

75 feet thick; it is separated from the lower sandstone by 300 feet or more of

gray shale. This shale sometimes contains a bed of sandstone, usually it does

not. The lower sandstone is much greater in total thickness than the upper,

but only the top 100 feet has good porosity and permeability. These beds of

sandstone contain most of the oil so far discovered in the Umiat field and are

referred to in this report as the upper and lower sands.

Depth to the producing sands depends upon the surface topography and subsurface structure. Measured to their tops, the shallowest upper sand well was

number 5 at 248 feet, the deepest lower sand well, where the sand was found

above the oil-water contact, was number 9 at 866 feet.
6

Formation Temperatures

Temperature surveys were made using thermistor cables in wells 4, 6, 9,

and 11. The cables did not reach the base of the permafrost (near 32° F.) in

these wells; however, the temperature gradients were rather uniform from a

depth of 100 feet to the bottom of the cable. Therefore, the extrapolation of

the observed temperature gradient used to estimate the depth to the base of

the permafrost should be reliable. Temperature generally decreases from the

surface to a depth of 70 to 100 feet, where the minimum temperature is about

20° F. Below 100 feet, the temperature increases with depth about 1.6° F.

for each 100 feet (6). The estimated depth to the base of the permafrost in

the four wells surveyed is given in table 1.

No temperature surveys were made in wells 1, 5, and 7, but the approximate depth to the base of the permafrost can be inferred from other data.

Frozen mud was found in well 1 to a depth of 920 feet when it was cleaned

after standing idle from September to the following June. In wells 5 and 7

the depth to the base of the permafrost, table 1, is that at which considerable water was first bailed from the hole.

TABLE 1. - Summary of permafrost data

Well number ................... 1 4 5 6 7 9 11

Surface elevation ........feet 810 483 335 337 330 424 481

Depth to top of lower

sand ............. ............... do. 1,818 745 770 -/1,055 1,200 866 2,805

Elevation of top of lower

sand, below sea level ....do. 1,008 262 435 718 870 442 2,324

Depth to base of

permafrost ............... do. 920 890 800 770 827 1,055 770

Elevation of base of

permafrost below sea

level ....................do. 110 407 465 433 497 631 289

Liquid produced from

lower sand .................. Water Oil Oi / Wate Water Oil Water

1/ The lower sand was not reached in this well; depth was estimated by using

interval between upper and lower sands in other wells. Position of oilwater contact in other wells indicates that lower sand contains water at

this location.

2/ Salt water was bailed from a depth of 800 feet at 2 bbl. per hour when the

well was first drilled; however, the well later produced very little

water on a 93-day pumping test.

Available data indicate that the only part of the producing sands below

the permafrost, but above the oil-water contact, is a narrow ring around the

structure between wells 5 and 6. Thus most of the producing sands are in the

permafrost zone, and expansion of gas in solution, aided by gravity drainage,

is the only effective producing method.
7

Reservoir Pressures

Attempts to make pressure surveys in the wells, using wire line instruments, were unsuccessful, mainly because of ice bridges in the well. Numerous

drill stem tests were made in various wells, and a series of bottom-hole pressures was usually recorded; however, no reliable formation pressures were recorded in most tests in the permafrost because no fluids entered the hole when

the tool was opened.

A tabulation was made of available data relating to the rise of liquids

in the hole during drilling and testing of the wells. Calculations of reservoir pressure from all reported static-fluid levels give such erratic results

that no reliable pressures can be estimated. Wells 5 and 9 flowed a little

oil by heads at times during testing, but it is not known whether this oil

came from the upper or lower sand or both. If part of this oil came from the

lower sand, then the reservoir pressure in the lower sand in well 9 must be

about 350 p.s.i. This pressure would be close to the maximum in the lower oil

reservoir, because the base of the lower sand in this well is close to the

oil-water contact.

All data indicate that the range of reservoir pressures is about 50 p.s.i.

in the high upper sand to 350 p.s.i. in the lower sand near the oil-water

contact.

The producing gas-oil ratio was not determined during the production

tests. Field personnel reported that only a small quantity of gas was produced with the oil on the pumping tests. Thus, apparently no gas cap was encountered in the upper or lower sands in any of the wells on the south side

of the fault, which follows the crest of the anticline, and the saturation

pressure of the oil is the same as, or lower than, the reservoir pressure.

Well 8, north of the fault, had gas in the lower sand; static pressure was

about 275 p.s.i.

EVIDENCE OF WELL DAMAGE

The first well drilled on the Umiat anticline was near the axis of the

structure and several hundred feet downdip from the crest. The well crossed

a fault, below which most of the Grandstand formation was repeated. Several

good shows of oil were noted in cores; however, none of the drillstem tests

recovered a significant amount of oil, and the well was abandoned.

Wells 2 and 3 had good shows of oil throughout both sands at depths less

than 1,100 feet, but extensive testing failed to produce more than 50 bbl. a

day. This insignificant production from thick sections of oil-saturated sand

indicated that the sands contained swelling clays, which, when exposed to the

fresh-water filtrate from the drilling mud, were expanding and blocking the

flow of oil from the formation to the well. The first three wells were

drilled with rotary rigs, using water-base mud; then experiments were made

with different drilling methods to try to develop high oil-production rates.
8

Well 4 was drilled with cable tools, using strong brine as drilling

fluid, in the belief that the brine would suppress expansion of interstitial

clays. This well pumped 100 barrels of oil a day, encouraging further

experiments.

Well 5 is only 200 feet from well 2, which was abandoned as a dry hole,

and it is about the same elevation on the structure. Well 5 was drilled with

cable tools, using brine, but it was reamed with a rotary, using crude oil as

the drilling fluid. This well, the best in the field, pumped 300 to 400 barrels of oil a day on a 93-day production test. This rate was the capacity of

the pump; the capacity of the well is unknown.

These field results confirmed that wells 2 and 3 were seriously damaged

by drilling and completion procedures used; it was supposed that the extreme

damage was due to montmorillonite clay in the sand (5 6).

EXPERIMENTAL METHODS AND PROCEDURES

Samples Analyzed

Core samples representing the lower sand in well 2, the upper sand in

well 3, and both sands in well 9 were analyzed. The sands should be productive in all three wells because of their location on the structure; however,

well 2 was abandoned as a dry hole, probably because of the drilling and completion methods used. Core samples from well 11, representing the lower sand

and the Chandler and Ninuluk formations were also analyzed. The Chandler formetion overlies the Grandstand, and the Ninuluk is above the Chandler. Well

11 is on the north flank of the anticline on the downthrown side of a major

fault; it was abandoned as a dry hole.

Crushed Samples

The "skin" around each piece of core was chipped off to eliminate possible contamination of the sample by drilling mud. The cleaned section of the

core was crushed, passed through a 28-mesh sieve, and divided into two parts.

One part of the crushed sample was dispersed in water, and the 12-micron

and smaller fractions were removed by siphoning off the upper 7.3 cm. of waterclay suspension after it had settled for 10 minutes. The suspension was then

filtered through a ceramic plate leaving a layer of clay on the porous surface. After the plate had been dried thoroughly, the clay was ready for identification by X-ray diffraction methods. This method of preparing clay samples is fast and convenient, and it has the advantage of orienting the clay

particles parallel to the plate surface, which results in an increased peak on

X-ray diffraction charts and aids in detecting small amounts of clay minerals

in a mixture.

The samples were run on a Norelco Geiger-counter X-ray diffractometer,

using nickel-filtered copper K-alpha radiation operated at a voltage of 40 kv.,

with a filament current of 20 ma. Scanning speed was 1° 2 theta per minute,

the width of the receiving slit was 0.003 inch, and the divergence slits were
9

1°. The Norelco electronic circuit-panel recording unit was run at a chart

speed of 30 inches per hour, and the rate meter was operated with a four-scale

factor, one multiplier, and an 8-second time constant.

After X-ray charts were made, the untreated samples were placed on a

platform about 1 inch above glycerol, which was heated to just below its boiling point. The glycerol vapor was allowed to condense on the sample for 20

to 30 minutes and was X-rayed again. Then the sample was ashed at a temperature of 600° C. for at least 1 hour, and the final X-ray chart was made.

The bulk-swelling capacity of the second part of the crushed sample was

determined by slowly dropping a measured dry volume (5 cc.) into distilled

water, which contained a small amount of wetting agent. After letting it

stand for 24 hours, the wet volume of the sample was read. The increase in

volume of the wet sample, as compared with its volume when dry, was used to

compute the bulk-swelling percent. After the wet volume was read, the sample

was thoroughly shaken and again allowed to stand for a day. Then the amount

of fine material in the sample was estimated visually by noting the thickness

of the layer that had settled on the coarser sand and the amount of clay that

was still suspended in the water.

An assumption in the bulk-swelling test is that the measured dry volume

will retain that volume after being dropped into water, if the sample does not

swell. This assumption was periodically tested by dropping the dry volume

into alcohol, which caused no interlayer expansion of clay minerals. These

calibration tests showed that the reproducibility limits of the swelling test,

using 5 cc. of dry volume, were plus or minus 0.2 to 0.3 cc.; therefore indicated swelling, no more than 6 percent, is insignificant. Reproducibility

limits of the test could be decreased by increasing the size of the sample;

however, larger volumes of crushed sample are not always available. Laboratory work done in connection with other studies has shown, that when even

trace amounts of montmorillonite are present, the samples will swell 10 percent or more.

Plug Samples

Plug samples, about 2 cm. in diameter and 3 cm. long, were used for determination of porosity, gas permeability (Ki), water permeability (Kw), and

irreducible-water saturation (IWS) by the semipermeable barrier method. This

method, used to determine the practical (not actual) irreducible-water saturation, is often called the restored-state or capillary-pressure method. Tests

of the plug samples were made by conventional methods, described in some

detail in previous reports (1, 2, and 3_.

For the Kw tests samples were soaked for 24 hours after being saturated.

Drilling muds sometimes require as much as 72 hours to attain hydration equilibrium. A porous sample would require less time, and hydration undoubtedly was

completed in the day allowed.
COOL

COOL

10

Radial Samples

A radial sample was prepared by cleaning the outside of a core section,

2 to 3 inches long, first by facing both ends with a diamond saw and then by

drilling a 3/16-inch hole axially through the center. After cleaning with

toluene and drying, the sample was ready for testing. Schematic diagrams of

the apparatus developed for testing the radial samples are shown in figures 2

and 3.

The sample was saturated first with brine containing 3,300 p.p.m. sodium

chloride and allowed to soak overnight, then it was mounted in the glasswalled cell shown in figure 3. The cell was mounted in the brine bath shown

in figure 2, and Umiat crude oil was forced through the sample at room temperature. The oil displaced part of the interstitial brine. This was collected

and measured until no more brine was produced by the flowing oil. The sample

then contained the irreducible-brine saturation (IBS), and the remaining pore

space was filled with dead oil. The dead oil was displaced with Umiat crude

oil, which was saturated with natural gas to a predetermined saturation pressure; following this step, the remaining oil surrounding the sample was displaced with gas. The sample containing IBS and gas-saturated oil was chilled

in the brine bath to 26° F. When the sample and apparatus reached temperature

equilibrium, the sample was ready for determination of oil recovery by

FIGURE 2. - Diagram of Apparatus Used to Determine Oil Recovery Under Simulated

Permafrost Conditions.
COOLING BRINEo

OUT

COOLING BRINE D

IN

11

RADIAL CORE

SAMPLE

FIGURE 3. - Diagram of Cell of Apparatus Used to Determine Oil Recovery

Under Simulated Permafrost Conditions.

solution-gas expansion. Cooling the gas-saturated oil from room temperature

to 26° F. will result in some oil shrinkage and undersaturation; however,

these changes should be small and have an insignificant effect on the results.

The recovery experiment was started by cracking the valve below the sample, allowing gas and oil to escape to atmospheric pressure, and slowly lowering the pressure in the system. The gas-filled space in the cell outside the

sample was connected to the outflow tube below the center hole through a mercury-bubbler arrangement. As the pressure on the system was lowered, the expanding gas outside the sample bubbled through the mercury. This process

allowed the pressure of the system to drop, while a slightly higher pressure

outside of the sample was steadily maintained, assuring that all oil expelled

from the sample by expanding solution gas would move to the center hole to be

produced and measured. A differential pressure of 0.3 p.s.i. was maintained

across the sample, and calibration experiments proved that this pressure
12

forced all produced oil to the center hole without forcing more gas through

the sample. Also, other calibration experiments showed that the amount of oil

produced by gravity drainage was negligible and could be ignored.

After oil recovery by gas expansion was complete, what could be recovered

further by gas drive was determined by driving gas through six of the samples

under a low differential pressure until no more oil was produced. Gas-expansion and gas-drive experiments were made with these six samples, first at 75°

F., and then at 26° F., to estimate the effect on oil recovery of freezing the

interstitial water. Oil was gas-saturated in these tests to 100 p.s.i.g.

Another set of experiments was designed to determine the effect of gasoil ratio on recovery by solution-gas expansion. A series of tests was made

of several radial samples with the oil gas-saturated at 50, 100, and 150

p.s.i.g.; temperature of the brine bath was 26° F.

DISCUSSION OF RESULTS

Clay Mineral Identification

X-ray diffraction analyses were made of the fine material separated from

36 samples of producing and nonproducing sands in the Umiat field. These samples represented the upper sand in two wells, the lower sand in three wells,

and sands in the Ninuluk and Chandler formations in one well. X-ray charts

obtained from these 36 samples were unusually similar, and this similarity

made it possible to summarize the results and give only the average values in

table 2.

The strong d-spacing reflection from the untreated samples at about 9.98

A. (angstroms) could indicate the presence of illite, montmorillonite, or

both. In the humid atmosphere of most laboratories montmorillonite usually

gives a d-spacing of about 14 A.; however, the relative humidity in the

Laramie laboratory is less than 10 percent, which is insufficient to rehydrate

the dried montmorillonite. As a result, experience with numerous oil-well

samples containing mixtures of illite and montmorillonite shows that only a

single peak indicating a d-spacing of about 10 A. is observed.

To separate the superimposed illite and montmorillonite peaks, the sample

is exposed to glycerol vapor. The glycerol enters between the montmorillonite

layers and expands them, which results in a shift of the d-spacing from 10 A.

to 17 A. or above. Since glycerol does not expand the illite layers, a glyceroled sample containing both illite and montmorillonite gives two distinct

peaks on the chart, indicating d-spacings at about 10 A. (illite) and 17 A.

or above (montmorillonite).

The d-spacings of the untreated and glyceroled Umiat samples shown in

table 2 are virtually the same; therefore, the samples did not contain more

than trace amounts of montmorillonite, if any. Montmorillonite flakes are

strongly oriented by being deposited on the flat surface of the sample plates;

so montmorillonite gives a strong X-ray reflection, making it possible to detect small amounts of this mineral in samples. If an appreciable amount of
Well and sand

Umiat 2, lower.........

Umiat 3, upper.........

Umiat 9, upper.........

Umiat 9, lower.........

Umiat 11, Ninuluk......

Umiat 11, Chandler.....

Umiat 11, lower ......

Depths,

feet

796

797

805

824

831

884

886

888

890

470

475

480

870

875

880

895

905

910

950

960

965

975

2, 110

2, 120

2, 130

2,140

2, 295

2,310

2,325

2,350

2,375

2,385

2,395

2,825

2,835

2.845

TTntrPntPd

ll/

TIllite

16

22

29

13

28

16

17

13

montmorillonite were present in the samples, it would have been detected by

the methods used.

TABLE 2. - Summay of X-ray diffraction results

d /-

9.98

9.99

9.98

9.98

9.99

9.96

9.96

1

16

20

27

12

27

14

14

Glyceroled

d

9.95

9.97

9.95

9.97

9.99

9.96

9.95

Kaolinite,

untreated

1

49

46

54

52

60

55

53

d

7.12

7.12

7.08

7.12

7.09

7.12

7.12

1

19

22

29

20

25

15

Chlorite,

ashed

d

13.8

13.8

13.8

13.8

13.7

13.8

18 13.7

. . - - - II

1/

2/

Average intensity of X-ray reflection, arbitrary units. Intensity is

given in units of peak height on charts; in the system used one unit

equals 0.1 inch.

Average lattice spacing (d-spacing) calculated from basal reflection,

angstroms.
14

The main nonclay minerals identified in the samples were quartz and feldspar. Average intensity of the first order quartz peak was 19 units and that

of feldspar 6 units.

Formation Damage Related to Clay Swelling or Permafrost

The rate of production from many sands may be reduced slightly or to a

great extent, if the sands are invaded by fresh water during the drilling and

completion of wells. Sands that are susceptible to serious productivity impairment are often called water sensitive. The two most common causes of

productivity impairment in water-sensitive sands are: (a) Swelling of interstitial clay minerals caused by displacing the original formation brine with

fresh water, and (b) reduction of relative permeability to oil by increasing

the water saturation through water invasion. This latter type of damage occurs in all sands, but it is especially detrimental in sands having low

original permeability.

Several tests have been used in the Laramie laboratory to estimate water

sensitivity of producing sands. The most important of these are tests that

determine types of clay minerals, amount of fine material of clay size, bulkswelling capacity, ratio of water permeability to gas permeability, and irreducible-water saturation. Experience with many sands in the Rocky Mountain

region has shown that a sand having a high water sensitivity will usually exhibit the following characteristics: (a) It will contain detectable amounts

of a clay mineral that exhibits large interlayer expansion in water, and this

clay usually will be either montmorillonite or mixed-layer montmorillonite;

(b) it will contain a relatively large amount of clay-size material; (c) bulk

swelling of a crushed sample of the sand will be greater than 15 percent, although a few exceptions to this rule have been observed; (d) the ratio of

water permeability to gas permeability will be less than 0.3; and (e) the

irreducible-water saturation will be unusually high for a given permeability,

especially in the low permeability range.

Application of these standards to the results of the laboratory tests of

samples of Umiat sands (tables 2 and 3) indicates that these sands have a low

to moderate water sensitivity. This conclusion is based upon the following

considerations: (a) The predominant clay minerals, as determined by X-ray

diffraction analyses, are kaolinite and illite; no montmorillonite was detected; (b) the sands contain small to medium amounts of fine materials; (c)

bulk swelling of the samples is very low--0 to 8 percent; (d) the Kw-K. ratios,

calculated from values listed in table 3, are mostly high (the average is about

0.67); (e) the relation of Kw to Ki is shown in figure 4;5/ (the position of

this average curve, when compared with that of other sands exhibiting various

degrees of water sensitivity (1, 3), again indicates the moderate sensitivity

of the Umiat sands); and (f) the position of the average curve showing the

5/ The average curve for figure 4 was constructed by plotting the corresponding permeability values from table 3 for wells 2, 3, and 9, and then by

drawing the average line through these points by the method of least

squares. Results from well 11 were omitted from this plot, because this

well was a dry hole, and the sands may not be representative of the

oil-reservoir sands.
ft

Well and sand

Umiat 2, lower....

Umiat 3, upper....

Umiat 9, upper....

Umiat 9, lower....

Umiat 11, Ninuluk.

Umiat 11,Chandler.

Umiat 11, lower...

Depth,

feet

796

797

805

824

831

259

274

352

355

475

480

870

875

880

895

905

910

950

960

965

975

2,110

2, 120

2, 130

2,140

2, 295

2,310

2,325

2,350

2,375

2,385

2,395

2,825

2,835

2,845

Amount

fine

material

Very small

do.

do.

Small

do.

Medium

do.

Small

Medium

do.

do.

do.

do.

Small

Medium

do.

do.

do.

do.

do.

do.

Very small

Medium

do.

do.

do.

Large

do.

Medium

Small

Medium

Large

Small

do.

do.

Bulk

swelling,

percent

15

relation of Ki;to IWS in figures 5 and 6 is that of a sand having moderate

sensitivity. The last point is discussed in more detail.

TABLE 3. - Physical properties and swelling capacity of upper and lower

Grandstand sands and sands in the Ninuluk

and Chandler formations

Porosity,

percent

19.7

18.3

17.1

15.5

17.3

10.2

17.8

17.4

14.8

9.7

19.1

17.2

18.2

15.8

14.5

13.1

11.7

15.4

13.7

13.8

24.1

12.4

14,7

11.1

19.0

13.6

5.5

19.3

14.2

23.3

12.6

18.3

10.4

14.5

K

272

100

15

65

0

83

55

23

1.3

232

154

274

58

30

7

7.6

79

11

14

300

5.4

21

28

286

2.5

<.5

87

2.6

5.2

1.2

145

139

445

K

w

220

35

85

-

10

46

0

88

25

14

<.5

136

32

172

43

21

6

7

37

8

9

97

2.6

6.2

<.5

75

<.5

0

17

0

2.6

0

160

118

370

Permeability,

md.

,ws, IWS

percent

pore

volume

15

20

21

28

21

53

22

24

23

49

18

18

15

23

29

31

19

32

30

5

32

15

49

100

20

50

26

85

14

20

10
0o

E

-

16

2

-0

'i

E

yd

Kw, millidarcys

FIGURE 4. - Relation of Water Permeability

to Gas Permeability.

0

P

WATER OR BRINE SATURATION PORE VOLUME, percent IWS PORE VOLUME, percent

FIGURE 5.- Relation of Gas Permeability to

Irreducible-Water and IrreducibleBrine Saturations.

FIGURE 6. - Average Relation of Gas Permeability to Irreducible-Water Saturations, Umiatand Four Reservoir

Sands in Wyoming.
17

If IWS, as determined in several samples from the same sand, is plotted

against the corresponding Ki, the trend of the plotted points usually will

indicate a general relation between these two variables. When a line is

fitted to these data points by the method of least squares, the resultant

curve shows the average relation of IWS to Ki. If several such average

curves, representing different sands, are placed on the same plot for easy

comparison, the relative position of each curve is related to the clay content, capillary behavior, and water sensitivity of the sand Q3).

Figure 5 shows the average relation of IWS to Ki for the Umiat sands, and

figure 6 shows this average relation with respect to that of four oil-producing sands in Wyoming. Since IWS increases with increasing water sensitivity

for a given permeability, especially in the low-permeability range, the position of the average lines on figure 6 indicates that the sensitivity of the

Umiat sands is higher than that of the Muddy and Tensleep, slightly less than

that of the Newcastle, and much less than that of the second Frontier. Muddy

and Tensleep exhibit low water sensitivity, Newcastle shows low to moderate

sensitivity, and the second Frontier is highly water-sensitive in the wells

represented in figure 6.

Since evidence indicates that Umiat reservoir sands exhibit low to moderate water sensitivity, some other set of physical conditions must have

caused the serious formation damage noted in several wells. Evidence, too,

suggests that well damage is related to the freezing temperatures and the low

pressures in the reservoir sands. Let us study wells 2 and 5 in order to

postulate the probable causes of production failure.

Well 2 was drilled with a rotary rig, using water-base mud, and was

abandoned as a dry hole. The hole was bailed dry with all the upper sand and

the upper part of the lower sand exposed in the open hole. Circulating mud

warmed the area around the well bore, which thawed the formation water and

allowed water filtrate from the mud to invade the formation. This decreased

oil saturation and increased water saturation. When circulation of the warm

mud was stopped in preparation for a formation test, water in the formation

froze and formed an impermeable barrier around the well bore. Reservoir pressure was not great enough to force oil through this frozen barrier, and the

hole was bailed dry without producing oil.

Now consider well 5, which was drilled close to well 2 but drilled first

with cable tools, using a small quantity of brine (containing about 100,000

p.p.m. sodium chloride) for the drilling fluid. This method thawed the sand

comparatively little, because the drilling fluid soon reached the temperature

of the formation. Furthermore, the brine drilling fluid that did enter the

sand, due to pressure differential and diffusion, would increase the salinity

of the formation water. Increasing the salinity of the formation water would

prevent it from refreezing when the formation temperature returned to normal,

and all mobile water would be produced ahead of the oil on a production test.

Thus no formation damage resulted from the methods used to drill well 5, resulting in a well that pumped as much as 400 barrels of oil a day and perhaps

could have produced more if a larger pump had been available.
18

Reduction of Oil Permeability and Oil Recovery Due

to Freezing of Interstitial Water

A set of experiments was made on six radial samples to obtain a qualitative index of oil recovery by solution-gas expansion and additional oil recovery by gas drive, as well as the effect of freezing of interstitial water on

these two recovery processes.

The average oil recovery from these six samples at 26° F., shown in table

4, is 28 percent of the initial oil by gas expansion and 23 percent more by

gas drive. Maximum recovery was by gas drive, because it was continued after

gas breakthrough until no more oil was produced.

After the experiments were completed at 26° F. they were repeated at

75° F. to compare results with those taken when the interstitial water was

frozen. Average recovery by solution-gas expansion of four samples run at

75° F. was 40 percent of the initial oil; this compares with an average of

29 percent for the same four samples tested at 26° F.

To test further the effects of freezing of interstitial water on movement of oil, the relative permeability of two samples to oil was tested at

room temperature and then below the freezing point of the water. Two radial

samples were saturated with water and driven with Umiat crude oil at 70° F.

until no more water was produced; the permeabilities to oil were noted. The

samples were cooled to 26° F., and the permeabilities to oil were determined

again. Permeabilities of the samples at 70° and 26° F. are, respectively, for

the first, 30 and 23 md. (23.3 percent reduction), and for the second, 19 and

13 md. (31.5 percent reduction). Since calculation of permeability includes

the change with temperature in oil viscosity, permeability values in each sample would have been the same at the two temperatures if no extraneous factors

were involved. Thus, average reduction in permeability value attributable to

freezing the water is 27 percent. Lowering the temperature from 70? to 26° F.

actually reduced the rate of oil flow by 54 percent.

Part of the decrease in oil recovery, caused by lowering the temperature

from 75° to 26° F. may be due to increased oil viscosity at the lower temperature; however, this loss seems too great to be caused solely by increased

viscosity.

Average water saturation of the four samples tested at 260 and 75° F. is

41 percent of pore space (see table 4). Since the volume of water increases

about 9 percent when it freezes, freezing of the interstitial water increased

the immobile water saturation from 41 to 45 percent of pore space. This increase of immobile saturation may cause additional constriction of connections

between pore spaces within the rock, thereby reducing both relative permeability to oil and oil recovery.
19

TABLE 4. - Oil-recovery experiments, solution-gas expansion followed

by gas drive, temperatures 26° and 75° F.

Initial Solution- as expansion Gas drive

Poros- Air satura- Recovery, Residual Recovery, Residual

Well Depth, ity permea- tions, per- initial oil, per- initial oil, perand feet per- bility, cent pore oil, cent pore oil, cent pore

sand cent milli- volume percent volume percent volume

_darcys Brine Oil 26° 750 26° 750 26° 750 26° 750

Umiat 796 16.5 196 37 63 34 48 42 33 21 20 28 20

2, 797 15.1 49 44 56 27 29 41 39 7 9 36 34

lower 805 14.6 92 41 59 17 - 49 - 28 - 33 -

Umiat 259 18.2 128 42 58 36 - 38 - 34 - 19 -

3, 352 17.7 134 38 62 31 50 43 34 26 23 27 16

upper 355 16.3 52 44 56 25 33 42 38 19 34 32 19

It is not known whether the deleterious effect due to increased oil viscosity

and expansion of water is responsible for all the reduction phenomena observed.

It is possible that other factors (some unknown, others half-guessed) may be as

harmful as either of the factors already discussed. For example, if ice crystals

in the capillary system were dislodged by some mechanism and freed for transport

by the moving oil, these crystals could cause very serious blocking of the flow

channels.

Oil Recovery by Depletion Drive Under Permafrost Conditions

A second series of recovery experiments was made to determine the relation of

solution gas-oil ratio to oil recovery under simulated permafrost conditions, when

the oil is produced entirely by solution-gas expansion. This series was conducted

at a temperature of 26° F. Recoveries obtained when the oil was gas saturated at

50, 100, and 150 p.s.i.g. are given in table 5, and the average relation of recovery to saturation pressure is plotted in figure 7. Average oil recoveries with the

oil initially gas-saturated at 50, 100, and 150 p.s.i.g. are 29, 40, and 45 percent

of the initial oil, respectively.

Laboratory analyses were made on a sample of Umiat crude oil combined with a

natural gas (mostly methane). Results of a differential liberation at 25° F. between saturation pressure, 328 p.s.i.a., and atmospheric pressure, gave 22.5 cu.

ft. of gas (measured at 14.4 p.s.i.a. and 60° F.) released from solution per bbl.

of residual oil at 60° F. for each 100 p.s.i. pressure drop (i).

Since volume of gas in solution is directly proportional to pressure in this

gas-saturated system, increasing the saturation pressure from 50 to 100 p.s.i.g.

increased 100 percent the amount of gas released from solution during the recovery

experiment; however, oil recovery was increased only 38 percent--from 29 to 40 percent of the initial oil. The proportional increase in recovery, as related to the

increase of gas in solution, was even less for saturation pressure increase from

100 to 150 p.s.i.g.

The first gas that comes out of solution, as the pressure is lowered below the

saturation pressures expands and displaces an equal volume of oil by pistonlike

action. This phase of oil recovery continues until the equilibrium-free-gas saturation is reached. After that point, gas begins to flow, relative permeability to

gas increases rapidly, and the rate of oil production declines steadily; it may

cease eventually even though gas flow continues.
20

TABLE 5. - Oil-recovery experiments, solution-gas expansion from three

saturation pressures, temperature 260 F.

.. Solution-gas expansion

Air Recovery, Residual

Well Poros- permea- Initial initial oil, oil, percent

and Depth, ity, bility, saturations, - percent pore volume

sand feet per- milli- percent Saturation pres- Saturation prescent darcys pore volume sure, .s.i.g. sure, p.s.i.g.

________Brine Oil 50 100 150 50 100 150

Umiat 2, 797 15.1 26 42 58 26 - - 36 - -

lower.. 805 14.6 81 38 62 36 - - 40 - -

Umiat 3 259 18.2 142 35 65 25 43 47 49 37 35

r 352 17.7 123 40 60 24 39 50 45 33 29 r 355 16.3 43 43 57 33 29 49 39 41 30

Umiat 9, 470 16.1 76 34 66 - 45 - 35 -

upper.. 475 13.9 22 42 58 33 40 42 39 35 34

870 17.4 195 37 63 - 51 - - 30 -

875 17.2 184 34 66 24 32 37 50 45 42

880 17.8 211 33 67 26 38 48 50 42 35

895 14.7 69 36 64 - 42 - 37 - Umiat 9, 900 12.4 23 48 52 - 40 - - 31 -

lower.. 905 14.3 26 42 58 - 49 - - 30 -

910 13.3 14 47 53 - 48 - - 27 -

950 12.3 12 48 52 - 29 - - 37 -

970 14.6 78 38 62 35 41 44 40 37 30

As a result of these two types of production during depletion drive, the

first gas released from solution displaces an almost equal volume of oil,

whereas the energy content of the gas released during the period of high gas

permeability is largely wasted.

Another factor making possible considerable recoveries from reservoirs

that have usually low pressures is that, although the mass of gas in solution

is small, its volume is greatly increased when released from solution. Thus a

small drop in pressure below the saturation point provides a sufficient volume

of gas to complete, not only the piston-action phase of the recovery process,

but at least part of the viscous-drag phase.

As an example of gas volumes in the reservoir, suppose that Umiat reservoir oil were gas-saturated at 200 p.s.i.a. and that the pressure dropped to

100 p.s.i.a., then 0.55 bbl. of gas would be released in the reservoir from

each barrel of original oil. If this gas displaced an equal volume of oil,

recovery would be much greater than that usually experienced in depletiondrive reservoirs. This example illustrates that at even low pressures a

reservoir oil may contain more energy than needed to complete the depletiondrive recovery process.
I

0'

0i. u-I

cc

U,

C,)

cr

(n

250

200

150

100

50

21

Increasing waste of reservoir energy at increasing gas-oil ratios accounts for the rise of the curve with increase in pressure shown in figure 7.

If this curve were extrapolated to higher pressures, an ultimate recovery by

this process would be realized at some rather low pressure--perhaps not more

than 500 p.s.i.g. These results and observations agree in principle with

published literature concerning recovery from depletion-drive reservoirs

(11, p. 536): "Oil recoveries from reservoirs exceeding 500 p.s.i. in pressure and 100 cu. ft. per bbl. solution gas are controlled more by fluid-flow

characteristics than by reservoir energy."

0

I

K

I I I TI

I

I m J . !. i i J i i i iiiii

0 10 20 30 40 50 60

INITIAL OIL RECOVERY, percent

FIGURE 7.- Average Relation of Saturation

Pressure to Oil Recovery at

26° F.
22

REFERENCES

1. BAPTIST, 0. C., AND SWEENEY, S. A. Effect of Clays on the Permeability of

Reservoir Sands to Various Saline Waters, Wyoming. Bureau of Mines Rept.

of Investigations 5180, 1955, 23 pp.

2. . Physical Properties and Behavior of the Newcastle Oil-Reservoir

Sand, Weston County, Wyo. Bureau of Mines Rept. of Investigations 5331,

1957, 43 pp.

3. BAPTIST, 0. C., AND WHITE, E. J. Clay Content and Capillary Behavior of

Wyoming Reservoir Sands. Jour. Petrol. Technol., vol. 9, No. 12,

December 1957, pp. 57-59; Petrol. Trans. AIME vol. 210, 1957, pp.

414-416.

4. BUREAU OF MINES. Recoverable Petroleum Reserves in the Umiat Structure,

Naval Petroleum Reserve No. 4, Alaska. Open-file report, 1952, 25 pp.

5. BURNSIDE, R. J. Alaska's Arctic Slope. Oil Gas Jour., vol. 57, No. 12,

Mar. 16, 1959, pp. 125-152.

6. COLLINS, FLORENCE RUCKER, AND OTHERS. Test Wells, Umiat Area, Alaska.

Geol. Survey Prof. Paper 305-B, 1958, 206 pp.

7. FAGIN, K. M. Drilling Problems in Alaska. Petrol. Eng., vol. 19, No. 1,

October 1947, pp. 180-190.

8. GATES, G. L., AND CARAWAY, W. H. Drilling Muds Related to Well Productivity, Umiat Field, Naval Petroleum Reserve No. 4, Alaska. AIME Soc.

Petrol. Eng., Paper 1383-G, Pasadena, Calif., Oct. 22, 1959, 12 pp.

9. OIL AND GAS JOURNAL. Alaska Search to End. Vol. 50, No. 14, Aug. 9, 1951,

p. 58.

10. . Northern Oil Search. Vol. 50, No. 39, Feb. 4, 1952, pp. 51-52.

11. PIRSON, S. J. Oil Reservoir Engineering. McGraw-Hill Book Co., Inc.,

New York, N. Y., 1958, 735 pp.

12. REED, JOHN C. Exploration of Naval Petroleum Reserve No. 4 and Adjacent

Areas, Northern Alaska, 1944-53. I. History of the Exploration. Geol.

Survey Prof. Paper 301, 1958, 192 pp.

INT.-BU.OFMINES.PGH. PA. 1536