GEOLOGICAL SURVEY CIRCULAR 687 

Report on Water lniectivity Test, 

lease OCS-P 0241, Well No. B-49-1, 

Dos Cuadras Field, Santa Barbara 

Channel, Off California 

Report on Water lniectivity Test, 

Lease OCS-P 0241, Well No. 8-49-1, 

Dos Cuadras Field, Santa Barbara 

Channel, Off California 

By Maurice V. Adams 

GEOLOGICAL SURVEY CIRCULAR 687 

1973 
United States Department of the Interior 

ROGERS C. B. MORTON, Secretary 

Geological Survey 

V. E. McKelvey, Diredor 

Free on application to the U.S. <;eologicol Survey, National Center, Reston, Va. 22092 
FOREWORD 

In its day-to-day operations, the United 

States Geological Survey acquires considerable 

confidential and proprietary information. It is 

obligated to preserve the confidentiality of such 

information until permission is obtained to 

make it publically available. When such permission is obtained, Geological Survey's policy 

is to make the results of its scientific and engineering investigations available in such a manner as will best serve the public, rather than 

benefit special interests. 

By adherence to this policy, the Geological 

Survey has built a reputation for integrity and 

impartiality in its service to the Nation. In this 

context of public service, the information contained herein has been published for the benefit of all who have an interest in the subject 

matter. 

Entitled "Water Injectivity Test, Lease 

OCS-P 0241, Well No. B-49-I, Dos Cuadras 

Field, Santa Barbara Channel, Off California," 

this publication is a progress report on the subject project. It includes pertinent information 

from the time the application to drill was submitted by Union Oil Co. of California on January 28, 1971, through May 31, 1973. 

The basic data utilized in preparing this report were submitted by Union Oil Co. of California in compliance with applicable regulations 

contained in Part 250, Title 30 of the Code of 

Federal Regulations. The analysis and interpre .. 

tation of these data have been made by the 

author. 

V. E. McKELVEY 

Director 

Ill 

CONTENTS 

Page 

Fore~ord --------------------------------------------------------------- III 

Introduction ------------------------------------------------------------ 1 

)LcknowledgTnents -------------------------------------------------------- 1 

Geologic characteristics and nomenclature ---------------------------------- 1 

Water drives--general discussion ----------------------------------------- ·< 2 

Reservoir characteristics of Dos Cuadras field ------------------------------ 4 

Injection ~ater source ----.----------------------------------------------- 5 

Special injection conditions ___ ---_________ - -----___________ ----_ --__ ----- 6 

Drilling and completion history ------------------------------------------- 7 

lnjectivity testing -------------------------------------------------------- 7 

Withdrawal and injection history ----------------------------------------- 9 

Special tests and surveys ------------------------------------------------ 10 Subsidence investigations ____________________________________________ -.--- _ 11 

Conclusions -------------------------------------------------------------- 13 

References cited --------------------------------------------------------- 14 

Well data: 

Well completion report ----------------------------------------------- 20 

Well record --------------------------------------------------------- 21 Mud record ________ -.- _ _ _ _ _ __ _ _ _ __ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ __ __ _ _ _ __ _ _ _ __ ___ _ _ 22 

Drilling record (daily) _____________ -.- __ _ _ _ _ _ _ _ _ __ _ _ ____ __ __ ___ ___ _ _ __ 23 

Drilling record (acidize) --------------------------------------------- 28 

ILLUSTRATIONS 

Page 

FIGURE 1. Composite type log of the Dos Cuadras oil field ------------------ 2 

2. Schematic relations between producing "zones," stratigraphic subdivisions, and structural divisions in the Dos Cuadras oil field__ 2 

3. Relative permeabilities of oil and water as a function of water 

saturation ------------------------------------------------ 3 

4. Structure contours for the top of the EP interval --------------- 16 

5. Structure contours for the top of the FP interval --------------- 17 

6. Structure contours for the top of the GP interval ---------------- 18 

7. Cross section through well B-49-1 ----------------------------- 19 

TABLE 1. 

2. 

3. 

4. 

TABLES 

Sea-water samples from Santa Barbara Channel ---------------

Composite produced water sample-Platform B ------------------

Six stages of injectivity testing --------------------------------

Water injection history of well B-49-1 -------------------------

v 

Page 

5 

6 

8 

10 

Report on Water lnjectivity Test 

Lease OCS-P 0241, Well No. B-49-1, 

D·os Cuadras Field, Santa Barbara Chann.el, 

O·ff California 

By Maurice V. Adams 

INTRODUCTION 

Union Oil Co. of California submitted an 

application to drill and complete well B-49-I 

for a pilot water inj ectivity test in a portion 

of the upper 402 zone of the "Repetto" reservoirs, lease OCS-P 0241, Dos Cuadras field, 

Santa Barbara Channel, off California. The application, with attachments, was received in the 

U.S. Geol. Survey Santa Barbara office J anuary 28, 1971, and after comprehensive review 

and recommendations, was approved by the 

Director, U.S. Geol. Survey, on March 24, 1971. 

A summary of the pertinent information and 

conclusions obtained from this pilot test is presented in response to public interest. 

ACKNOWLEDGMENTS 

The author wishes to thank Union Oil Co. 

of California and their co-lessees Gulf Oil Co.-

U.S., Mobil Oil Corp., and Texaco, Inc., for 

their permission to publish the basic data contained in this report. Special thanks are extended to Mr. D. W. Solanas, U.S. Geol. Survey, 

for his assignment of this project to the author. 

The author also extends his thanks to Mr. 

Edgar W. Guynn, U.S. Geol. Survey, who made 

a substantial contribution to this report by his 

early work on the subject. 

GEOLOGIC CHARACTERISTICS AND 

NOMENCLATURE 

The trapping structure in the Dos Cuadras 

field is a doubly plunging east-west trending 

1 

anticline on the seaward extension of the Rincon trend. The productive zones are in the 

upper "Repetto Formation" of early Pliocene 

age. Longitudinally (E-W), the structure is 

fairly symmetrical, although detailed geology 

of the western one-quarter is not yet well 

known. The transverse section (N-S) is asymmetrical with substantially steeper dips on the 

south flank through the "Repetto Formation," 

but may be more symmetrical in deeper formations. There is a major longitudinal thrust fault 

(TF-1) cutting the anticline. The formations 

lying above the thrust fault have been designated as the P block, and those below the fault 

are the Q block. 

Identifiable electric log markers, from B to 

L, have been established in the "Repetto Formation" (fig. 1). However, only those sandstones from the C marker through H have been 

commercially productive to date. In addition, 

arbitrary color designations have been made 

for the zone which lies below the E-log marker, 

as follows: C and D (Brown), E (Yellow), F 

(Purple), G (Orange), and H (Green). With 

this informal nomenclature, as an example, 

the Yellow zone above the thrust fault is called 

EP, but below the thrust fault it is EQ. Some 

of the zones are further subdivided by a numerically increasing designation, within the 

zone, such as F1P, F2P, F3P, etc. 

The productive "Repetto" sandstones, in the 

Dos Cuadras field, have been combined into 

three development zones : ( 1) the upper Brown 

zone, consisting of the CP (Brown) and DP 
~ ... 

~ 

Ql ~i n:~'"O «< E «~ E -- Q) ,-.. 

CD ><<II- Qj O.QQI 

til) .Q 

oct: LLI ~~~ ~ 

Mud lme 

c 500 

-=- ...z: 

~~~ ~-

G '--= ·c: 22000 0 

:;; 

«< 

!§ c:::a -- - ~ 

.s -

~2~ G) 

a. 

Ql 

~ 

""" Ql 

c: 

Ql 

.~ a: 

Qj t= 3t 

0 

...J 

3000 

FIGURE 1.-Composite type log of the Dos Cuadras oil 

field. From McCulloh (1969, fig. 6). 

2 

Sea floor 

u c 

p 

p 

E 

R 

("P")F u 

B 

l G 

0 

c 

K 

H 

/ 

WELL 

Red zone 

~ 

~North 

WELL 

Red zone 

402 lower zone 

0 500 1000 FEET 

APPROXIMATE VERTICAL SCALE 

Note: F-G markers are included in 402 upper zone above thrust fault 

and in 402 lower zone below thrust fault 

FIGURE 2.-Sehematic relations between producing 

"zones," stratigraphic subdivisions, and structural 

divisions in the Dos Cuadras oil field. From McCulloh 

(1969, ~g. 10). 

(Brown) intervals above the TF-1 fault; (2) 

the upper 402 zone including the EP (Yellow) 

and FP (Purple) intervals above TF-1 and the 

CQ (Brown), DQ (Brown), and EQ (Yellow) 

intervals below TF-1; and (3) the lower 402 

zone comprising the G P (Orange), G3P 

(Orange), and HP (Green) intervals above 

TF -1 and FQ (Purple), GQ (Orange), G3Q 

(Orange), HQ (Green), and H1Q (Green) below the TF-1 fault. The upper 402 zone is usually abbreviated as EP, FP,/CQ, DQ, EQ, and 

the lower 402 zone as GP, G3P, HP,/FQ, GQ, 

G3Q, HQ, H1Q with the slash designating the 

T:F-1 thrust fault (fig. 2). Not all these zones 

are productive throughout the entire areal extent of the field, nor, with few exceptions, are 

all of the intervals of a development zone present and productive in a particular well bore. 

(See structure maps and cross section, figs. 

4-7). 

WATER DRIVES-GENERAL DISCUSSION 

In general, water drives, in an oil reservoir, 

may be either natural or artificial. Natural water drives can be divided into two basic types : 
( 1) those where the producing zone crops out, 

generally some distance from the field, and the 

edge water is replenished by natural sources 

(artesian effect) or (2) those where the volume 

of the surrounding aquifer is of such magnitude 

with respect to the volume of oil in place that 

reduction in reservoir pressure will cause the 

water in the aquifer to expand sufficiently to 

supply driving energy to the reservoir. 

Artificial, or induced, water drives are those 

where water is injected, from the surface, 

through injection wells, to supplement the natural driving pressure energy contained within 

the reservoir. Artificial water drives can be 

divided into three basic types: (1) peripheral 

injection at, or near, the oil-water interface, 

(2) five-spot injection into the producing zone 

to drive oil to surrounding producing wells, or 

(3) line injection to drive oil to a line of producing wells. Each type of artificial water drive 

has various merits which make a particular 

one preferable for a certain set of existing conditions. As a generality, peripheral injection is 

more desirable when initiated early in the life 

of a field. In operation, it becomes an effective 

means of pressure maintenance. Line or fivespot injection is more commonly used in the 

late producing life of a field. 

A majority of California oil fields probably 

have a limited degree of natural water drive. 

However, it is relatively rare that the degree 

of drive, or encroachment, is of sufficient magnitude to be considered effective. Where a natural effective drive does exist, the field is usually small and the encroachment results from 

expansion of the aquifer. A notable exception 

to this type of drive is the Kern River field, 

near Bakersfield, Calif. This giant field has 

produced a cumulative total of more than 552,-

000,000 barrels during its 73-year life. It has 

an effective drive because water in the aquifer 

is replenished by the Kern River where the 

producing zone crops out upstream from the 

field. 

Artificial water drive is usually used as a 

means of secondary recovery to supplement the 

primary driving mechanism and to achieve an 

increase in ultimate oil recovery. Muskat 

(1937) established the basic premise that when 

a porous medium is saturated with a native 

fluid. the introduction of a non-native fluid 

3 

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a: 

w 

Q. 

~ .3 

~ 

<l 

-1 

w 

a: .2 

.I 

.7 

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w 

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.... .2 ~ 

.I 

w 

a: 

.o~._.--=~~~~~--------~~--~.o 

0 2 0 40 60 80 100 

WATER SATURATION, percent 

FIGURE 3.-Relative permeabilities of oil and water 

as a function of water saturation. From Douglas, 

Peaceman, and Rachford (1959, p. 297). 

results in a decrease in permeability to the native fluid and an increase in permeability to 

the non-native fluid. In the case of a porous 

medium that is saturated with oil, the introduction of water as a non-native fluid results in 

a decrease of permeability to oil to essentially 

zero when the water saturation has reached 

about 80 to 90 percent and the oil saturation 

has been reduced to about 10 to 20 percent (fig. 

3). The relationship of permeabilities to water 

saturation, shown in figure 3, should be considered only a general relationship because of 

the influence of such variables as oil gravity, oil 

viscosity, and absolute permeability of a particular zone. The major significance is that by 

water flooding, a field usually can be ultimately 

abandoned in the safest possible condition, that 

is, with the relative permeability to oil reduced to a level that immobilizes the remaining 
oil in place. Alternatively, if the field were depleted by primary recovery only, then abandoned, and if even a nominal amount of natural 

water drive exists, reservoir pressures might, 

over a long period of time rebuild to near their 

virgin values. 

The relationship in figure 3 should not be 

interpreted to mean that water flooding will 

result in the recovery of 80 to 90 percent of the 

original oil in place. To attain such an end 

would require a perfect flood, which in turn 

would require a completely homogeneous zone 

of absolutely uniform permeability. Such conditions seldom, if ever, occur in nature. Consequently, some oil will be bypassed; some, in 

areas of low permeability and porosity, will be 

held in place by surface tension ; and some will 

never be reached by the sweeping effect of the 

flood. In fact, a highly successful water flood 

usually recovers on the order of 40 to 50 percent of the original oil in place. Water flooding, for many fields, is the only economical 

long-term secondary recovery method available. 

RESERVOIR CHARACTERISTICS OF 

DOS CUADRAS FIELD 

The primary recovery mechanism for the 

various reservoirs of the Dos Cuadras field is 

indicated to be solution gas drive. Only one 

reservoir is known to have a small gas cap; 

it is in the lower (H1Q) Green sand, south 

of Platform A, and is not open to production. 

Since solution gas appears to be the driving 

force in a relatively new field, the reservoir 

fluid must have been initially at, or near, saturation pressure. "Bubble point" of a reservoir 

fluid is defined as that pressure at which gas 

begins to be released from solution. If the reservoir fluid is saturated at virgin conditions, then 

"bubble point" and virgin pressure are equal. 

If the fluid is undersaturated, "bubble point" is 

lower than virgin pressure. 

As in any hydraulic system, fluids move 

through a reservoir as a result of pressure differential, with the movement being from higher 

to lower pressure areas. An oil or gas well 

produces because the pressure within the well 

bore is lower than the pressure in the surrounding reservoir. When reservoir pressure is reduced below "bubble point" and gas breaks out 

of solution, gas becomes a non-native fluid in 

4 

the reservoir. According to Muskat's premise, 

the net result is an increase in permeability to 

gas and a decrease in permeability to oil. The 

relative relationship is similar to that shown in 

figure 3, but relative permeability to water is 

replaced with relative permeability to gas and 

water saturation is replaced with reservoir 

pressure. Continued reduction in reservoir 

pressure (decrease to right in fig. 3) aggravates the changes in permeability and results 

in dissipation of reservoir energy. Inefficient 

recovery of oil results and is indicated by a 

gas/oil ratio in excess of the solution gas contained in the reservoir fluid. 

PVT (pressure-volume-temperature) analysis 

of a reservoir fluid sample from the upper 402 

zone, taken at a subsea depth of minus 1,490 

feet, indicated that the initial solution gas/oil 

ratio was approximately 115 cubic feet per 

barrel. During the early life of the Dos Cuadras 

field, the average overall gas/ oil ratio was 

about 250 cubic feet per barrel; by September 

1971, it had gradually increased to about 575 

cubic feet per barrel; and since, has gradually decreased to about 400 cubic feet per barrel 

at the present time. 

This energy waste, which has an adverse 

effect on ultimate oil recovery, can be retarded, 

or minimized, by a program of pressure maintenance. It can be completely avoided only if 

reservoir pressure is maintained at, or above, 

the "bubble point." Since it appears that the 

reservoir fluid was initially at, or near, the 

saturation pressure, it is not practical to maintain pressures above the "bubble point" nor 

would it be particularly desirable. 

The efficiency of a solution gas drive is substantially less than either a gas cap drive or 

a water drive simply because the driving energy comes from within the reservoir fluid 

itself rather than from an external source; 

that is, external to the oil bearing portion of 

the reservoir. Accordingly, improvement in 

efficiency along with greater ultimate oil recovery can be attained by supplementing reservoir energy with a program of pressure maintenance. For the Dos Cuadras field it appears 

that a feasible means of effecting a program 

of pressure maintenance is peripheral water 

injection. Such a program would be in the interest of conservation by increasing ultimate 
oil recovery. Additionally, as pointed out earlier, an artificial water drive is the best means 

of immobilizing the residual oil in place. 

A limited natural water drive probably exists 

in some of the "Repetto" reservoirs of the Dos 

Cuadras field. It is known that an aquifer exists; therefore, as reservoir pressures are reduced, the aquifer will expand. Some water 

encroachment into the reservoirs has occurred 

as attested by the fact that during the early 

productive life of the field the overall average 

water production was only about 2 percent of 

the gross production, whereas it presently 

amounts to about 40 percent. 

The areal extent of the various reservoirs 

in the "Repetto Formation" differs from reservoir to reservoir. On the other hand, it is probable that the areal extent of each aquifer is 

the same. If so, the degree of natural water 

drive will be related to the ratio of the volume 

of the aquifer to the volume of the oil reservoir. For the smaller reservoirs, the degree of 

effectiveness of natural water encroachment 

may be sufficient to flood the reservoir to depletion. Conversely, it is probable that the effectiveness of the natural water drive for the 

larger reservoirs will be minimal ; hence, it will 

be necessary to supplement it with artificially 

induced energy in the form of injected water. 

INJECTION WATER SOURCE 

Of significant importance in any water injection program is a source of water that is compatible with that contained in the injection 

zone; or, at least, does not have adverse effects 

on the formation into which it is being injected. In the case of an offshore water injection well an obvious source of supply is the 

surrounding sea water. Union Oil Co. made 

analyses of sea-water samples which are tabulated in table 1. 

In addition to these analyses, cores from the 

producing zones were flushed with sea water, 

with the results indicating only a minor reduction in permeability. On the basis of these 

laboratory analyses and core tests, it was concluded that sea water was a suitable injection 

fluid that could be used without filtration with 

the possible exception of times when turbidity 

was high. Accordingly, instrumentation was installed to provide a positive means of monitoring turbidity. During periods of high turbidity 

it was planned that the injection system would 

be shut down. Additionally, provisions were 

made for deaeration of the injection water, use 

of chemical corrosion inhibitors, and microbiological control. 

5 

Frequently, a more desirable source of injection water is the water produced in conjunction 

with the production of oil and gas. Since such 

water is formation water, it is usually compatible for reinjection into the formation. Use 

of produced water for injection has the additional advantage of being an environmentally 

acceptable method of disposal. Water from different zones is usually suitable for injection 

into any zone within the same formation even 

though there may be some chemical differences 

TABLE 1.-Sea-water samples from Santa Barbara 

Channel. Sampled April 30, 1968, at OCS-P 0241, 

well1 

[With the exception of pH, units are expressed in parts per million] 

50 feet 

pH ----------------------- 8.1 

~a ----------------------- 10,390 

Ca ----------------------- 414 

Mg ----.------------------- 1240 

Cl ------------------------ 18,300 

804 ---------------------- 2610 

COs ---------------------- 30 

HCOs --------------------- 90 

Total dissolved solids 

by evaporation ---------- 40,000 

Millipore filterable soHds --- 1.3 

Depth 

100 feet 

8.0 

10,390 

406 

1270 

18,200 

2630 

20 

105 

40,000 

2.5 

150 feet 

8.1 

10,580 

404 

1250 

18,200 

2630 

20 

100 

39,900 

1.1 

in the waters from the various zones. In the 

case of the Dos Cuadras field, chemical analyses 

have been made of the water produced from 

each zone in the "Repetto Formation". While 

the waters differ sufficiently enough that the 

chemical composition identifies the zone from 

which they were produced, water from any 

zone is suitable for reinjection in any zone. 

Since early February 1973, the water injected into well B-49-1 has been a composite of 

the free water produced at Platform B. The 

chemical analysis of a composite sample of produced water at Platform B is tabulated in 

table 2. 

When oil, water, and gas are produced from 

a well, some of the water is in the form of an 
TABLE 2.-Composite produced-water sample-Platform, 

B. Sannpled June 26, 1973 

[With the exception of pH, units are expressed in parts per 

million] 

pH ----------""- ----------------------8.0 ~a ----------------------------------7,600 Ca ----.- -----------------------------T·race 

]dg ---------------------------------49 

Cl ----------------------------------10,100 

SO, -------------------------------- ~ot detected 

COa ----------.-----------------------Trace 

HCOa -------------------------------3,09•8 Total dissolved solids by analysis ________________________ 20,84 7 

]dillipore filterable solids: 

Out of Quadricell ----------------28.2 

Out of filter -.--------------------13.0 

oil-water emulsion, and some of it is in an unemulsified or free state. The amount of free 

water increases as the percentage of water in 

the gross production increases. Since the present overall water production for the Dos 

Cuadras field is on the order of 40 percent of 

the gross production, considerable free water 

is being produced. Free water can be separated 

from the gross production stream by means of 

an oil-water separator known as a "fr.ee-water 

knockout." Such a separator is in operation on 

Platform B. 

Water from the free-water knockout usually 

is associated with some oil and suspended 

solids. The fluid is passed through a Quadricell 

unit for removal of these substances. The 

Quadricell unit in service on Platform B consists of four cells in series, each with an aerator mechanism to separate oil and suspended 

solids and carry them to the surface where 

they are removed by a skimmer. The unit is 

hermetically sealed and operates with natural 

gas aeration which results in a natural gas 

blanket over the fluid. The gas atmosphere 

prevents oxygen absorption, removes any oxygen present, and purges light hydrocarbons or 

entrained gases from the stream, with the 

gases being removed through a special vent. 

Prohibition of oxygen entering injection water, 

or its removal if it is present, is important in 

avoiding corrosion or scale formation by oxidation. 

Before the water is injected into the well, it 

is passed through a cartridge type filter to remove very small additional suspended solids. 

The millipore test data shown in table 2 were 

obtained using a 45-micron millipore filter. 

6 

This same test showed zero parts per million 

of hydrocarbons present in the injection water, 

but this should not be interpreted as ineaning 

the absolute absence of hydrocarbons. These 

data were obtained by using standard laboratory procedures for the determination of 

hydrocarbons in the form of oil and grease 

present in the water. Since the lighter ends 

of the paraffin series of hydrocarbons (methane, ethane, propane, normal butane, isobutane, 

pentane) have a degree of solubility in water, 

they are probably present but undetected by 

this laboratory procedure. 

SPECIAL INJECTION CONDITIONS 

On March 24, 1971, the Director of the 

Geological Survey approved the drilling of water injection test well B-49-1, lease OCS-P 

0241, subject to the following special conditions: 

"1. Coordination of Union's activities under 

this proposal with Sun Oil ·company 

toward the goal of unitizing the structure if a full scale waterflood is initiated. 

2. A representative of the Geological Survey 

must witness all initial water injection 

tests and all changes in rate of injection. 

3. A continuous and accurate pressure recording shall be made of all injection 

pressures. No injection shall be allowed 

without pressure recording. 

4. Injection pressures at the sand face in excess of 0.44 psi per vertical foot of 

water depth and 0.65 psi per vertical 

foot of rock overburden must first receive approval of the District Engineer. 

Complete justification for exceeding this 

minimum pressure must be made. 

5. In no event will a pressure in excess of 

0.44 psi per vertical foot of water depth 

and 0.80 psi per vertical foot of rock 

overburden be permitted. 

6. Adequate tests and surveys shall be conducted to detect any communication between any zones in the structure. 

Special emphasis will be placed on the 

quality of the cement job above the EP 

zone. The quality of this cement shall 

be verified with a cement bond log." 
DRILLING AND COMPLETION HISTORY 

In order to reach the aquifer of the EP and 

FP zones, it was necessary to drill well B-49-l 

with the slant rig set at an angle of 25 o. Additionally, because the bottomhole location was 

on the south flank of the anticline, it was necessary to use a platform drilling slot with a 

south-facing conductor. The well drilling commenced on May 2, 1971, and reached total 

depth on May 17, 1971. The hole was bottomed 

1,163 feet south and 290 feet east of the sur~ 

face location at a measured total depth of 2,625 

feet below the kelly bushing (KB). The true 

vertical depth ( TVD) was 2,290 feet below 

KB. The major geologic markers encountered 

are as follows : 

CP ---- DP --- EP ---

FP ----

Depth, in feet, from kelly bushing 

Measured 

816 

1,293 

1,520 

2,064 

True vertical 

723 

1,085 

1,278 

1,755 

NOTE.-Kelly bushing was 85 feet above sea level. 

Subsea 

depth, in feet 

- 638 

-1,000 

-1,193 

-1,670 

The various casing strings run in the well 

are at the following measured depths (MD), 

with respect to the kelly bushing (KB): 20 

inch at 316 feet, 16 inch at 417 feet, 133;8 inch 

at 734 feet, and 10% inch at 1,516 feet. All 

casing strings were cemented through the shoe 

except the 20 inch, which was driven about 11 

feet into the ocean floor. The EP and FP intervals were cased with an 8%-inch blank liner 

which was cemented through the shoe, extending from 1,331 feet to 2,620 feet (MDKB). 

In compliance with special condition 6, a 

cement bond log was run to confirm the quality 

of the primary cementing jobs. This log indicated that the cement bond for the 85/8-inch 

liner was not of good quality. Additionally, the 

lap between the 8o/s-inch liner and the 1034-

inch casing did not pressure test satisfactorily. 

Accordingly, the liner was perforated and 

squeeze cemented at various points to repair 

the primary cementing job. After squeeze cementing and cleaning out, the liner lap and all 

perforations were pressure tested with satisfactory results. A second cement bond log was 

run after the remedial cementing which indicated that good cement bonding had been attained. (For detailed well history, and well 

7 

mud and drilling records, see well data at end 

of report.) 

The well is completed with two strings of 

2o/8-inch tubing, a single packer at 2,019 feet, 

and a dual packer at 1,450 feet. The single 

packer is between the EP and FP zones to isolate them from each other and the dual packer 

is above the EP zone to seal the annulus between the tubing strings and the casing. This 

annular space is filled with inhibited sea water 

to prevent corrosion. 

INJECTIVITY TESTING 

Special condition 4 provided that initial injection pressure could not exceed a sand face 

pressure in excess of 0.44 pounds per square 

inch (psi) per vertical foot of water depth plus 

0.65 psi per vertical foot of rock overburden. 

If it became necessary to exceed this pressure 

to attain adequate injection rates, prior approv-al of the District Engineer was required. 

However, under special condition 5, in no 

event could the sand face pressure exceed 0.44 

psi per vertical foot of water depth plus 0.80 

psi per vertical foot of rock overburden. It was 

necessary during the injectivity testing to go 

to the higher pressures permitted by special 

condition 5, but it was accomplished in an incremental and controlled manner. The injectivity testing was monitored at all times by 

petroleum engineers and technicians from the 

Santa Barbara District office. As pressures 

were increased above those permitted by special condition 4, the increase was made in 50 

psi increments to establish stabilized flow. In 

this manner, any abnormal pressure or volume 

changes could be readily observed and corrected. No such changes were observed. 

The injectivity testing was conducted in six 

stages as depicted in table 3. The computation 

of permissible well-head pressures was made 

by neglecting friction losses in the injection 

string. This procedure results in an added 

safety factor, which for low rates of injection 

is negligible but for higher rates would be significant. 

All intervals open for injection were perforated with two jet shots per foot. Stages 1 

and 4 were perforated with a casing gun prior 

to running tubing, but the remaining stages 
TABLE 3.-Six stages of injectivity testing well B-49-llease OCS-P 0241 

Maximum permissible pressure ( psig) 

Perforated Subsea depth Stage Condition 5 interval Zone of top 

MDKB perforation 

1 2,376-2,427 F2P -1,959 

2,488-2,509 F3P 

2,516-2,523 F3P 

2 2,267-2,332 F1P -1,854 

2,336-2,364 F1P 

3 2,062-2,248 FP -1,668 

4 1,769-1,797 E2P -1,416 

1,804-1,914 E2P 

1,929-1,995 E3P 

5 1,643-1,754 E1P -1,303 

6 1,522-1,554 EP -1,195 

1,558-1,624 EP 

1 Well head is 47 feet above sea level. Water depth is 190 feet. 

(2, 3, 5, and 6) were perforated through the 

tubing using Schlumberger's 2-inch scallop 

gun. 

On June 4, 1971, before starting water injection, temperature and bottomhole pressure 

surveys were made. At 2,514 feet MDKB 

(minus 2,095 feet subsea), which is in the 

lower F3P interval, a temperature of 107.5°F 

and a pressure of 981 psig were recorded. In 

the early development life of the Dos Cuadras 

field, Union Oil Co. determined that virgin 

pressures in the "Repetto Formation" were 

equal to 0.44 psi per foot of subsea depth plus 

50 psi. These data would indicate a virgin pressure of 972 psig at the above depth of minus 

2,095 feet. Sun Oil Co.'s measurements of virgin pressure indicated a gradient of 0.45 psi 

per foot of subsea depth plus 40 psi. Using the 

Sun data, the anticipated virgin pressure would 

be 983 psig. It was concluded that the observed 

pressure in well B-49-1 was essentially a virgin pressure. 

Stage 1 injection (F2P and F3P intervals) 

was started on June 7, 1971. Under special condition 4 the maximum permissible well-head 

pressure was 352 psig. At this pressure the 

formation would not take any water. Accordingly, with the approval of the District Engineer, the pressure was increased in 50 psi increments. The formation started taking water 

at the rate of five barrels per hour when the 

injection pressure reached 550 psig. Increasing 

the pressure to the maximum allowed under 

special condition 5 (620 psig) did not appreciably increase the rate of injection, but it did 

8 

Condition 4 

Sand face Well head1 Sand face Well head1 

1,234 352 1,499 620 

1,165 330 1,415 580 

1,044 292 1,266 513 

881 239 1,064 423 

80·7 215 974 382 

73·7 192 888 343 

reveal that the single packer separating the FP 

and EP zones was leaking. The packer was 

reset and injection was resumed on June 21, 

1971. During the subsequent 4 days, the injected volume amounted to 94, 84, 100, and 72 

barrels per day at a well-head pressure of 620 

psig. 

On July 1, 1971, the F1P intervals (stage 

2) from 2,267 feet to 2,332 feet and 2,336 to 

2,364 feet were perforated. This perforating 

was done through the tubing, and the perforating gun found sand fill at 2,477 feet MDKB 

sealing off all of the F3P interval. Because of 

the higher perforated interval of 2,267 feet, 

the maximum permissible injection pressure 

was reduced to 580 psig. At this pressure, the 

average daily rate was only 37 barrels of water 

per day. 

On July 12, 1971, the injection intervals 

were acidized in one stage with 2,000 gallons 

of 71;2-percent hydrochloric acid, and in a second stage with 1,000 gallons of 9-percent hydrochloric acid and 6-percent hydrofluoric acid. 

Seventy-five pounds of a diverting agent, 

known as Matriseal II, were used to make the 

acid enter the tighter formations. This acidizing job was quite successful in increasing injectivity. During the 6 days following the acid 

treatment the injection rate averaged 1,695 

barrels per day at an injection pressure of 580 

psig. 

On July 19, 1971, the FP interval (stage 3) 

was perforated from 2,062 feet to 2,248 feet. 

The maximum permissible injection pressure 

for this interval is 513 psig, and it has subse-
quently been maintained at 510 psig most of 

the time. At this pressure the average injection 

rate during the next 11 days was 774 barrels 

per day. 

A second acid treatment of the FP intervals 

was performed on August 5, 1971. This treatment used 3,000 gallons of 9-percent hydrochloric and 6-percent hydrofluoric acids with 

200 pounds of Matriseal II diverting agent. 

Again the injection rate was improved. During 

the ensuing 10 days the average injection rate 

was 1,560 barrels per day at a pressure of 510 

psig. 

Stage 4 injection (E2P and E3P intervals) 

started on August 5, 1971. However, after 2 

days during which 160 barrels were injected at 

a pressure of 100 psig, the pressure controller 

malfunctioned and was repaired. Injection was 

resumed on August 12, 1971. The maximum 

permissible pressure for this .stage was 423 

psig. The injection pressure was incrementally 

increased to 420 psig, and for a 4-day period 

the average injection rate was 2,027 barrels per 

day. 

On August 18, 1971, the E1P (stage 5) interval was perforated from 1,643 feet to 1, 754 

feet MDKB. The maximum permissible injection pressure for this interval was 382 psig. 

The injection pressure was gradually increased 

to 380 psig. The injection rate averaged 1,551 

barrels per day at this pressure. 

On August 26, 1971, the EP (stage 6) interval was perforated from 1,522 feet to 1,554 

feet and 1,558 feet to 1,624 feet MDKB. The 

maximum permissible injection pressure for 

this interval was 343 psig. However, injection 

at a pressure of 230 psig resulted in an average 

rate of 1. 779 barrels per day for the next 19 

days. The injection pressure was then increased 

to 250 psig and has remained at that point or 

lower to date. 

On May 12, 1972, the EP interval was treated 

with a total of 3,000 gallons of 15-percent hydrochloric acid and 200 pounds of Matriseal II. 

On May 20, 1972, the FP interval was treated 

with 3,000 gallons of 15-percent hydrochloric 

acid and 150 pounds of Matriseal II. Table 4 

shows that these acid treatments more than 

doubled injectivity into the EP interval and 

somewhat less than doubled injectivity into the 

FP interval. 

9 

WITHDRAWAL AND INJECTION HISTORY 

The upper 402 zone is comprised of the EP, 

FP,/CQ, DQ, and EQ intervals. Where these intervals are productive the reservoir fluids are 

commingled in a single well bore; therefore, it 

is not possible to maintain an exact record of 

production from each interval. Calculation of 

the original oil in place indicates that approximately 70 ·percent of the total in the upper 402 

zone was contained in the EP and FP intervals. 

Allocation of withdrawals, by intervals, is made 

on the basis of original oil in place. On this 

basis, through May 31, 1973, the EP interval 

has produced 9,213,112 barrels of oil, 2,576,000 

thousand cubic feet of gas, and 440,286 barrels 

of water. The FP interval has produced 4,691,-

579 barrels of oil, 1,610,000 thousand cubic feet 

of gas, and 275,160 barrels of water. These 

data are for lease OCS-P 0241 only. They do 

not include production from lease OCS-P 0240. 

PVT (pressure-volume-temperature) analyses 

of re~ervoir fluid samples in the early life of 

the Dos Cuadras field indicated that the formation volume factor (the ratio of the volume 

of a barrel of oil in the reservoir under reservoir conditions and that same barrel of oil at 

the surface under atmospheric conditions) for 

the EP interval was 1.039 and for the FP interval it was 1.061. Typically, in a reservoir 

with a solution gas drive recovery mechani<Sm, 

formation volume factor decreases as fluid is 

withdrawn from the reservoir. In the case of the 

Dos Cuadras field, the production, to date, has 

been only a smal1 portion of the volume of the 

initial oil in place; hence, volume of reservoir 

space voided can be closely ~pproximated at this 

point in time by using the originally determined 

formation volume factors. Through May 31, 

1973, calculation indicates that 10,012,709 barrels of reservoir volume has been voided in the 

EP interval and 5,252,925 barrels in the FP 

interval. 

Table 4 depicts the water injection history of 

well B-49-I, lease OCS-P 0241. To date, there 

has been no discernible reaction at the nearby 

producing wells; there has been no breakthrough of water; there has been no detectable 

change in producing characteristics; and there 

has been no observed anomaly in bottomhole 

pressures. Lack of reaction to water injection 
TABLE 4.-Wa.ter injection history of well B-1,9-llea.se OCS-P OBJ,1 

Date 

Water injected (bbls) Water injected (bbls) 

Days of Dally Well-head Days of Dally Well-head 

injection Monthly Cumulative average pressure injection Monthly Cumulative average pressure 

19'11: 

June -------- July -------- August ------ September __ 

October ----- November __ _ 

December ---- 19'1~: 

January ---- February ----

March ------ April ------- May -------- June -------- July -------- August ----- September --- October ----- November __ _ December __ _ 

19'18: 

January ---- February ---- March ------ April ------- May --------

EP interval (Upper yellow) 

0 

0 

19 

26 

28 

so 

S1 

31 

29 

2S 

28 

28 

so 

S1 

so 

so 

28 

29 

S1 

4 

26 

S1 

29 

S1 

0 

0 

30,419 

S9,49S 

28,077 

40,654 

48,021 

S7,164 

S6,191 

16,895 

18,025 

S8,590 

43,422 

44,120 

44,120 

29,654 

26,278 

22,698 

22,230 

2,557 

6,827 

2,798 

2,639 

2,936 

0 

0 

30.419 

69,912 

97,989 

138,64S 

186,664 

223,828 

260,019 

276,914 

294,939 

333,529 

S76,951 

421,071 

465,191 

494,845 

521,12S 

54S,821 

566,051 

568,608 

575,4S5 

578,2SS 

580,872 

583,808 

0 

0 

1,601 

1,519 

1,00S 

1,S55 

1,549 

1,199 

1,248 

735 

644 

1,S78 

1,447 

1,42S 

1,471 

988 

9S9 

78S 

717 

6S9 

26S 

90 

91 

95 

0 

0 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

250 

135 

'14 

60 

55 

is not unexpected inasmuch as the ratio of injected volume to withdrawal volume is nominal. 

For the two intervals, the volume of injected 

water has amounted to only 5.83 percent of the 

reservoir volume voided for the EP intervals 

and 8.19 percent for the FP intervals. 

SPECIAL TESTS AND SURVEYS 

Special condition 6 imposed a requirement 

for various tests and surveys with particular 

emphasis on verification of the quality of the 

cementing of the 85/8-inch liner through the EP 

and FP intervals. Additionally, an initial bottomhole formation pressure was determined 

and a base-line temperature gradient was run. 

These last two items are of primary value for 

future use for comparative purposes during the 

life of the well. All three of these special tests 

have been discussed earlier. 

The single packer installed to separate the 

EP and FP intervals was discovered to be leaking during the initial injection. After resetting 

the packer and resuming injection, the F2P and 

F3P intervals were accepting water at a rate of 

less than 100 barrels per day even though the 

well-head pressure was at the maximum permissible pressure of 620 psig. It was known that 

the permeability of these intervals was such 

that the injection rate should be higher; there10 

10 

so 

31 

26 

28 

30 

S1 

31 

29 

23 

28 

28 

30 

31 

30 

30 

28 

29 

31 

4 

24 

81 

29 

S1 

FP interval (Upper purple) 

1,434 

18,2S6 

39,454 

S0,767 

26,864 

25,048 

24,8S5 

17,008 

16,388 

9,79S 

10,'1SO 

11,564 

23,310 

19,315 

16,285 

1S,871 

15,0S7 

14.918 

16,495 

1,539 

1S,562 

20,791 

20,876 

22,26S 

1,4S4 

19,6'10 

59,124 

89,891 

116,755 

141,80S 

166,638 

18S.646 

200,0S4 

209,827 

220,557 

2S2,121 

255,4S1 

274,746 

291,081 

304,902 

S19,989 

3S4,857 

S51,S52 

852,891 

866,45S 

S87.244 

408,120 

4SO.S8S 

143 

608 

1,27S 

1,183 

959 

8S5 

801 

549 

565 

428 

383 

41S 

7'17 

62S 

543 

462 

5S7 

514 

532 

S85 

565 

671 

720 

718 

620 

545 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

510 

250 

S96 

500 

500 

500 

fore, it was postulated that reduction in permeability had occurred during the drilling of the 

well because of local invasion of the formation 

with drilling fluid in the immediate vicinity of 

the well bore. In order to confirm this theory a 

pressure "fall off" survey was made during the 

period of June 25 to 28, 1971. To make this survey, injection was stopped while dual bottomhole pressure gauges equipped with 120-hour 

clocks were run to 2,024 feet MDKB (minus 

1,635 feet subsea). Injection was then resumed 

at a surface pressure of 620 psig for 5 hours to 

established stabilized flow. The pressure observed during this period was 1,390 psig. Injection was then stopped for 50 hours to permit 

the fluid ·Column to stabilize at reservoir pressure. For the last 4 hours of this period the 

pressure was stable at 734 psig. Injection was 

then resumed for 30 hours before removing 

the pressure gauges and the observed pressure 

was 1,394 psig, essentially equivalent to the 

first observation of 1,390 psig. 

The observed injection pressure of 1,390 

psig at minus 1,635 feet subsea, with a surface 

pressure of 620 psig, indicates that the gradient 

of the fluid column was 0.471 psi per foot of 

vertical depth. This value would include friction 

loss, which would be negligible because the flow 

rate was only about four barrels per hour 

through 2'Vs-inch tubing. Extrapolating the ob-
served static pressure at minus 1,635 feet subsea to minus 2,095 feet subsea with a gradient 

of 0.471 would result in a pressure of 951 psig 

at the lower depth. The initially observed bottomhole .pressure at this lower depth was 981 

psig, which earlier was considered to be in the 

appropriate range of a virgin bottomhole pressure. With the "fall off" test indicating a formation pressure some 30 psi lower, it was concluded that there had been reduction in permeability during the drilling of the well. The 

previously reported successful results of the 

acid treatments of July 12 and August 5, 1971, 

confirmed this conclusion. 

On July 29, 1971, an injection profile survey 

was run on the FP, F1P, F2P, and F3P intervals. This survey revealed that 71 percent of 

the injected water was entering the F1P interval and 29 percent into the F2P. There was no 

entry into either the FP or F3P intervals. The 

sand fill at 2,477 feet MDKB, some 11 feet above 

the F3P interval, was the most likely reason 

for lack of entry into this interval. The second 

acid treatment of August 5, 1971, was performed subsequent to the injection profile survey for the purpose of improving the injection 

profile. As previously reported, it increased injectivity substantially. 

On January 7, 1972, radioactive tracer surveys were made of both the EP and FP intervals. Both of these surveys revealed that 

neither the packer was leaking nor was there 

any upward movement of fluid above the top 

perforation of either interval. The survey also 

revealed that the FP interval was taking water, 

which is probably the result of the acid treatment of August 5, 1971. 

SUBSIDENCE INVESTIGATIONS 

On May 12 and 13, 1969, a special scientific 

panel of the DuBridge Committee met in Los 

Angeles to consider future operations of lease 

OCS-P 0241. This panel recognized the possibility of subsidence in their recommendation 5 

where they stated: "Reduce pressures throughout the reservoir to hydrostatic or less and 

maintain pressures with water injection, if 

needed, to minimize subsidence." (Emphasis 

added.) U.S. Geol. Survey Professional Paper 

679 also refers to the possibility of subsidence 

(McCulloh, 1969, p. 45-46; Hamilton and 

others, 1969, p. 65-66). 

There are four general causes of subsidence: 

(a) subsurface removal of solids; (b) compaction of dry surface soils by wetting ; (c) 

tectonic movement; and (d) net withdrawal of 

subsurface fluids. The first two do not concern 

Dos Cuadras operations. Tectonic subsidence 

could conceivably occur, but it is not within the 

scope of the discussion in this report. It is now 

generally accepted that oil-field subsidence, 

when it does occur, is caused by withdrawal of 

reservoir fluids. It is, therefore, a reasonable 

conclusion that if subsidence does occur at Dos 

Cuadras it will be caused by withdrawal of reservoir hydrocarbons and water that are not 

replaced by another fluid, either injected or 

supplied by natural water drive. 

Some concern has been expressed that if subsidence should occur it might result in aggravation of the seepage problem at the crest of 

the Dos Cuadras structure. Fault movement as 

a result of subsidence is unlikely to occur in the 

present area of seepage. This type of subsidence faulting is normally experienced only 

around the periphery of the productive area, 

subparallel to the isobase contours, as a result 

of tension strains. In the center of the productive area, where subsidence is generally greatest formations undergo compaction, but the 

compressive force is seldom great enough to 

produce surface faulting. Therefore, even if 

there is subsidence, the seep areas are on the 

crest of the structure where surface faulting 

would not normally occur. The foregoing conclusion concurs with the statement in Professional Paper 679, (McCulloh, 1969, p. 45), that 

"It is possible that subsidence would be accompanied by localized peripheral tensional fracturing of the capping layers." 

11 

An additional significant point is that the 

occurrence of subsidence cannot be predicted. 

McCulloh (1969, p. 45) states: "The numerous 

complexly interrelated variables that determine 

whether or not subsidence occurs when pore 

fluids are withdrawn from a reservoir are understood so poorly that accurate prediction beforehand of the amount of subsidence is difficult, if not impossible." Similar opinions are 

held by many of the experts in the field of 

subsidence. It would appear to be more im-
portant to anticipate that subsidence may occur 

and to monitor it, so that, if it does, early detection will permit a course of remedial action to 

minimize it. 

To this end, the Pacific Area initiated a program in mid-1970 with the operators of leases 

OCS-P 0240 and 0241 to determine platform 

elevations with a degree of accuracy that would 

detect minute subsidence. First, bench marks 

were established on each corner of the three 

platforms in the Dos Cuadras field. By periodically running elevations on these bench marks 

any tilting of the platform would be discovered. 

Second, the lease operators were requested to 

investigate the possibility of determining the 

elevation of each platform with respect to a 

known datum so that any change in elevation 

could be detected. 

To obtain the latter information, it was 

planned that simultaneous measurement of reciprocal vertical angles from the platforms and 

a point of known elevation on land would yield 

accurate results because it would eliminate the 

need to apply corrections for curvature of the 

earth and refraction of light in the atmosphere. 

However, in attempting to use this method it 

was found that small vibrations caused by drilling and production machinery on the platforms 

made it impossible to measure an accurate vertical angle from the platform end of the survey line. Because of the distance involved, to 

survey from the land end of the line only would 

require correction for both curvature and refraction. Inasmuch as refraction will vary 

somewhat with atmospheric conditions, repeatability would not be such that a later survey 

would determine that there had been a small 

change in elevation. It was estimated that surveying from the land point only would yield 

results that were accurate to only about + 6 

inches. 

Research by Lewis & Lewis Offshore, Inc., 

offshore surveyors of Ventura, Calif., revealed 

that an accurate elevation could be determined 

from records obtained with recording tide 

gauges installed on each platform. They estimated that a 60-day study would result in an 

accuracy of ±0.1 foot, when compared with 

a suitable known station, and a 1-year study 

should provide an accuracy of ±0.05 foot. The 

National Ocean Survey of the National Oceanic 

and Atmospheric Administration (formerly the 

U.S. Coast and Geodetic Survey) has a tide 

station on nearby Rincon Island from which 

monthly reports are available for use as a 

standard station. Even without a standard station, any change of elevation of a particular 

platform would become apparent by comparing 

data obtained from each platform. 

There are two basic types of tide gauges. 

One is a float type water-level recorder which 

requires the installation of a stilling well to 

eliminate the effect of wave action and surges. 

The other is a nitrogen pressure bubble gauge 

which does not require a supporting structure. 

Both types of gauges record water level on a 

30-day clock driven strip chart. Both Union Oil 

Co. and Sun Oil Co. chose to use the water-level 

recorder type for their Platforms A, B, and 

Hillhouse. All three installations were made and 

became operational on October 1, 1971. 

There are several tidal datum planes th~t can 

be computed from the data recorded by the tide 

gauges, such as : ( 1) daily highs and lows, ( 2) 

mean high water, (3) mean low water, (4) 

mean higher high water, (5) mean lower low 

water, (6) mean tide level, (7) diurnal high 

water inequality, and (8) diurnal low water 

inequality. Computation of several of the datum 

planes provides a "built in" check on computed 

results. 

During the 20 months that the tide gauges 

have been in operation, since October 1, 1971, 

there has been no discernible change in relative 

elevation of the three platforms. The determination of absolute elevations of the platforms 

by comparison to the Rincon Island tide station 

has not yielded consistent results. Since there 

has been no relative change in elevation of the 

platforms one must conclude that either (1) 

the platforms are all changing in unison or (2) 

that the Rincon Island station is itself changing 

in elevation. The second condition seems to be 

the more likely, because the probability of the 

three platforms, each separated from the other 

by approximately 2,800 feet, consistently changing together is extremely remote. Surveys of 

the bench marks on the corners of the platforms have not indicated any tilting. The lack 

of any measurable differential subsidence adds 

to the probability that the platforms have not 

changed in elevation. These results are not sur12 
prising as reservoir fluid withdrawal has been 

relatively nominal with respect to the initial 

volume of oil in place. Nevertheless, acquisition 

of these data early in the productive life of the 

Dos Cuadras field will serve as a reference for 

comparison with future data. 

CONCLUSIONS 

In their original planning of this water injectivity test, Union Oil Co. reviewed injection 

projects in California oil fields with reservoir 

characteristics similar to the Dos Cuadras field. 

These investigations revealed that, in general, 

the injectivity index ranged from less than 1 

to as much as 10 times the productivity index. 

On the assumption that the injectivity index 

would equal the productivity index, it was anticipated that the average water injection rate 

into the Yellow (EP) or Purple (FP) intervals 

would be on the order of 1,500 barrels per day. 

However, the primary purpose of this B-49-I 

injectivity test was to acquire information under actual field conditions to be used for a 

comprehensive analysis in planning a full-scale 

water injection progr.am for the "Repetto" reservoirs in the Dos Cuadras field. 

From the information contained in this report one can reasonably draw the following 

conclusions: 

1. All phases of this inj ectivity test have 

been conducted in conformity with applicable 

regulations, OCS orders, and the six special 

conditions imposed upon this project. 

2. The water injection rate into the Yellow 

(EP) interval has been approximately that anticipated in the original planning. During the 

first year, the daily average injection rate was 

1,261 barrels at a well-head pressure of 250 

psig. The maximum permissible injection pressure for this interval i.s 343 psig. By extrapolation, if the well-head pressure were increased 

to 343 psig the injection rate would be about 

1,730 barrels per day. However, during recent 

months an unsatisfactory injection profile has 

developed in this well, and injection has been 

reduced until the condition can be corrected. 

Maintenance of a uniform injection profile is 

highly desirable; otherwise, the advancing front 

of the water flood would not be uniform and 

would result in water reaching a producing well 

in a part of the interval, while other parts 

would not be efficiently swept by the flood. 

3. The water injection rate into the Purple 

(FP) interval has not been as high as expected. 

During the first year, the daily average rate 

was 714 barrels at the maximum permissible 

well-head pressure of 510 psig. It is known that 

the F3P interval is covered with sand fill and, 

hence, is not accepting any injected water. Acid 

treatment of this interval has had good results; 

for example, during the month of August 1971 

after two acid treatments the daily average injection rate was 1,273 barrels at a well-head 

injection pressure of 510 psig. It is probable 

that by cleaning out the sand fill and using additional acid treatments the injection rate can 

be improved. 

4. Whether or not subsidence will occur in 

a particular oil field cannot be predicted. If it 

does occur, it will be the result of fluid withdrawal from the reservoirs. Additionally, the 

major problems created will be operational 

with little likelihood of causing any damage to 

the environment. At the present time the best 

known method to minimize subsidence is toreplace the withdrawn fluid with an equivalent 

volume of another fluid; in this instance, water. The Pacific Area of the Conservation Division, USGS, has required a monitoring system 

so that should any subsidence occur it will be 

detected in its early stages, thus permitting 

early corrective action. 

5. The overall concept of water injection into 

reservoirs such as the "Repetto" reservoirs of 

the Dos Cuadras field has a sound engineering 

basis. Early initiation of such a project results 

in a pressure maintenance mechanism, whereas, if it were delayed until the late productive 

life of the field it would be a secondary recovery method and result in lower oil recovery 

efficiency. A full-scale water injection program 

for the "Repetto" reservoirs of the Dos Cuadras field should reasonably be expected to yield 

the following beneficial results : (a) increase 

ultimate oil recovery, thus conserving a depletable natural resource ; (b) decrease the productive life of the field, thereby permitting the 

return of the area to its natural environment 

at an earlier date; (c) inhibit subsidence, or, 

should it occur, minimize it; and (d) immobilize most of the residual oil in place thus, 

13 
upon abandonment, leaving the field in a condition so as to prevent or minimize possible 

future seepage. 

REFERENCES CITED 

Douglas, Jim, Jr., Peaceman, D. W., and Rachford, H. 

H., Jr., 1959, A method for calculating multi-dimensional immiscible displacement: Am. In st. Mining Engineers Trans. 216. 

14 

Hamilton, R. M., Yerkes, R. F., Brown, R. D., Jr., Burford, R. 0., and DeNoyer, J. M., 1969, Seismicity 

and associated effects, Santa Barbara region: U.S. 

Geological Survey Prof. Paper 679-D, p. 47-68. 

McCulloh, T. H .. 1969, Geologic characteristics of the 

Dos Cuadras offshore field: U.S. Geological Survey Prof. Paper 679-C, p. 29-46. 

Muskat, Morris, 1937, The flow of homogeneous fluids 

through porous media: New York, McGraw-Hill 

Book Co., Inc. 
FIGURES 4-7 AND WELL DATA 
1-l 

CJ) 

53 

58 

57 

''2oo·/-~ 0 ~ o d' 

I \ f~ ~ N e.1 ' -1200' \ 

/# 

~ ~ 

'//00, 

-------

~ 4!1 . •· ' '-. ...... I ~o ·' ' ./.... -- .... '· ~-'••n•-••J-- \-,, ~1 -., o_...~~- \ , I ,, 

' ', I ' 

~ ''/<'6'9·r. .. ,,____ ---.... ""' \ ~... ,, ..... ..... ...... -,.. .,.00. ... ... _ ......... ... ......... 

. ~ POOPBHCOO\ ':::,": ...... ._._ ._ 

y ~-~--~ t-----._ - -------.: ......... 

.......__ 

DOS CUADRAS FIELD 

SANTA BARBARA CHANNEL 

STRUCTURE CONTOURS 

TOP OF 'EP' 

PROPOSED LOCATION B-49-I 

LEASE OCS- P 0241 

......... 

I j ~ /~oo, 

.............. __ 

0 500 FEET 

FIGURE 4.-Structure contours for the top of the EP interval. 
...,. 

~ 

58 

/ 

57 

/ -,,/ /z 

/ 

3 /~-

/ N 

V,/ / 

DOS CUADRAS FIELD 

SANTA BARBARA CHANNEL 

STRUCTURE CONTOURS 

TOP OF 1FP 1 

PROPOSED LOCATION B-49-I 

LEASE OCS- P 0241 

I' 

/ 

0 500 FEET 

FIGURE 5.-Strueture contours for the top of the FP interval. 

~ 

4e~ 

£.~:.-,~,~ 

Q){ ....

............ .................. .......... ~ ...........__ ............ ....... ...........__ ..... _ ...... _ 8o ,~-
~ 

00 

53 

57 

N 

v/ 

DOS CUADRAS FIELD 

SANTA BARBARA CHANNEL 

STRUCTURE CONTOURS 

TOP OF 1GP 1 

PROPOSED LOCATION B- 49- I 

LEASE OCS-P 0241 

_,9~0-----------

- 22oo·-----:r 

-•,oo-~ 

- -R3oo· -2300' ~~/ --------

----- 0/WMa;r -234 • 

-••oo·_ 6 '•·"----------

'l 

0 ~~~ 

FIGURE G.-Structure contours for the top of the GP interval. 
~ ELEV.+88' 

\ 

B-49-I 

DOS CUAORAS FIELD 

SANTA BARBARA CHANNEL 

MEAN SEA LEVEL 

CROSS SECTION THROUGH 

PROPOSED LOCATION 

WELL NO. B-49-I 

·200' 

-400' 

-1000' 

-1200' 

-1400' 

-1600' 

-1800' 

-2000' 

-2200' 

-2400' 

\ 

\ 

\ 

\ 

\ 

\ 

\ 

\ 

\ 

~ 

---EP 

LEASE OCS-P 0241 

500 FEET 

I 

FIGURE 7.-Cross section :through well No. B-49-1. 

19 

- ·1289' EP 

Mo-. 

- -1768' FP 

- -1919'FIP 

Max 

TMO 28001 

iVO 24781 

550 -23901 

5 12°E 11301 
v. UNITED STATES SVBMIT IN DUPLICATE• Form approved. 

( SN• othPr In· Budget Bureau No. 42-R365.6. 

DEPARTMENT OF THE INTERIOR stru<"tions on 5. ---------------- rt·verse side) l.t:ASE DESIGNATION AND SERIAL NO. 

GEOLOGICAL SURVEY ocs Tract p 0241 

WELL COMPLETION OR RECOMPLETION REPORT AND LOG* 6. Ill' INDIAN, ALLOTTJillol OR TRIBII NAME 

-- la. TYPE OF WELL: ~~~LL 0 ~~~~ .. 0 DRY 0 Injection 7. !'NIT AGREt:AIENT NAMII OthPr 

b. TYPE OF COMPLETION: -- ~-~:'::1. ~ (~~·~~!{ 0 ~~·:p. 0 ~:~~ 0 ~:~~·n.O OthPr S. I''ARM OR LII:ASII: NAMII 

2. NAME OF OPII:RATOR p 0241 (Platform "8") 

Union Oil Company of California 9. WII:LL NO. 

3. AllDRESS Oil' OPERATOR B-49-1 

2427 E. Harbor Rlvd., Ventura, Calif. 93003 10. FIELD AND POOL, OR WILDCAT 

4. I.OCATION OF WEI.L (Report location clearly and in accordance with an11 State requirement•> • r>os Cuadras At surface Lambert Grid Zone VI 11. SEC., T., R., M., OR BLOCK AND SURVEY 

X = 9R2,170 y = 804,516 OR ARE.t. 

At top :p.,. Interval reported below 

X ="Inj. 982,296 y = 803,738 SIN 65W ~fap 68 At total deptli 

X = 982,422 y 803,344 114. PERMIT NO. DATE ISSI!ED 12. COUNTY OR 

I 

13. STATE 

= I PARISH 

-- -- -- - ·• -

HI. DATE sPUDDED 116. DATE T.D. RE.t.CHED 11" DATE COM PL. (Ready to prod.) 118. ELEVATIONS (oF, RKB, RT, ca, ETC.) • 119. ELEv. R • T. 

5-2-71 5-17-71 8-27-71 Water depth 190' 85' above LLMT 20. TOTAL DEPTH, MD a TVD 121. PLUO, BACK T.D., li(D a TVD 122. IF Ml'J,TIPI.E COMPL., 123. INTERVAJ,S ROTARY TOOLS CABLE TOOLS HOW MANY• DRILLED BY 

2625'~fD/2290'VD 2551 '~lr>/22l<>'VD Dual -.~_._l_t_o_T_._D_._~~,i;--::~-=-====-

24. -~1M INTERVAJ,(S), 011' THIS COMPLETION-TOP, BOTTOM, NAME (MD AND TVD)• (Purple) 125. W.t.S DIRECTJON.t.L SURVEY MADII 

injection 

1522 'HD/1280 'VD - 1995 '~ID/1695 'VD (Yellow)2062 '~10/ 1753 'VD-2523 'HD/2189 'VD Yes 26. TYPE ELEcTRic AND oTHER LoGs RUN Nr.fL and CD~·1 1 ogs . 21. wAs wELL coa110 

Dual Induction Laterolog, Cement Rond Lo , Gamma Ray Lop, FDC, CNP, Yes 2S. CASING RECORD (Report aU /ftring11 11et in tDell) 

CASINO SIZE WEIGHT, LB./J'T. DEPTH SET (MD) --- ----- ~-----

CEMENTING RECORD 

:l HOLE SIZE A~IOUNT PULLIID 

20" 104 .13# 316' -- Driven 

16" 75 417 20 250 sc "G" + 3% CaCl 

13-3l8" 40.5 734 t7-tL2 200 sx Gilsonite & 1~0 "G" 

l0-3l4" 32 1516 15 500 sx Gilsonite & 150 "G" 29. LINER RECORD 30. TVBING RECORD 

SIZE 

I 

TOP (MD) I ~,.,...(MD} lue&s n••MT• 

I 

SCREEN (MD) SIZE 

I 

DEPTH SliT (MD) 

I 

PACKER Sll'l' (MD) 

8-5LB" 1331' 2620' 625' Blank 2-7/8" 2038' 2016' 

2-7/8" 1454 1451 31. PERJ'ORATION RECORD (Interval, llize and numOer) 82. ACID, SHOT, FRACTURE, CEMENT SQUEEZE, ETC. 

DEPTH INTERVAL (MD) AMOI!NT AND KIND 011' MATERIAL USJ:D 

EP 1522-1995' 2 - 1/2" SPF 2267-2523' 2000 gal. 7-1/2% HCI 1000 ga 1. 

FP 2062-2523' 2 1/2" SPF 9-6 HCI-HF 

2062-2523' 3000 sal. 9'6-6'6 HCl-HF 

33.• tn]eCtlOn PRODUCTION 

DATil FIRST e!WIIttK:t:•a ~PRODUCTION METHOD (F'lotDing, ga11 lift, pvmping-aize and tflpe·of pump) I WJ:LL sTATUS (Prodvcing or 11Aut-in) 

6-7-7l(FP)8-5-71( P) Injection well on injection DATE OJ' TIIST I HOURS TESTE.-;::D--,;-::C::H::-OK~II;."-:S::;IZ:-:E:--;,-T=p:=-=~=~7:·~=-.E-=:=-=~o::-"o---:O::-:I:-L-----::B:=B:-L.----:G:-:A-::S---=A~I c=v=-. -----:r=-~-:-::~===~---=n:=-)--fi-:-G:-:A-:<I-:-D:-:-u---= • .u.::-:-:'li:::::0-

9-19-71 24 ___.... 11379 illl 

Inj. 'I'UII!No ...... , cAsiNG PREsst:RE I cALCULATJ:D OIL-BBl.. cAs-Mcr. WATER-BBL. • I OIL GRAVITY·API <coBB.) 24·HOUR RATE 

510(FP)250(EP) 34. DISPOSITION OJ' GAS (Sold, - Ulled for fuel, vented, ~ 

etc.) 

35. LIST OJ' ATTACHMENTS 

36. I hereby certify that the foregoing and attached Information Ia complete and correct u determined from all available recordS 

Orig. 

siGNED: R. 0. Engebretsen TITLE Drilling Engineer DATJD 9-21-71 

*(See Instructions and Spaces for Additional Data on Reverse Side) 

20 
UNION OIL CO. OF CALIFORNIA 

WELL RECORD 

SHEET A 

PAGE NO. ___ l ____ __ 

LEASE OCS-P 0241 WELL NO. B-49-1 

F 1 E L D Dos Cuadras 

LOCATION Conductor 1#49 

Lambert Grid Zone VI 

X= 982,170 Y = 804,516 at R.T. 

PERMIT NO.~----- SERIAL NO·-~~~--

T.D. 2625' T.V.D 2290' 

DE VI AT I 0 N (B. H. L.) ------------------------

COMPANY ENGINEER--------------------

SPUD DATE 5- 2- 71 COMP.DATE__-__-_l---=~-­ CONTRACTOR Bawden Drlg. Co. RIG N0._8=-----

TYPE UN IT National 55 at 25° 

D f-lthR 1 ~H ,D i~f .R lfgd oti~e~/ 2" FH 16. 60, 18° taper 

ELEVA T I 0 N S: WATER DEPTH -=19::;...;0::;...;' ________________ _ 

R. T. TO 0 C EA N FLOOR -30~4~'~------------­

R. T. TO M L L W .......:9~4=-'~------------­

R. T. T 0 DRILL DECK _1~7:::-:-' --------------

R.T. TO PRODUCTION DECK ....:4:...:::3;...'--~----------­ APPROVED: Orig. Sgd: R. 0. Engebretsen 

CASING & TUBING RECORD 

SIZE WEIGHT THREAD GRADE DEPTH REMARKS 

20" 941 Welded IC-55 316' Driven 

16" 75 Buttress K-55 417' Cmtd W/250 sks. "G" + 3% CaC1 2 

13-3 8 54.5 Seal-lock K-55 734' Cmtd w/200 sks. Gilsonite + 100 sks "G"+ 3% CaC1 7 

10-3'4 40.5 Buttress K-55 1516 1 Cmtd w/500 sks. Gilsonite + 150 sks "G"+ 3'0 CaC1 7 

8-5 8 32 Buttress K-55 2620 1 Cmtd w/475 sks. Gilsonite 2% NaCl, 3/4% CFR2 

2-7'8 6.5 A-95 Hvdril J-55 1454 1 

2-7t8 6.5 A-95 Hvdril J-55 2038' 

PERFORATING RECORD 

DATE INTERVAL E.T.D. RE:ASON PRESENT CONDITION 

5-21-71 2370' l4Jl/2" ho es Squeezed Squeezed· w/150 sks. "G" cmt and 3% CaC1 7 

5-22-71 2260' (4)1/2" ho es Squeezed Squeezed wf75 sks. "G11 cmt and 3lli CaCl., 

5-23-71 2030' ( 4 H/211 ho es Squeezed Unable to break down formation. 

5-23-71 2040' !4) 1/211 ho es Squeezed Squeezed w/200 sks. 11G11 cmt and 3% CaCl? 

5-23-71 1765' (4)1/211 hn e~ .. . ... _. w/125 sks "G11 ~mt: and 3% Ca.C1., 

5-24-71 1670 1 f.tH/2 11 ha les C'. ..J C'. ..J w/150 ctlc~ 11G11 t"mt" ~nd 3% c~ct., 

5-_2_8_-71 2516-2523 2551' W~t:e-r Tni Onen -fn-r w~t"e-r iniet"t"i nn 

2488-2509 1 II II 

2376-2427 1 II II 

1929-1995 1 II II 

1 RO.i-J QU t II II 

1769-1797' II II 

7 -2-_71 2267-2332' 2477' Onen -fo-r wa.t:er inie~t:ian 

2336-2364' II II 

7-20-71 2062-22.1R 1 

8-19-71 1643-1754' 

8-27-71 1558-1624' 

1522-1554' 

DATE REMARKS 

WELL HEAD ASSEMBLY 

TYPE: Shaffer unitized wellhead. 

CASING HEAD: Two piece: 13-5/811 30001# lower. 13-5/8"30001# casing tubing head with 30001# (6 bx) C.I.w. clamp hubs. 

CASING HANGER: 13-3/811 x 10-3/411 circulating landing mandrel wi t:h replaceable packing 

TUBING HANGER: 12" 59 ADJ dual tubing hanger. 

TUB lNG HEAD TOP: 13-5/8" x 2-7 /8" EUE 8-rd. tubing 

MA~·.-eR VALVES: Two 2-1/2" 3000# W.P. flanged end Shaffer gate valves full port. 

CHRISTMAS TREE TOP CONN: 3" female line !lipe thread. 

21 
5 

5 

5 

5 

5 

5 

5 

5 

5 

5 

5 

5 

5 

5 

LEASE OCS-P 0241 

UNION OIL CO. OF CALIFORNIA 

MUD RECORD 

SHEET B 

PAGE NO. __ l__ 

Dos Cuadras WELL NO. B-49-1 FIELD __ D_o_s_C_u_ad_r_a_s _____ _ 

TYPE __ L_ig;_n_o_s_u_lf_o_n_a_t_e _______________ DISTRIBUTOR IMC Drilling Mud Inc. 

DATE DEPTH WEIGHT VISC. W.L. PH SALT SAND SOLIDS REMARKS 

5-3-71 417 Spudd€ d wit} sea ' ater. spott d _g_el ~ill. 

5-4-71 417 71 40 8.0 10.0 Salt water from B-2 

5-5-71 750 72.5 so 9.8 10.5 1-1/2 Viscosified Salt Water 

5-7-7 7.34 i6R .3R A~8 9.5 1200 - _S_ llii!lP.d nut ~hnP. 1.3-.3/R" ,..~o 

5-8-7 1000 72 .39 4.8 10.5 850 _3/4 7 nvna-dr;llP.d 

5-9-7 1300 71 39 5.8 10.0 150 2!1:: 7 _Lost. ~nn'rnY RO hhl~-d,.ld ~hA~rl 

-10-7 1300 72 .39 5.4 10.0 150 2% 7 IDnened hn 1 P. 

-10-7 1625 172 5 .39 5.6 9.8 180 12-1/2 7 " " -12-7 1516 17? 40 4 , 9.5 120 1/4 6 n,.ld nn~ c:hn ... ln-~/.4" 

-13-7 1649 72 5 38 4 0 10.5 100 1-112 6 Cut core 1637-1649' 

-14-7 1821 72 39 4 0 10.5 150 1-1/2 6 Cut core 1701-1721' 

-15-7 2100 72 41 4.1 10.0 150 3/4 6 Lost annrox 200 bbls to hole 

-16-7 2432 73 40 4 0 10.0 140 1 7 1Dr1d ahead 

-17-7 2625 73 41 3.9 10.0 130 i l-_ll_4_ j_ l:r_D lno hnlP. ~nd nnened 

-18-71 R__an casin~ 

-20-7 2620 71.5 34 110.0 lCh~ nve-r t.o sa· -n1"An 

-22-7 2551 71 34 9.6 Shoot and saueeze -23-7 2551 71 36 9.6 Shoot and saueeze -26-7 2276 72 41 9.5 1/2 Drld out cmt and tested 

-28-7 72.5 39 9.6 trc Washed nerfs. Shut ri~ down. 

22 
UNION OIL CO. OF CALIFORNIA 

DRILLING RECORD 

SHEET C 

PAGE NO._,_,..;l....__ 

LEASE-------~OC~S~-~P_0~2~4~1~-----------WELL NO. B-49-1 FIELD----~Qo~s~C~uaaMdr~aas~-----------

DATE 

5-2-71 

5-3-71 

From 

417.56 

415.56 

65.71 

46.05 

44.55 

5-4-71 

5-5-71 

5-6-71 

From 

733.97 

731.87 

692.12 

690.52 

49.55 

44 55 

5-7-71 

E.T.D. 

430' 

430' 

To 

415.56 

65.71 

46.05 

44.55 

0.00 

550' 

750' 

750' 

To 

731.87 

692.12 

690.52 

49.55 

44.55 

o.oo 

750' 

DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 

Spudded in at 12:00 noon with Bawden Drlg. Co. rig 18. Drilled 15" 

hole to 430'. 

Opened 15" hole to 20" from 316' to 425' • Ran 16" 7Sf casing to 

417'. Cemented through shoe at 417' with 250 sacks "G" cement and 

3% CaC1 2• Displaced with 475 cu. ft. sea water. Cement in place 

8:00 a. m. Waited on cement. 

16" Casin& Detail 

Lensth Jts. Description 

2.00 16" Baker flexiflow fillup shoe. 

349.85 9 16" 751 K-55 buttress blank casing. 

19.66 1 16" 751 K-55 buttress thread blank pup joint. 

1.50 16" x 20" Vetco swage. 

44.55 Landed below zero. 

417.56 10 Totals 

B&W centralizers located at 405', 379', 338', 299'. 

Ins'talled 16" x 20" Vetco swage. Drilled shoe at 417'. Cleaned out 

to 430'. Ran Sperry Sun gyro survey. Drilled 12-1/4" hole to 550'. 

Drilled 12-1/4" hole to 750'. Opened 12-1/4" hole to 17-1/2" from 

417-750'. Regauged hole 417-750'. 

Ran 17 joints 13-3/8" 54.51 K-55 seal-lock cas1ng to 734'. Float 

collar at 690'. Pumped 100 cu. ft. water ahead followed by 200 sacks 

"G" cement and 251 per sack Gilsonite and 2% CaCl2. Followed by 100 

sacks "G" cement and 2% eac12• Displaced and bumped plug with 612 

cu. ft. water. Cement in place at 4:45 p.m. Installed wellhead, 

3000# riser, 12" 3000# W.P. double hydril, Shaffer gate and 12" 30001 

W.f. G.K. hydril. 

13-3/8" Casing Detail 

Length 

2.10 

39.75 

1.60 

640.97 

5.00 

44.55 

733.97 

Jts. 

1 

16 

Description 

13-3/8" Baker fl6xiflow fill up shoe. 

13-3/8" 54.51 K-55 Amco seal-lock casing. 

13-3/8" Baker flexiflow fill up collar. 

13-3/8" 54.51 K-55 Amco seal-lock casing. 

13-3/8" Shaffer lower landing head (fin joint) 

Landed below zero. 

Totals 

B&W centralizers located at 721', 692', 610', 528', 453', 372'. 

Cement basket at 447'. 

Installed blowout equipment. Tested pipe rams and blind rams to 

3000 psi. Hydril to 1500 psi. 

23 
UNION OIL CO. OF CALIFORNIA 

DRILLING RECORD 

SHEET C 

PAGE N0._--=:2:...__ 

LEASE ____ o_c_s_-_P_0_2_4_1 ______ WELL N 0. B-49-I FIE L D _____ D..;;.o_s_C_u;...;a;.;..;d...;;r...;;a;..;;s ____ _ 

DATE E.T.D. 

5-8-71 1017' 

5-9-71 1388' 

5-10-71 1625' 

5-11-71 1625' 

From To 

1516.16 1514.16 

1514.16 61.87 

61.87 45.77 

45.77 44.55 

44.55 0.00 

5-12-71 1625' 

5-13-71 1645' 

5-14-71 1827' 

5-15-71 2100' 

5-16-71 2497' 

DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 

Drilled and dyna-drilled 12-1/4" hole 750-1017'. 

Drilled 12-1/4" hole 1017-1318'. Lost fluid at 1300'. Mixed lost 

circulation material to stop lost circulation. 

Drilled 12-1/4" hole to 1625'. Ran DIL. Opened 12-1/4" hole to 

15" 734-1226'. 

Opened hole to 1500' to 15". Ran 35 joints and 1 pup joint 10-3/4" 

40.5# K-55 buttress casing. Cemented through shoe at 1516' with 500 

sacks "G" with 25# per sack Gilsonite and 2% NaCl and 3/4% CFR2. 

Followed by 150 sacks "G" with 3% CaC1 2• Lost returns first 900 cu. 

ft. Had partial returns for remainder of displacement. Cement in 

place at 8:00 p.m. 

10-3/4" Casing Detail 

Length Jts. Description 

2.00 10-3/4" Baker flexiflow fill up shoe. 

1452.29 35 10-3/4" 40.5# K-55 buttress blank casing. 

16.10 l0-3/4" 40.5# K-55 buttress blank pup joint. 

1.22 13-3/8" x 10-3/4" Shaffer eire. landing mandrel. 

44.55 Landed below zero. 

1516.16 35 Totals 

Waited on cement. Tested blowout equipment to 3000 psi. Hydril to 

1500 psi. Ran CBL. 

Drilled 9-7/8" hole to 1637 1 • Cut core #1 1635-1648'. Recovered 4' 

shale. Dyna-dri1led to 1645'. 

Dyna-drilled to 1701'. Cut core #2 1701-1721'. Recovered 20'. 

Dyna-drilled to 1827'. 

Drilled 9-7/8" hole to 2100'. 

Cut core #3 2100-2120'. Recovered 19'. Dyna-drilled to 2497'. 

5-17-71 2625'TD Drilled 9-7/8" hole to 2625'. Ran DIL, FDC, CNP, l'ML and CDM logs. 

5-18-71 2625' 

5-19-71 2625' 

Opened 9-7/8" hole to 12•1/4" 1625-2625'. Conditioned hole for casing. 

Ran and cemented 30 joints of 8-5/8" 32# blank casing. Cemented 

through shoe at 2680' and top of Burns hanger at 1330'. Pumped 50 cu. 

ft. fresh water ahead followed by 250 cu. ft. sea water. Mixed and 

pumped 475 sacks "G" cement and 25# per sack Gilsonite and 2% NaCl 

and 3/4% CFR2. Lost returns. Cement in place at 4:00a.m. Waited 

on cement. Tested blowout equipment. Tagged top of liner at 1330'. 

No cement. Cleaned out to 2551'. 

24 
UNION OIL CO. OF CALIFORNIA 

DRILLING RECORD 

SHEET C 

PAGE N0. __ 3 __ 

LEASE ______ O_C_S_-_P __ 0_24_l ________ WELL NO. B-49-I FIELD ________ D_o_s_C_u_a_dr_a_s ______ ___ 

DATE E.T.D. 

From To 

2620.00 2618.00 

2618.00 2574.95 

2574.95 2573.40 

2573.40 1332.60 

1332.60 1330.80 

1330.80 0.00 

5-20-71 2551' 

5-21-71 2551' 

5-22-71 2551' 

5-23-71 2551' 

5-24-71 2551' 

DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 

8-5/8" Casing Detail 

Length Jts. DescriEtion 

2.00 8-5/8" Baker flexiflow shoe. 

43.05 1 8-5/8" 32# K-55 buttress blank casing. 

1.55 8-5/8" Baker flexiflow fill up collar. 

1240.80 29 8-5/8" 32# K-55 buttress blank casing. 

1.80 10-3/4" x 8-5/8" Burns plain liner hanger. 

1330.80 Landed below zero. 

2620.00 30 Totals 

Ran CBL. Unable to test 10-3/4" x 8-5/8" lap. Shot four 1/2" holes 

at 2370'. 

Ran in hole with RTTS. Unable to work past hanger at 1330'. Made 

up open end 4" bull plug on bottom of RTTS. Set RTTS at 2215' • Broke 

down formation with 1700# 12 cu. ft. per minute. Pumped 75 sacks "G" 

with 3% CaC12• Unable to obtain buildup. Cleared holes with 50 cu. 

ft. sea water. Waited 1 hour. Pumped 75 sacks "G" with 3% CaCl2. 

Displaced with 220 cu. ft. 72# NaCl water. Final pressure 2050#. 

Cement in place at 2:45 a.m. Rigged up Schlumberger lubricator and 

tested to 1000 psi. 

Shot four 1/2" holes per foot at 2260 1 • Set RTTS packer at 2ll8'. 

Broke down formation with 15 cu. ft. per minute at 1750 psi. Mixed 

and pumped 75 sacks "G" with 3% CaC12• Displaced with 230 cu. ft. 

72# NaCl. Final pressure 1950 psi. Shot four 1/2" holes per foot 

at 2030'. 

Set packer at 1870'. Could not break down with 1950 psi. Shot four 

1/2" holes per foot at 2040 1 • Set RTTS at 1872'. Broke down formation 

with 34 cu. ft. per minute at 1400 psi. Mixed and pumped 100 sacks "G" 

with 3% CaC1 2• Mixed and pumped 100 sacks "G" with 3% CaCl2. Had 

build up 500 psi to 1750 psi final pressure. Shot four 1/2" holes per 

foot at 1765 1 • Set packer at 1620'. Broke down with 20 cu. ft. per 

minute at 1400 psi. ~fixed and pumped 125 sacks "G" with 3% CaC12• Had 

buildup to 1500 psi. Cement in place at 3:30 a.m. Shot four 1/2" holes 

per foot at 1670'. 

Set packer at 1492 1 • Broke down formation with 30 cu. ft. per minute 

at 1350 psi. Mixed and pumped 150 sacks "G" with 3% CaC1 2• Displaced 

156 cu. ft. No buildup. Staged for 3-1/2 hours. Last stage to 1400 

psi. Rroke loose and circulated. Checked packer and reset. Still 

circulating. Set Baker retainer at 1520'. Stabbed intv retainer. 

Broke down formation with 10 cu. ft. per minute at 1200 psi. Pumped 

200 sacks "G" with 3% CaC1 2• Waited 8 hours. Cleaned out to 1520 1 • 

Tested lap at 1000 psi. Approved by U.S.G.S. Cleaned out from 1520-

1602'. 

25 
UNION OIL CO. OF CALIFORNIA 

DRILLING RECORD 

SHEET C 

PAGE N 0 . _ ___;4~-

LEASE __________ OC~S~--P __ 0~2~4~l ___________ WELL NO. 8-49-I FIELD'-------~Do~s_C~u~a~d~r~a~s~--------

DATE E.T.D. 

5-25-71 2551' 

5-26-71 2551' 

5-27-71 2551' 

5-28-71 2551' 

5-29-71 2551' 

6-2-71 2551' 

6-3-71 2551' 

6-4-71 2551' 

DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 

Cleaned out 1602-1609'. Cleaned out 1609-1612'. Approximately 

4-1/2" cut out of center of economill. Cleaned out 1612-1620' with 

7-5/8" junk mill. 

Cleaned out 1609-1777' with 7-5/8" junk mill. Ran in hole with 

8-5/8" burns wash tool. Tested perforations at 1670' to 720 psi. 

Ran in hole with 7-7/8" bit, 8-5/8" casing scraper. Cleaned out 

1777'-2060'. Ran in hole with Burns washer. Attempted to test 

perforations 2030 and 2040'. Bypass on valve plugged, bottom cup 

torn. Ran in hole with open ended drill pipe. Circulated hole 

clean. No fill. Ran in hole with Burns washer. 

Tested holes at 2030' and 2040' with 880 psi - O.K. (Ran in hole 

with 7-5/8" bit, junk sub, 8-5/8" casing scraper). Cleaned out 

cement from 2060' to 2275'. Set RTTS packer at 2200' and tested 

holes at 2260' to 985 psi - O.K. Picked up 7-5/8" bit assembly 

and cleaned out from 2275' to 2377'. Ran out of cement at 2377'. 

Set packer at 2299'. Tested holes at 2370' to 1030 psi- O.K. 

Pulled out. Ran in hole with 7-5/8" bit. Cleaned out from 2388 to 

2551'. Ran CBL. Shot two 1/2" holes per foot at following intervals: 

2516-2523', 2488-2509', 2376-2427', 1929-1995', 1804-1914', 1769-1797'. 

Unable to break down perforations with washer. Pulled out of hole. 

Found pieces of cement retainer and cement in wash tool. Ran in hole 

with wash tool. Washed perforations 2523-2516', 2509-2488', 2427-2376', 

1995-1929', 1914-1804', 1797-1769'. Used 72# sea water for washing. 

Ran in hole with open end drill pipe to top of liner. Closed in well. 

Released rig, crews to 8-38 at 8:00 p.m. 5-28-71. 

Ran 2-7/8" Hydril 6.5# tubing with tail at 2038', single packer at 

2019', sliding sleeve at 2012', dual packer at 1450', "F" nipple at 415'. 

Landed long string. Ran 45 joints and 5 pups of A-95 6.5# 2-7/8" 

Hydril tubing. Stabbed into dual packer at 1454', "F" nipple at 1453', 

sliding sleeve at 1419', "F" nipple at 443'. Installed and tested 

Xmas tree to 3000 psi. Displaced with inhibited sea water. 

Set dual packer at 1454' and single packer at 2015' and tested same. 

Released rig at 1:00 p.m. 6-3-71 to move to B-46. Primary tubing string 

on lower side of wellhead, north side. Secondary tubing string on 

upper side of wellhead, south side. (Remove secondary tubing· string 

first when pulling) 

26 
UNION OIL CO. OF CALIFORNIA 

DRILLING RECORD 

SHEET C 

PAGE N0. __ 5 __ 

LEASE _____ O_C_S_-_P_0_24_1 _______ WELL NO. B-49-IFIELD _____ D_o_s_C_u_a_dr_a_s ____ ___ 

DATE 

From 

2038.16 

2028.76 

2025.01 

2024.01 

2015.96 

2015.49 

2012.74 

2012.27 

1464.26 

1450.51 

416.23 

415.23 

50.35 

46.65 

45.65 

44.55 

From 

1454.30 

1454.00 

1453.00 

1422.40 

1421.93 

1419.21 

1418.74 

444.80 

443.80 

79.75 

79.28 

75.42 

74.95 

71.23 

65.17 

55.33 

1.64 

46.12 

45.65 

44.55 

7-2-71 

E.T.D. 

To 

2028.76 

2025.01 

2024.01 

2015.96 

2015.49 

2012.74 

2012.27 

1464.26 

1450.51 

410.23 

415.23 

50.35 

46.65 

45.65 

44.55 

0.00 

To 

1454.00 

1453.00 

1422.40 

1421.93 

1419.21 

1418.74 

444.80 

443.80 

79.75 

79.28 

75.42 

74.95 

71.23 

65.17 

55.33 

51.64 

46.12 

45.65 

44.55 

• 00 

2477' 

DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 

2-:-7/8" Tubing Detail - Long String 

Length Jts. 

9.40 

3.75 

1.00 

8.05 

.47 

2.75 

.47 

548.01 18 

13.75 

1034.28 34 

1.00 

304.88 12 

3.70 

1.00 

1.10 

44.55 

2038.16 64 

Description 

2-7/8" Hydril pup joint. 

2-7/8" Hydril pup joint. 

"F" nipple. 

8-5/8" Baker "FII'· single hydrostatic packer. 

2-7/8" 8-rd. x 2-7/8" A-95 hydril Crossover. 

Baker sliding sleeve. 

2-7/8" 8-rd. x 2-7/8" A-95 hydril crossover. 

2-7/8" 6.5# A-95 Hydril tubing. 

8-5/8" Baker "AL-5" hydrostatic dual packer. 

2-7/8" 6.5# A-95 Hydril tubing. 

"F" nipple. 

2-7/8" 6.5# A-95 Hydril tubing. 

2-7/8" Hydril pup joint. 

Fatigue nipple. 

Donut. 

Landed below zero. 

Totals 

2-7/8" Tubing Detail - Short String 

Length Jts. 

.30 

1.00 

30.60 1 

.47 

2.72 

.47 

973.94 32 

1.00 

364.05 12 

.47 

3.86 

.47 

3.72 

6.06 

9.84 

3.69 

5.52 

.47 

1.10 

44.55 

1454.30 45 

Description 

Hodel "S" seal nipple. 

"F" nipple. 

2-7/8" A-95 Hydril 6.5# tubing. 

2-7/8" 8-rd. x 2-7/8" A-95 Hydril crossover. 

Baker sliding sleeve. 

2-7/8" 8-rd. x 2-7/8" Hydril crossover. 

2-7/8" Hydril 6.5# tubing. 

"F" nipple. 

2-7/8" Hydril 6.5# tubing. 

2-7/8" 8-rd. x 2-7/8" A-95 Hydril crossover. 

Baker 24" telescoping swivel sub. 

2-7/8" 8-rd. x 2-7/8" A-95 Hydril crossover. 

(1) A-95 Hydril tubing pup 2-7/8" 

(1) A-95 Hydril tubing pup 2-7/8" 

(1) A-95 Hydril tubing pup 2-7/8" 

(1) A-95 Hydri1 tubing pup 2-7/8" 

(1) A-95 Hydril tubing pup 2-7/8" 

Fatigue nipple 

Donut 

Landed below zero . 

Totals 

Ran Schlumberger through tubing 2" scallop guns and tagged fill at 

2477'. Perforated 2267-2332' and 2336-2364' with 2 JSPF using 1/2" 

Hyperjets. 

27 
UNION OIL CO. OF CALIFORNIA 

DRILLING RECORD 

ACIDIZE 

SHEET C 

PAGE N0. _ _.-1 __ 

LEASE ___ oc_s_-_P_0_2_4_l __________ WELL NO. B-49-I FIELD, ___ D_o_s_C_u_a_d_r~a_s ________ _ 

DATE 

7-13-71 

fill 

8-6-71 

fill 

7-20-71 

8-19-71 

8-27-71 

5-12-72 

5-20-72 

E.T.D. 

2551 1 

t 2477 1 

2551 1 

t 2477 1 

2551 1 

2551 1 

2551 1 

DETAILS OF OPERATIONS, DESCRIPTIONS & RESULTS 

Acidi~ed th1 1gh long string with 2000 gallons of 7-1/2% HCl and 

1000 gallons 9% HC! - 6% HF in two stages. Used 75# of Matriseal II 

diverting agent. 

Acidized through long string with 3000 gallons of 9% HCl - 6% HF. 

Used 200# Matriseal II diverting agent. 

Ran Schlwnberger through tubing 2" Scallop guns and perforated 

2062-2248' with 2 JSPF using 1/2" Hyperjets. 

Ran Schlwnberger "Oriented Type" through tubing 2" Scallop guns and 

perforated 1643-1754' with 2 JSPF using 1/2" Hyperjets. 

Ran Schlwnberger "Oriented Type" through tubing 2" Scallop guns and 

perforated 1522-1554' and 1558-1624' with 2 JSPF using 1/2" Hyperjets. 

Short Str ng_ 

1454' 

Long Stril~g 

2038' 

Short String Acid Job: Pwnped 500 gallons of 15% HCl at 275 psi. 

Followed with 500 gallons 15% HCl with 125# Matriseal II. Pwnped 750 

gallons 15% HCl at 275 psi at 6 cu. ft. per minute. Pwnped 250 

gallons 15% HCl with 75# Matriseal II at 10 cu. ft. per minute. 

Pumped 1000 gallons 15% HCl at 275 psi at 10 cu. ft. per minute. 

Displaced with 208 cu. ft. of sea water at 9 cu. ft. per minute. Put 

well back on injection. 

Long String Acid Job: Pumped 10 cu. ft. sea water at 500 psi at 3 

cu. ft. per minute. Pumped 1000 gallons 15% HCl at 3 cu. ft. per 

minute at 525 psi. Pumped 750 gallons 15% HCl with 100 lbs. Matriseal II. Pumped 250 gallons HCl with SO# Matriseal II at 5 cu. ft. 

per minute and 540 psi. Rate decreased to 3 cu. ft. per minute. 

Pumped 1000 gallons 15% HCl at 3 cu. ft. per minute and 550 psi. 

Displaced acid with sea water at 2.5 cu. ft. per minute and 570 psi. 

After 180 cu. ft. could not pump water away within pressure limits. 

Put well back on injection. 

*u.s. GOVERNMENT PRINTING OFFICE: 1974-543-582/83 

28