Ten Pattern Steamflood - Ken River Field.pdf

8/17/2019 Ten Pattern Steamflood - Ken River Field.pdf

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~ h~ ~ ~ ~ pa t t ern

Steamflood, Kern

.

.

River Field, alifornia

T. R. Blevins, SPE-AtME,ChevronOil FieldResearchCo.

R. H. Billingsley, SPE-ANE, StandardOil Co. of California

Introduction

The 10-pattem steamflood field trial was initiated in the

Kern River field, Calif., in Sept. 1968. This field was

selected for a commercial test after the technical success

of the steamflood process was confirmed by the In-

glewood field test. 1 The Kern River field properties

of high oil viscosity, low reservoir pressure, shallow

depth, and high oil saturation are all favorable for ther-

mal recovery techniques. Chevron Oil Field Research

Co. and Standard Oil Co. of California, Western Opera-

tions Inc., designed and operated the test to measure

vertical and areal coverages, displacement efficiencies,

and residual oil saturations with data from several

temperature observation wells and core holes.

This paper contains a description of the reservoir, the

project facilities, and the performance to Oct. 1, 1973.

The project is analyzed in detail and the performance is

compared with theory. Results of a new steamflood

prediction methodz are also included.

Project Description

Field Area and Background

The 10-pattern steamflood is being conducted in Sec-

.r AL. v-—

D:.,,s.

+Zal,-l

tlon 3 u] mc IVGII N VGI Ile,u, ,,&a “amw..,..-.~,

a r Ralc-rcfield ~~ ~f,

The field was discovered in 1899 and was largely de-

veloped by 1915. The reservoir is 300 to 500 ft thick

and is first encountered in Section 3 from 200 to 300 ft

below the surface. The Kern River Sand Series produc-

ti ve limits are defined by the downdip China Grade

Loop fault and by updip outcropping.

The dip in Section 3 averages 3°, and strike is on a

northwest-southeast trend. The Kern River Sand Series

consists of at least six sand bodies separated vertically

by 6- to 20-ft-thick siltstone or clay intervals. A typical

IES log of the Kern River Sand Series is showm irt Flg.

1. The subject field tial is being conducted in the bot-

tom sand interval, from 705 to 765 ft on the log. Upper

sands will be processed successively from bottom to

top. The productive intervals are friable and unconsoli-

date~ the rock ranges from fine to coarse grain, poorly

sorted sandstone, to conglomerate with pebbles from %

to +5 in. in diameter.

The reservoir data, based on wells cored at the start

of the project in 1968, are shown in Table 1. The aver-

age properties for the steamflood interval are 7,600 md

permeability, 35 percent porosity, and an oil saturation

before steamflooding of 52 percent, equivalent to an oil

content of 1,437 bbl/acre-ft. The steamflood project

area is shown in Fig. 2.

The project consists of 10 inverted seven-spot injec-

tion patterns covering 61 surface acres. The two central

patterns are confined or backed up by the outside ring

of injection wells and are the two key patterns for proj-

ect analysis. The 6-acre patterns provided the opportu-

nity to evaluate the effects of patterns larger than the

2.5-acre Inglewood test.’

Well Completions

Most of the existing wells at the start of the project

were completed before 1915 with star “perforated lin-

?

The steamflood project at Kern River j7eld consists

10 inverted seven spot injection

patterns with 32 producing wells covering 61 acres. Steam injection is confined to a 70 ft

sand. Extensive data analyses confirm that steamflooding is a most eflicient displacement

mechanism with a volumetric sweep of more than 60 percent.

DECEMBER, 1975 1505


2/10

., ...

——

———

Fig.

1

— Typical Kern River IES log (Well 2-2, Section 3).

ers”

that did not provide adequate sand control. Ten

new wells (Wells 5-8, 6-9, 7-5, 7-7, 9-8, 10-9, 11-9,

14-7, 16-5, and 16-6) were drilled in Feb. and March

1968 to replace 10 old wells and were completed with

40-mesh, 6%-in. slotted liners. In the remainder of

the old producers the star liners were pulled using. a

newly developed, steam-assisted, foam-solvent recov-

~py,technique ad

were renlaced by

40-mesh, 6%-in.

._. . . . . ~

slotted liners. One old well, Well 177, has a 40-mesh

inner liner set through the original 8%-in. star perfo-

rated liner.

Therefore, at the start of the project in Sept. 1968,

there were 42 producing wells — 10 old wells, 10 new

--

. 11 . - -. .. -- -l .- .. a, l

wells matching them, and 22 oid weus rccump=cu

with new liners. The 10 old wells matched by new

wells sanded soon after the project started and subse-

quently were abandoned.

The 10 injection wells (Wells 5-6, 7-4, 7-8, 9-6,

IO-4, 10-8, 12-6, 13-4, 13-8, and 14-6) were all com-

pleted with 51h-in. casing set through, cemented, and

jet perforated. All the injection wells except Well 14-6

were newly drilled near plugged and abandoned pro-

ducing wells, with a minimum of 35 ft between a

plugged and abandoned well and an injector.

These wells are perforated in the bottom 35 ft of the

70-ft interval being flooded. The perforation density is

based on injectivity tests made in Well 7-8 and consists

of two %-in. jet holes per foot in the upper 17 ft of

perforated interval and one %-in. bullet hole per foot in

the bottom 18ft of interval.

The 14 temperature observation wells, all designated

191

+= 4.2 81

122

175

2-2 992

65

I

7s(

*.. =

~,s.

67

*

g ,7

1%

40+

A.

lmd

&-__

-+F_

11.11

200

201

ZJ2

LEGENO

~~g~.Q*~~~y&? Qu KLL

INJECTION WELL

PROOUCING WILL

ABANOONEO WELL

SHUT-IN WELL

1971 EXPANSION AREA

Fig. 2 —

Ten-pattern steamflood, Section 3, Kern River.

1506

JOURNALOFPETROLEUMTECHNOLOGY


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TABLE 1

- SUMMARY OF RESERVOIR DATA (AS OF 1*),

KERN RIVER FtELD STEAMFLOOD INTERVAL

Depth, ft

700 to 770

Oil gravity, “API

14

Estimated original reservoir pressure, psig

225

Current resavoir pressure, psig

80

Average net sand thickness, ft

70

Reservoir temperature” F

80

Oil viscosity at 85”F, CP

2,710

Oil viscosity at 35(IW, cp

4

Average permeability to air, md 7,800

Average porosity, percent

Average oil content, bbl/acra-ft

1,4E

Average oil saturation, percent

52

with T prefixes, were located to give maximum infor-

mation on areal sweep, rate of advance of the heat

front, and vertical coverage of the steam drive. The ob-

servation wells were completed with 31h-in. tubing

cemented to the surface.

Project Facilities

A bank of six steam generators, each rated at 18 million

Btu/hr and 1,200 psi, was instaiied to initiate the pi~j-

ect. A seventh generator was placed in June 1969 and

an eighth generator was added in April 1970 to bring

total steam-generating capacity to 10,400 BWPD.

Most wells in the project area formerly were pro-

duced by central-power rod lines and jack pumps.

These wells aIl have been equipped with modem pump-

ing units ranging from WI *’25””o AFI ‘‘ i60” in SkR,

with elecrnc motor drive and lifting capacity from 200

to 1,000 B/D.

Production is routed through the gauge settings at the

injection manifold sites to the central treating plant in

Section 3. The plant uses horizontal water knock-outs

and heater treaters for separation and cleaning before

shipment through an LACT unit to the pipeline. All

production from Section 3 is metered by the LACT unit

this provides a check against daily production by

gauges. Gauging frequency ranges from once a week on

the 10 inside key-pattern wells to once a month for the

first line of wells outside the project area.

Project Performance

injection

Hkitliy

The total project injection and production history is

shown in Fig. 3.

Injection rates have varied from 6,000 to 10,000

BWPD, and are currently near 6,000 BWPD. Wellhead

pressures were as high as 620 psig initially, but de-

creased to 200 psig w~thin 3 months as the area around

the welIbore became hot and there was less resistance to

flow because of reduced reservoir fluid viscosity. The

surface pressures and temperatures are directly related

to rates but, in general, there has been a significant in-

crease in the injectivityy index with time.

Pressure and temperature surveys made in injection

wells indicate that most pressure losses occur in the in-

jection tubing and not in the formation.

The project as a whole appears to be rate-sensitive;

that is, the higher the injection rate, the higher the

oil production. However, there is also an econornic-

optimum injection rate that results in the most oil pro-

duction per dollar invested for steam injection. The

search for this economic optimum was the basis for

most changes in injection rate. Neuman2 includes sev-

eral equations that can be used to estimate the economic

feasibility of steamflooding, including an optimum in-

jection rate.

Production History — Total project

All producing wells were steam stimulated immediately

before steam injection started. The first significant rate

increase for the project attributed to steam drive oc-

curred in Jan. 1969, or 4 months after the project was

initiated.

The oil rate climbed steadily to 1,600 BOPD in June

1970. At t.iis time, the injection rate was reduced and

the oil rate declined. The oil rate reached 1,680 BOPD

;fi j~fi. i97 i be~a~~e of a c~ncentrated well stimulation

effort, but again declined in mid-1971. The Dec. 1971

rate of 1,490 BOPD represents a probable peaking of

the project for the current injection rate of 6,200

BWPD, production has since declined slowly to around

1,300 BOPD.

As mentioned before, steamflooding is believed to be

-..4- ,a”c;t;,,a

nrluction response to changes in

$ tiie pr.-._atG-s&lla,.,w, “

injection rate is often masked by wellbore plugging or

failure to keep a well “pumped-off.” One of the keys

to successful steam drive operations is the ability to

keep wellbores clean and the wells producing at com-

plete drawdown in the wellbore.

The steam-oil ratio (SOR) is the most important

~ccficw,ic p~--m.eter &Qidefrom the initial investment.

The monthly SOR was 5.1 in Sept. 1973, and the

cumulative ratio had decIined to 5.8. Any significant -

amount of oil produced after steam injection stops will

further reduce the cumulative SOR.

In addition to the 32 wells included in the production

history in Fig. 3, there are 10 wells immediately north

and west of the project that have responded to the

steamflood. These weIls, Wells 34, 36, 38, 39, 8-1,

8-2, 12-1, 12-2, 13-1, and 67, are all hot, but are not as

. - -..*-,.”- k-f ..,-11

.uithip the

nrnie~[ area.

proiiik as dic aIVGICI~G ,Iut --1 . . . . ...1..... ~-_J-

In addition, several other “outside” wells (Wells 192,

183, and 195) appeared to be heating when this paper

was written.

Cumulative production from the 32 wells in the proj-

ect area since Sept. 1%8 is 2,285,100 bbl of oil and

9,705,500 bbl of water. This represents a gain of

2,166,100 bbl over extrapolated primary recovery and a

total recovery of 45.8 percent of the stock-tank oil orig-

inally in place. An ultimate recovery of 55 percent of

the oil originally in place is now anticipated.

12

90

CW. S7EAM OIL RbTlO—

D

6

4

IIWLUD2S CVCUC C7EAMI

2

10.000

6TE6M lwEc71m .

~~

‘(*DRIvE + CVCLICI ------- ,:.>. -.,>~,> .. ... .... . . . . . ... .. ... ,

5.000

,..

F-._-__-&

m.+

- .. .

10 ;

. ..-. ..-..6 z

10

lS9S)661@7168 f6S )70 ‘711721 ?3174’75

Fig. 3 —

Ten-pattern steamflood total performance.

DECEMBER.1975

1507


4/10

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t

HI

.

ml

1, “ In. ----

,,

mm

mm”

,,,

,, *

,

.1

*

; ,,

i

,,

- .

“

- “

t,

- .

.

- .

u

,,

.

1

.

1

.

I

ml

[

m

I

IV*

F@. 4 — Cumulative injected and produced liquid balance.

Production Data — Individual Patterns

Although supporting data are not included, production

allocations for individual patterns “have been made.

These allocations are based on our knowledge of tracer

breakthrough, heat breakthrough, and pattern geometry.

The allocation is somewhat arbitrary because only four

tracers have been used, but it is the best estimate from

the available data. The production allocations in the two

key patterns, Wells 9-6 and 12-6,’ were used for dis-

placement and capture analysis, and are discussed later.

Liquid Balance

The

total volume of steam injected (as barrels of water)

is compared with the total liquids produced in Fig. 4.

The figure indicates that an injection-withdrawal bal-

ance was reached in Aug. 1971. The maximum differ-

ence between cumulative liquids injected and produced

occurred in July 1970, when there were 824,000 bbl of

injected liquids unaccounted for, either by fillup or be

cause they were lost outside the project area. This wa

before the expansion to the south, which has apparently

contributed to production since Aug. 1971.

Of the maximum of 824,000 bbl “over-injected” t

Aug. 1971, it is estimated that about 600,000 bbl wer

required for fillup inside the project area. This is 5.3

percent of the pore volume of the flooded zone.

Heat Balance

A heat balance in a large injection project like the 10

pattem is more difficult to calculate than the liquid

balance. Estimates of surface heat losses, down-hole

losses in the injection and production wells, losses i

the formation based on observation well data, and hea

content of the produced fluids must be made. A com

plete heat balance had not been made at the time o

this report. However, in this paper the produced hea

is subtracted from the injected heat (as though i

never entered the reservoir) for calculation purposes

Fig. 5 shows that the cumulative heat produced a

the surface has reached 15 percent of the total surfac

injected heat. It is slowly increasing and may ultimatel

reach 18 percent. None of the published heat-loss

theory accounts for the heat produced at the surfac

with produced fluids.

Tracer Data

Four tracers were injected at the beginning of the project

Well

Tracer Concentration

12-6 Tritium 0.5 millicuries/gal

10-4 NaN03 500 ppm N03

10-8 NaBr 150 ppm Br

9-6 NaCl 1,000 ppm Cl

The tritium tracer was used subsequently in three othe

injection patterns. The detection of these tracers an

40

40

i

3E

[email protected] —

Cumulative and monthly heat produced in surface fluids.


5/10

measurement of the total solids content of produced

water from all wells formed the basis for analyzing fluid

movement and interpreting areal coverage in the indi-

vidual patterns. The tracer data also were used in al-

locating production to individual patterns.

Project Analysis

Te.mperdureData

Surface flowline temperatures have been monitored

throughout the project and have proved useful in several

ways. The data are necessary for produced-heat calcula-

tions and can reveal whether a well is responding,

whether the liner is plugging, and whether larger pump-

ing equipment should be considered.

More than 600 temperature profiles taken in the 14

observation wells have been used in analyzing the verti-

cal and areal coverage, the rate of heat-front movement,

and heat losses within the reservoir. A typical tempera-

ture profile depicting the steam zone, hot water zone,

and equivalent injection interval is shown in Fig. 6.

Core Analysis Results

The oil displacement efficiency of steam was measured

by comparing the saturations in cores taken in Injection

Wells 9-6 and 12-6 with cores taken behind the steam

front in Wells C6-9 and C5-7.

Fig, 7 compares the oil saturations in the presteam

cores with the post-steam cores by depth for Pattern

,*<

-1-. . . ..— .-..

h-t .S,otmm7n?le

1,&o. 1n~ SLW1l 8XJ11e,wc Wa.W &w. w,

. . . .

n~ tmimmvn

data zone are marked to emphasize the different residual

oil saturations found in these intervals. This figure also

shows the gravity override of the steam zone. Even

though steam is restricted at the injection point to the

bottom 35 ft of the 70-ft zone, the cored steam zone is

at the top, at a lateral distance of only 150 ft from the

injection well.

Since the vertical coverage improves with time, these

core data represent only the conditions in Dec. 1970 for

Pattern 12-6. By correlating the core results with neu-

tron logs run in all observation wells at the time the

post-steam cores were cut. and then correlating the

neutron logs with temperature profiles run in aii ob-

TABLE 2 —

OIL DISPLACED PRE- AND POST-STEAM

CORES, PAHERN 12-6, DEC. 1970

stem Zone

Thickness, ft

Average

oil saturation, percent

Average oil content, bbl/acre-ft

Oil displaced, bbl/acre-ft

Stock-tank oil in place, percent

Hot Water Zone

Thickness, ft


Average oil content, bbl /acre-ft



Total Cored Zone

Thickness, ft


Average oil content, bbl/acre-ft



DECEMBER,1975

Well

~

18

8

188

39

24

590

1,191

87

Well

12-6

18

53

1,377

39

47

1,235

845

52

~?

49

1,278

814

64

servation wells periodically over the life of the project,

the volume of the heated zones can be estimated at

other times.

The oil displaced at the time the post-steam cores

were obtained in Pattern 12-6 is summarized in Table

2. The oil saturations in the presteam injection wells

have been adjusted for overburden pressure and core

flushing.

It can be seen that steam is a very efficient displace-

ment process, with 87 percent of the oil in place being

displaced. However, the steam zone was relatively thin

at this location and time, with a thickness of 18 ft in the

Fig. 6 —

Typical temperature profi le (Well T6-4).


6/10

cored interval. The 39-ft condensed hot water zone had

displaced

52 percent of the oil in place but was twice as

thick as the steam zone.

Laboratory floods performed on Kern River cores be-

fore the field project indicated ‘residual oil saturations of

8 and 20 percent for the steam and hot water zones, re-

spectively. The two field cores averaged 6.3 and 23.2

percent residual oil for the respective zones, which

compares favorably with the laboratory floods. This

good agreement between laboratory and field results

was also noted in the Inglewood pilot steam drive. 1

Displacement Analyses

To analyze the fluid displacement of the steamflood

process, it is necessary to define the two heated zones

involved — the steam zone and the hot water or con-

densed steam zone. The steam zone is relatively easy to

identify because it has a uniform peak temperature in-

terval that appears as a vertical line in the profiles of

temperature vs depth.

The hot water zone is not as easy to identify because

the minimum temperatures above which oil is being

displaced may vary from iocation to i~eati~fi. A ~eiieia-

tion technique using the core results, the pre- and post-

steam neutron logs, and temperature profiles was de-

1

,Mt4

,“

,7, ,7 s71 ,71

OUJSO .sO.sO. >s0

LOG TM

Fig. 8 —

Vertical heat-zone growth vs log time.

veloped to define the “cutoff” temperature for’the hot

water zone. This technique leads to the use of the tem-

perature profiles alone to analyze the growth of both the

steam and hot water zones.

Plots of three temperature regimes of + 150”F,

+ 230”F, and the steam zone from the temperature pro-

files vs time were constructed on semilog paper to show

.,.

the verucal cnanges m heated zmies iii eae,, ““.-., -..-..

= --h rihcarva timn

well. One of these plots is shown in Fig. 8.

This plot clearly demonstrates the gravity override of

the steam zone and its location immediately below the

siltstone overlying the steamflooded zone.

Well T6-4 in Fig.

8

is also an example of the vertical

heterogeneities in the reservoir (probably siltstone

lenses) that can retard the gravity override of the steam

zone. As can be seen, there was no gravity override

initially, but after 4 months the steam zone appeared at

the top of the formation and dissipated at the bottom.

There is no evidence of a siltstone lens on logs run in

either Injection Well 12-6 or Well T6-4, but there is

apparently some barrier to vertical heat flow between

the wells,

The growth of Ihe heated zones

was

highly nonradial,

and heat arrival time for individual observation wells

located the same distance from the injection well varied

from 2 weeks to 2 years. An areal plot of the steam-

zone “front” progression with time is shown in Fig. 9

for Pattern 12-6.

The areal control beyond the point of heat break-

through in individual producing wells or observation

wells was estimated by constructing an isopach map of

a 15(YFtemperature zone to serve as an areal bound for

the steam and hot water zone maps prepared individu-

ally. Thus, the maximum areal coverage is controlled

by

our best estimate

of a 15(YF contour line that en-

compasses both the steam and hot water zones.

It was further felt that the estimated areal coverage of

a steam drive should not significantly exceed that of a

waterflood with a mobility ratio of unity in a seven-spot

configuration. This value is 74.5 percent at water break-

through. The maximum areal coverage estimated for the

hot water zone in either key pattern is 77 percent, which

. ..

---:-.--I ~r~ie of th~rnmb’

is siignuy better than the clllplll~ai

. . .

mentioned above.

Isopach maps for all observation-well steam and

hot water zones as a function of time were drawn and

planimetered. The acre-feet of heated zone, steam zone,

10-b

and hot water zones for Pattern 12-6 are shown in

Fig. 10.

117

153

F@. 9 — Steam “front” progression,

1510

Pattern 12-6.

zoo,

J

TOTALNETTEAWONE

+HOTWATERZONE

0

0

Fig.

10 — Heated zones — volume and percent vs time.

JOURNALOF PETROLEUMTECHNOLOGY


7/10

Oil Recovery Factors —

Vertical and Areal Coverage

Table 3 summarizes the vertical, areal, and volumetric

coverage of the steam and hot water zones, and dis-

placement calculations for the two key patterns and

for the total project. It should be noted that the 10-

pattem project totals are simply arithmetic averages of

the two key pattern coverages; and because of heat

leakage to an upper zone in Pattern 9-6, the totals may

be conservative.

The average vertical coverage of the total heated-oil

displacing zone is 88 percent, the average areal cover-

age is 68 percent, and the volumetric efficiency is 60

percent. This means that more than one-half the reser-

voir pore volume has been contacted by sufficient heat

to reduce the residual oil saturation to less than 23 per-

cent. This is an excellent combination of volumetric

coverage and displacement efficiency.

The displacement data given in Table 3 are based on

core results shown in Table 2 and heated zone volumes

shown for Pattern 12-6 in Fig. 10, but include data from

Pattern 9-6. If all the displaced oil were produced, the

recoveries of the stock-tank oil originally in place

would be between 45 and 54 percent, respectively, in

the two key patterns, with the 10-pattern project total

estimated at 50 percent. Therefore, in repeated pattern

steamflood with high capture factors, recoveries up to

S5 percent of the stock-tank oil originally in place ap-

pear reasonable and attainable.

The summary of the oil recovery factors of the key

patterns and the project as of Oct. 1, 1973, given in

Table 4, shows that recovery is now more than 45 per-

cent of the stock-tank oil originality in piace for the t~tai

project. The type of production acceleration possible

with steamflooding can be appreciated even more when

it is noted that only 13 percent of the stock-tank oil

originally in place was produced over the first 69 years

of this reservoir’s producing life.

It should be noted that the producing wells are open

to all the zones indicated on the log in Fig. 1. This

means that decline curves could not be used to estimate

primary recovery from the injection interval; instead,

this number was estimated at 15 percent, which is

reasonable for this type of field and is consistent with

past history. In addition, any contribution to 10-pattem

project production from the new injectors to the south

has not been accounted for because the expansion came

late in the life of the test. The combined effect of these

approximations is probably within the error of produc-

tion allocation to individual wells.

Capture Factor

The capture factor is defined as the ratio of the total

production minus primary oil produced to 1968, to the

total oil displaced since 1968 by steam drive. To accu-

rately analyze the capture factor, the production from

hot wells outside the original project area must be con-

sidered. These outside responding wells have a cumula-

tive gain of 218,200 bbl of oil, which is included in the

total oil production attibuted to the steam drive project

for the capture-factor calculation in Table 4.

The calculated capture factors for Patterns 9-6 and

i2-6 aie 74 and 3 percent, respectively. These cap-

ture factors are subject to errors in production alloca-

tion, as well as in the assumptions made in using dis-

placement voiumes based on iimkd core data.

If one-half the patterns had heated volumes similar to

Pattern 9-6 and the other one-half was similar to Pat-

tern 12-6, the oil displaced since 1968 would be

~ CAs qy

hbl ad the rmture factor

for incremental oil

L,JVJ, J u “ au..” ...- --~-–

to Ott. 1, 1973, would be 98.3 percent. The capture

factors for each key pattern were calculated at 6-month

intervals, and their average was applied to the total

TABLE 3 — STEAMFLOOD COVERAGE AND DWPLACEMENT AT 1.18 PVI

Pattern 9-6

(Oct. 1, 1973)

Percent

Units of Total

Steam zone

Areal sweep

3.1 acres 52

Vertical sweep

21.4 ft 36

Volumetric sweep

66.6 acre-ft 19

Displacement, STB/acre-ft

1,523

res bbl

101,400

Hot water zone

Areal sweep

4.6 acres 77

Vertical sweep

21.4 ft 36

Volumetric sweep

98.0 acre-ft 26

Di&x ent, STB/acre-ft

.-.. ---

83%

Heat leak zone (Pattern 9-6 only)

Displacement, STB/acre-ft

734

res bbl

14,700

Total heated zones

Areal sweep

3.8 acres 64

Vertical sweep

42.8 ft

72

Volumetric sweep

164.6 acre-ft 47

Total displacement since Sept. 1968, bbl

199,300

Primary production to Sept. 1968, bbl

82,200

Total primary + diaplac.ement, bbl

281,500

Total primary + displacement,

percent stock-tank oil originally in place 45.5

DECEMBER.1975

Pattern 12-6

(Oct. 1, 1973)

Percent

Units of Total

3.7 acres 60

32.5 ff 51

121.2 acre-ft 31

1,191

I 4A mn

,----

4.7 acres 77

35.1 ft

55

165.6 acre-ft 42

645

106,800

—

4.2 acres” 68

67.6 ft

100+

286.8

acre n

73

251,100

81,300

332,400

54.4

Estimated 10-Pattern Totals

(Oct. 1, 1973)

Average Percent

Units of Total

34.0 acres 56

30.0 n

43

1,059.3 acre-ft

25

1,357

1,437,500

46.6 acres

77

31.4 ff

45

1,483.0 acre-ft

35

747 ‘-

1,107,800

—

41.4 acres

67

61.4’ft

86

2,542.3 acre-ft

60

2,545,300

934,000

3,479,300

49.5

1511


8/10

TABLE 4

— STEAMFLOOD RECOVERY FACTORS TO OCT. 1, 1973

Pattern 9-6

Pattern 12-6

~.~~

64.3

392

10-Pattern Total

ha, awes

Thickness, average, ff

Acre-feet

Stock-tank oil original ly in place

(at discovery), bbl

Primary recovery to Sept. 1968, bbl

Primary recovery to Sept. 1966,

percent stock-tafik oil originally in place

Stock-tank oil in place at Sept. 1968, bbl

Remaining primary (ultimate recovery—

1~

txircent}. bbl

------- ,. ---

Total product ion, bbl

Production gain over primary, bbl

Production gain over prima~,

percent stock-tank oil originally in place

Total recovery,

percent stock-tank oil originally in place

Capture factors (Oct . 1, 1973)

Total production-primary to 1968

iTabie 41. biii

60,74

69.8

4,237

618,200

82,200

611,300

81,300

7,023,000

934,000

13.3

536,000

13.3

530,000

13.3

6,089,000

10,600

230,400

137,600

10,400

365,300

273,600

119,000

3,219,100

2,166,100

22.2 44.8 30.5

37.2 59.8

45.8

(230,400 to Wx)tl)

199,300

= 74.3 percent

I-cc

m-m .-

nl m-m\

\iw3,G4uv

Lw

u ,

,..?” .?,

251,100

= 113.1 percent

IQ Aa7

mn tfi afiA nnm

{-. ---, .“”- .“ -“-. ””-,

2,545,300

= 98.3 percent

Total displacement since 1968

(Table 3), bbl

inc udes

218,200-bbl gain

from first-line

responding wells)

steam drive project.

These data are plotted in Fig. 1I,

and were used as the correction factor in Fig. 13. The

total project capture factor improved with time as fillup

was reached, and the ability to keep responding wells

operating at maximum capacity was improved. Unfor-

tunately, the capture factor usually must be estimated in

most displacement processes, in lieu of the actual data

available from this field trial.

and incorporate these data into a general prediction

method for steamflood performance. These objectives

are related in the sense that heat-loss models or heat-

10SScalculation procedures are basic to any prediction

method for steamflood performance.

Before this field trial, it was recognized that exist-

ing heat-loss models, such as the Marx-Langenheimq

model, were not completely satisfactory for steamflood

predictions. The Marx-Langenheim model of areas

heated checked the early field results of the Inglewood

pilot test fairly well; but thickness-heated and displace-

ment predictions were not satisfactory. None of the

existing heat-loss models consider gravity override.

which is a fact of life in gas-phase injection systems. In

Project Performance vs Theory

One of the objectives of this field trial was to test the

validity of present theoretical methods for heat-loss cal-

culations after relatively long injection periods. Another

objective was to gather data from a controlled field test

105

f

10 PAITERN ~EAM FLOOD

KERN RIVER

~ ‘

S-

/

TOTAL10PAmERN PROJECT

100

90

1512

JOURNALOF PETROLEUMTECHNOLOGY


9/10

a recent experimental study of gravity-overnde effects,

Bake concluded that gravity override primarily de-

pends on the injection rate and is less severe at higher

rates, and that heat losses to overburden and substratum

are functions of time alone. Recent theoretical work by

Neuman2 has resulted in a mathematical model of the

steamflood process that incorporates gravity override

and downward st$am-zone growth in the performance

prediction.

The Neuman Model

Figs. 12 and 13 show the Neuman2 predictions vs Pat-

tern 12-6 and total project performance. This theoretical

model agrees reasonably well with field measurements

of total steam and hot water volumes, as shown in Fig.

12, and with total cumulative production after capture-

factor correction, as shown in Fig. 13. Complete details

of the Neuman model are included in his paper.z

The most important difference in parameters used by

Neuman and those used in the displacement analyses of

this field trial is the “critical or cutoff temperature” in

the hot water zone. Neuman’s critical temperature is

that below which water fiow is preferential to oil, baaed

-- I--- ....+ .-n -~ *-.*. am~

the field ~~~~ff temperature

UII IIU1 Wcd llo”” , OK.,

. ... . . .. . .. . .

is

that below which no further oil is displaced from the

reservoir, based on cores and logs. The field correla-

tions gave a temperature cutoff as low as 14&’F.

The Marx-Langenheim Model

A Marx-Langenheim4 prediction was also made to

compare with Pattern 12-6, and is shown in Fig. 14.

The parameters comparable with Neuman’s model, such

as British thermal units injected (Q), volumetric heat

capacity @4), and difference in temperature (AT), are

identical in both predictions. The Marx-Langenheim

prediction models can

be used for area or volume-

heated or oil-displacement volumes as functions of

time, but normally are used only for area calculations

because the displacement rates are quite optimistic.

h must be assumed thatthe steam zone has a constant

thickness

in the Marx-Langenheim model, but the

Neuman model does not require this assumption. The

Marx-Langenheim thickness of 32.5 ft used in the Fig.

14 comparison is the average steam zone, or uniform

. -~-..t.s-s

thicbmecc frnm Pattern. 12-6 data as Of OCt.

le llpac” . ~ C. . r. ’-” ” , . . . . . . - ---

1, 1973 The thermal diffusivity and conductivity val-

, ,

.

.

I

/,

..

.1

/

o

./

. ..Q

,., .

/0”

‘0

.0?6

o

_

‘ ..mcm. *.- . “..=

009

/---3 s -’-

.

.’

-H, ’-

..O:

. .

,’

.’

0“

,’.mmn.’” lcalw.l...l ,,.

% .

,,

0

/’

,---

0 ,/

,“.”

. .OO”

.00.0

.“./

..” /

,.’

.

..O 0 0

/

. . ,/

6;0;00000 =- .*M = v=-

.@

/

Fig. 12 — Neuman’ predieted heat zone vs actual,

Pattern 12-6.

ues are also

based on field temperature profiles.

The original intent of the Marx-Langenheim field-

data comparison was to test the data’s validity for long

injection periods. The data are not satisfactory, as can

be seen from the comparison of the predicted with ac-

tual steam-zone volumes. However, it was noted that

the Marx-Langenheim uniform temperature-zone predic-

tion overlies the total steam and hot-water zone field

curve. This is probably accidental because the thickness

of the steam zone and the ratio of the steam zone thick-

ness to hot water zones change with time. There is no

way to test this observation against other steamflood

because of lack of data on hot water zones.

Reservoir Heat-Loss Parameters

The thermal conductivity and diffusivity values used for

the

Neuman,z

Baker,3 Marx- Langenheim4 and other

heat-loss prediction methods are usually taken from the

literature.

For the 10-pattem project steamflood, it was possi-

ble to derive the values for diffusivity from the shape of

the temperature profiles as described in Neuman’s

p~pei.

~ ~lffidS~v:ty ~aiue of

0=87 sq f~D

gave

a good

“match” to measured temperature profiles in most

cases.

The average value of the expression for the ratio of

.

-

i

.

/’

?“

-

..’

,.’”

/

/’

.

-

,/.

. .mr y.y .Mm

/ ,

*-

-

/

.-. .

—,”. .

. .

-.

/

i

‘*

-

/A+.&

s

~

W

/

:

/’

g ‘-

-

mu . -mm .-m

,.’

“ . . . * “—

/

.

/’

,. ~

.

/’

F@. 13 —

Neuman’ predicted oil production vs actual

oil

production, 10-pattern steamflood.

-d

I

J

1~

//

i:lilii ll iil liliillll? t511iii ildl i ililiil di 15il ii\i IdJ ~iilil iii

.

w .

,,,,

Fig. 14 — Marx-Langenheim’ predicted steam zone vs

actual, Pattern 12-6.


10/10

conductivity and diffusivity, 2Kh/m, which is

us

in many heat-loss calculations, is 67.5 Btu/sq ft-°F-Dl’2

for most observation wells at Kern River. Most pub-

lished Vahtes give a range of .54 to 88 for 2&/w.

Since the average Kern River value of 67.5 is also near

the average of the published values, it can be used with

some confidence for thermal studies in other areas.

Conclusions

Analysis of the 10-pattem project steamflood data to

Ott. 1, 1973, leads to the following conclusions.

1. Steamflooding is a very efficient oil displacement

process, and ultimate recoveries up to 55 percent of the

stock-tank oil originally in place appear attainable in

multipattem steamflood. Current recovery in the 10-

pattem project steamflood interval is more than 45 per-

cent, compared with an estimated 15 percent ultimate

recovery by primary means.

2. Steamflooding is rate sensitive, but there is

an economic-optimum injection rate that results in

the highest oil production per dollar cost for steam

injection.

3. As of Ott. 1, 1973, three of the original 32 project

wells were “cold.”

This is because of reservoir het-

erogeneities that seem to prevent a few wells from re-

ceiving heat, regardless of the stimulation efforts.

4.

The use of

radioactive tridutn mid three

d~ff~iefil

salt tracers has been successful in this steamflood.

5. The heat equivalent of produced surface fluids is

nearly 15 percent of injected heat and should be sub-

tracted from the injected heat for theoretical predictions.

6. Surface producing-well flowline temperatures are

important data to monitor to help analyze individual

well performance in steamflood operations.

7. Values of hot water and steitmflood residual oil

saturations measured in the laboratory agreed closely

with field derived values.

8. Current vertical coverage of the total heated zones

(steam and hot water) is 88 percent and areal coverage

is 68 percent, resulting in a volumetric sweep at 1.18

PV input of 60 percent.

9. The capture efficiency has improved with time in

the 10-pattem project steamflood, and is currently ap-

proaching 100 percent.

10. A new steamflood prediction model developed

by Neuman2 has given a reasonable “match” for the

10-pattem project steamflood field data.

Acknowledgments

We wish to thank all those employees of Standard Oil

Co. of California who contributed to the success of the

field trial since it was conceived in 1967. We especial]y

c“’-=b~d G. W. h?pe j T: A. Ed-

hank D. G-. ~lllJu w ,

mondson, B. L. Evans, A. E. Pinson, W. G. Paulsen,

F. I. Walker, the late E. A. Erlewine, C. D. Fiddler,

G. W. Rooney, L. W. Glazier, J. W. Hatcher, J. C.

Harrod, W. M. Johnson, and D. W. Ambrose.

References

1.

2.

3.

4.

Blevins, T. R., Aaeltine, R. J., and Kirk, R. S.: ‘“Anatysisof a

SteamDrive Project, InglewoodField, Califomiii,”J.

Per . Tech .

(Sept. 1969) 1141-1150.

Neuman, C. H.: “A Mathematical Model of Steamflooding—

Appl ications,” paper SPE 4757, presentedat the SPE-AIME45th

Awwa CaliforniaRegionalMeeting, Ventura, Apri l 2 -4 , 1975.

Baker, P. E.: “Effects of Pressure-and Rate on Steam Zone De-

velopment

in Steamflooding,” Sot. Pef. Eng. J.

Oct 973)

274-284; Trans., AlME, 255.

Marx. J. W. and LanQenheim. R. H.: “Reservoir Heating by Hot

Fluid ‘Injection,” Tra~s., AIME (1959) 216, 312-315. - fiT

Original manuscript r ece ived in Soc ie ty of Pe troleum Eng inee rs of fke Feb. 18,

1975. Revised manuscript received Oct. 28, t 9 75. Paper (SPE 4756) was first

pra. samad at tf se SPE-AIME 45th Annual Cal if ornia Regional Meet ing, held in

Ventura, April 2- 4, 1975. @ Copyright 1975 American Insti tute of Mining, Metal-

lurg ical , and Pe troleum Engineers , Inc .

Th s paper wil l be included in the 19757r.snsacbons VOIWIW.

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