US3795278A

US3795278A - Down-dip steam injection for oil recovery

Info

Publication number: US3795278A
Application number: US00305637A
Authority: US
Inventors: D Whitten; Intire D Mc
Original assignee: Shell Oil Co
Current assignee: Shell USA Inc
Priority date: 1972-11-10
Filing date: 1972-11-10
Publication date: 1974-03-05
Anticipated expiration: 1991-03-05
Also published as: DE2355870C2; CA976084A; DE2355870A1

Abstract

In a dipping reservoir which has an active aquifer located downdip, oil is recovered by injecting a slug of steam only slightly updip from the original oil-water contact in the reservoir while concurrently and subsequently producing fluid from at least one location updip from the point of steam injection.

Description

1 1 Mar. 5, 1974 DOWN-DIP STEAM INJECTION FOR OIL RECOVERY [75] Inventors: Derrill G. Whitten, Houston, Tex.; Daryl C. Mclntire, Seymour, Iowa [73] Assignee: Shell Oil Company, Houston, Tex.

[22] Filed: Nov. 10, 1972 [21] Appl. No.2 305,637

[52] U.S.Cl. ..166/272 51 Int. Cl ..E2lb 43/24 [58] Field ofSearch 166/272, 303, 245

561 References Cited v UNITED STATES PATENTS 3,319,712 5 1967 QBricn 166/245 3,332,485 7/1967 (3611mm 166/245 1? FAULT 1; UP// ,5

3,353,598 11/1967 Smith 166/245 3,360,045 12/1967 Sanlourian.... 166/269 3,474,862 lO/l969 Bruisl 1 1 1 166/272 3,477,510 11/1969 Spillettc 1 166/272 3,572,437 3/1971 Marbcrry 166/272 Primary Examiner-Stephen J. Novosad Attorney, Agent, or FirmH. W. Coryell [5 7 ABSTRACT In a clipping reservoir which has an active aquifer located down-dip, oil is recovered by injecting a slug of steam only slightly updip from the original oil-water contact in the reservoir while concurrently and subsequently producing fluid from at least one location updip from the point of steam injection.

4 Claims, 4 Drawing Figures COLD O/L BANK STEAM ZONE STEAM INJECTOR PATENTED 5 I974 CUMULATIVE INJECTION AND PRODUCTION, PORE VOLUMES 3.795.278 sum 1 uf 2 F/OI COLD OIL BANK 72 STEAII I ZONE INJECTION AND PRODUCTION HISTORY, "LEAPFROO" PROCEDURE USING TWO INJECTORS CUMULATIVE STEAM INJECT WELL 5 OIL /STEAM RAT/O CUMULATIVE OIL l l l l l CUMULATIVE INJECTION AND PRODUCTION, PORE VOLUMES PATENTEI] "AR 5 I974 CUMULATIVE OIL/STEAM RA TIO, bbI/bb/ SHEET 2 OF 2 UPPER STEAM ZONE 3 UPD/P STEAM INJECTOR COLD OIL BANK LOWER STEAM ZONE STEAM INJECTOR +WATER PRODUCER CUMULATIVE STEAM OIL /STEAM RATIO CUMULA T/VE OIL INJECTION AND PRODUCTION HIS TOR Y, COMB/NA T/ON PROCESS YEARS 6 4 DOWN-DIP STEAM INJECTION FOR OIL v RECOVERY BACKGROUND OF THE INVENTION This invention relates to a steam drive oil production process. More particularly, it relates to producing a relatively viscous oil from a dipping reservoir in which the influx of water from a downdip aquifer causes an updip migration of water within the reservoir whenever more fluid is produced than is injected.

In such a reservoir, the permeability may be high and this may aggravate problems due to gravity segregation. In addition, severe problems are posed by the influx of water. If a'conventional type of steam flood is used in such a reservoir, it may be necessary to establish and maintain an undesirably high pressure in the reservoir, and/or to pump off substantially all of the water that tends to enter the production pattern. The injected steam tends to form a thin steam zone that extends between wells along the uppermost portion of the reservoir and gravity causes the liquid flow to be directed predominately downdip. The injected steam causes a cold oil bank to be developed downdip from the injection wells in a manner that may require an undesirably high fluid injection pressure in order to displace the oil.

SUMMARY OF THE INVENTION This invention relates to a steam drive process for producing a relatively viscous oil from a dipping subterranean reservoir located updip from an active aquifer from which water inflows whenever more fluid is produced than is injected at a location above the original oil-water contact within 'the reservoir. Fluid is produced from the reservoir at two or more locations, with one being farther updip from the oil-water contact than another and with the fluid being produced at a rate that causesan inflow of water into the reservoir. A discrete slug ofsteam is injected into the reservoir at one or more locations that isupdip from the oil-water contact but downdip from the farthest downdip fluid production location, with the steam being injected at a rate and pressure sufficient to divert inflowing water around at least one steam zone that is forming and expanding within the reservoir. The production of fluid from the reservoir is continued after the steam slug has been injected. The production from the farthest downdip location is terminated after the water cut has increased to a selected economic limit due to encroaching water influx, e.g., to a water concentration such as about 98 percent or more.

In one preferred embodiment, at least one such downdip steam slug injection with updip production operation is combined with an updip operation in which steam is injected near the uppermost boundary of the reservoir while fluid is produced from at least one location near but downdip from the latter steam injection location. In another preferred embodiment, where the oil-containing portion of the reservoir contains a relatively centrally located layer or streak of material having a permeability that is significantly less than that of other portions of the reservoir, in each steam injection step, the steam is injected at a depth within the reservoir that underlies the layer of relatively low permeability. I

DESCRIPTION OF THE DRAWING FIG. 1 is a schematic illustration of a portion of a reservoir being treated in accordance with this invention. FIG. 2 is a graphical illustration of the results of employing one embodiment of the invention. FIG. 3 is a schematic illustration of a portion of the reservoir being treated in accordance with a combined updip and downdip embodiment of the invention. FIG. 4 is a graphic illustration of the results of employing combination updip and downdip embodiment of the invention.

DESCRIPTION OF THE INVENTION This invention is applicable to substantially any subterranean reservoir that: (l) is inclined by at least about 3 to the horizontal; (2) is sufficiently permeable (e.g., having a permeability of at least about 200 millidarcies) to permit an economically feasible rate of displacement of fluid within the reservoir in response to pressure less than the fracturing pressure of the reservoir; (3) contains an oil which is relatively viscous at the reservoir temperature; and (4) is interconnected with an active source of natural water located downdip of the oil-bearing sands in a manner such that the water encroachment within the reservoir tends to move updip whenever fluid is produced from above the oil-water contact in a manner that reduces the total amount of fluid and/or pressure within the upper portion of the reservoir.

A model of such a reservoir is shown in FIG. 1. The model comprises a rectangular sand pack which is scaled to represent a reservoir sand having a thickness of about feet thick; awidth of about 500 feet, along the strike of a 6 dipping bed; and a length of about 4000 feet, along the dip of the bed. The reservoir sand has a permeability of about 5 darcies throughout all portions except a layer (equivalent to an 8 foot thick layer of the reservoir) which is located about one-third the distance from the bottom and has a permeability of 0.5 darcies. The influx of aquifer water is simulated by injecting water through a manifold at the downdip end of the model at a rate equivalent to 2300 barrels per day. The model is provided with simulated wells 1-9 and B through which fluids can be injected or produced.

The behavior of the model shown in FIG. 1 is relatively accurately indicative of the behavior of an actual subterranean reservoir with respect to the response to an injection of steam or water and the production of fluid, the distribution of heat, and the like.

In respect to such a reservoir, steam injection experiments indicate that a number of difiiculties are encountered by conventional steam drive oil recovery operation. In typical examples of such experiments, steam was injected into wells 1 and 3 at rates equivalent to about 2000 barrels per day and an amount equivalent to 0.7 pore volumes, using an average injection pressure corresponding To 200 psig in the field. Wells 2,4,5,6,7 and 8 were produced at rates up to 1500 barrels per day while well 9, the well nearest the original oil-water contact was produced at about 3000 barrels per day. Where the rate of aquifer water influx was about 3000 barrels per day, the injected steam formed a steam zone which overlaid the entire upper portion of the reservoir and formed a cold oil bank that extended downdip to a point that eventually reached well 8. Most of the oil was produced in the more

downdip wells

6, 7 and 8. The production involved high rates and unrealistic negative prototype production pressures. This indicated that for such an oil recovery process to work it would be necessary to employ additional infill production wells, higher steam zone pressure levels, or some type of stimulation for the downdip wells. Similar production problems were indicated by analogous experiments in which the steam was injected into a single updip well.

In such a reservoir situation the above type of difficulties (which involve the tendency for steam overrunning, water influx, steam zone collapsing by an influx of cold water, and the like) are indicative of the inapplicability of previously known steam drive oil production processes to such a reservoir. With respect to such prior processes, US Pat. No. 3,572,437 indicates that an injection of steam should be followed by an injection of hot water since a process of first steam flooding and then injecting water (e.g., as suggested in US Pats. Nos. 3,353,598 or 3,360,045) are apt to involve a disadvantageous cold water influx induced collapse of the steam zone. In a water drive reservoir of the type to which the present invention is applicable, the avoidance of the enroachment by the relatively cool aquifer water would be unfeasibly expensive to avoid. US Pat. No. 3,477,510 indicates that in a reservoir in which gravity segregation is apt to occur, a steam drive should be effected by injecting alternating slugs of steam and water in order to avoid steam overrunning and the water underrunning. In a water drive reservoir, a water encroachment occurs whenever more fluid is produced than is injected, and the encroachment prevention and alternating slug mode of operation would be unfeasibly expensive.

FIG. I shows an early stage (after simulated six months injection of steam) of application of the present process to a dipping and inhomogeneous reservoir in which there is a significant water drive from downdip. In the illustrated experiment, the steam was injected through well B at a rate equivalent to 1850 barrels per day. The reservoir oil saturation at the beginning of the steam injection was 50 percent. A constant 2300 barrels per day water influx was simulated throughout the experiment by an injection through a special manifold at the downdip end of the model. During the steam injection, wells 2-6 were produced at rates up to 1000 barrels per day. Two years of steam injection produced a steam zone which extended 200 feet downdip from the injection well B and about 1800 feet updip to just beyond Well 3.

A reservoir of the type to which the present invention is applicable is apt to be inhomogeneous. Such inhomogeneties are apt to comprise a layer or zone that is: thin relative to the total thickness of the reservoir, extends along substantially all of the reservoir, and is relatively centrally located within the reservoir. The reservoir shown in FIG. 1 contains a low permeability layer (permeability 0.5 darcies) located about one-third the distance from the bottom sand of the reservoir (permeability of S darcies). The tight streak is about 8 feet (i.e., a thin layer relative to the 75-foot thick reservoir) and extends along substantially all portions of the reservoir within the production pattern. In a preferred manner of operating the present invention, the steam is injected into such a reservoir so that it is forced to enter the portion below such a streak or tight zone. As shown in FIG. 1, such an injection procedure causes the expanding steam zone 11 to partially underrun such a tight streak by forming steam zone fingers such as 11a. Such underrunning tends to improve the vertical profile of the steam zone and thus tends to reduce the bypassing of the oil that is to be displaced ahead of the steam zone to form the cold oil bank 12.

FIG. 2 shows the result of repetitive or leap frog use of the downdip steam slug injection process of this invention. While fluid was being produced from a series of wells located along dip, steam was injected in succession through well 9 and well 5. The experiment was continued until a total of 0.6. pore volumes of steam was injected into a reservoir having a 60 percent initial oil saturation. As will be apparent from the injection production history on the graph, the oil recovery amounted to about 0.2 pore volumes of oil recovered at an oil steam ratio of slightly more than 0.3, during a 10 year period. An analogous experiment in which a similar amount of steam was'injected in succession through

wells

9, 6 and 3 indicated that the attainment of such results are relatively insensitive to the number of wells that are so employed.

In various stages of the present process it is desirable to produce fluid from wells which have been reached by a portion of the expanding steam zone within the reservoir. As known to those skilled in the art, numerous procedures can be utilized to maintain a suitable efiiciency of oil production. For example, gas anchors, and/or downhole gas-liquid segregation into conduits arranged for separate production of liquid and gas, two stage pumping systems, or the like procedures can be used. In a particular suitable procedure. a pumping device can be supercharged by means of a jet-pump through which a small amount of power fluid is injected to prevent vapor-locking within the pump section chamber, as described in the co-pending patent application Ser. No. 254,276, filed May 17, l972.

Experiments such as those described above indicate that certain advantages and limitations are involved in either updip or downdip steam injection processes with respect to a field-wide recovery process. The updip steam injection is efficient in driving the oil into the upper and middle portion of the reservoir but the aquifer influx must be produced within the downdip part of the reservoir, either from high volume producers or by special well located near the oil-water contact. The downdip steam slug injection is effective in recovering oil from near the oil-water contact, and is relatively uneffected by the aquifer behavior, but a relatively low oil/steam ratio is obtained and a long production time would be required to extend such a procedure to the updip area. Thus, a combination of the updip and downdip processes might possibly enhance the advantages of each other.

FIG. 3 shows the dispositions of an upper steam zone 16 and a lower steam zone 17 after a simulated 1.6 year injection of steam into

wells

3 and 8.

In the completed experiment, a total of 0.7 pore volumes of steam was injected into the updip well 3 at rates up to 2000 barrels per day over a 10-year period while 02 pore volumes was injected into the downdip well '8 during the first 2 years. After being shut in for one year, i.e., during the third year of the experiment, well 8 was operated as a producing well that produced 1800 barrels per day of fluid for the remainder of the experiment. A constant aquifer-water influx of 2300 ing wells. As a result, the downdip producers were able to produce at high oil rates without the draw-down problems that were indicated when the updip continuous injection process was employed by itself.

FIG. 4 shows the injection and production results. An oil recovery of 0.34 pore volumes was attained at an oil-steam ratio of 0.39 and since the updip and downdip injection procedures were found to complement each other, the process performs as a summation of the two processes.

An analogous experiment in which well 1 (located only 65 feet from the updip fault) was used as the upper injector (instead ofwell 3), produced substantially similar results. This indicates that the oil recovery is relatively unaffected by the position of the updip injector along the dip. This allows flexibility relative to operational ease or the availability of an existing well pattern or the like, with respect to selecting the location of the updip wells.

.In an analogous experiment, Well 8 was not produced (after the injection of the downdip steam slug) so that the full 2300 barrels per day of water influx was produced from

wells

7, 6 and 5. The maximum gross rate of fluid production of these wells was increased to handle the added influx of water. The overall oil recovery was substantially unchanged, indicating that the efficiency is good as long as the aquifer influx is produced in the most downdip two or three rows of wells.

An analogous experiment in which a 1000 barrel per day aquifer influx was simulated during the first two years indicated, in spite of such a variation, the oil recovery was substantially unchanged. In a field operation, during the initial period such a decrease in aquifer influx might be caused by the pressure build-up resulting from the injection of the downdip steam slug.

What is claimed is:

1. In a steam drive process for producing oil from a dipping oil reservoir located just updip from an aquifer from which Water inflows when fluid is produced from within the reservoir updip of the oil-water contact the improvement which comprises:

producing fluid from at least two locations at different distances updip from the oil-water contact at a rate causing an inflow of water into the reservoir;

injecting a slug of steam in at least one location updip from the oil-water contact but downdip from the farthest downdip production location; injecting the steam at a rate and pressure sufficient to divert the inflowing water around an expanding steam zone; and

continuing the fluid production after-the steam slug has been injected at least until the water cut has reached a selected limit in at least the farthest downdip production location.

2. The process of claim 1 including the step of repeating said downdip steam slug injection and fluid production by injecting at least one additional downdip slug of steam into at least one additional location that is updip from the first injection location but downdip from the then existing downdip production location.

3. The process of claim 1 in which the reservoir contains a centrally located layer having a relatively low permeability and said steam slug is injected selectively into a depth interval lower than the top of said layer.

duction location.

mg UNITED STATES PATENT OFFICE CERTIFICATE OF CORRECTION March 5, 1974 Patent No. 3,795,278 Dated Inventor) DERRILL G. WHITTEN It is certified that error appears in the above-identified patent and that said Letters Patent are hereby corrected as shown below:

The inventorship should read:

"In'vehtor: Derrill G. Whitten, Houston, Texas" Signed and sealed this 9th day of July 1974p.

(SEAL) Attest: i I MCCOY M.GIBSON,JR. c. MARSHALL DANN Attesting Officer Commissioner. of Patents

Claims

1. In a steam drive process for producing oil from a dipping oil reservoir located just updip from an aquifer from which water inflows when fluid is produced from within the reservoir updip of the oil-water contact the improvement which comprises: producing fluid from at least two locations at different distances updip from the oil-water contact at a rate causing an inflow of water into the reservoir; injecting a slug of steam in at least one location updip from the oil-water contact but downdip from the farthest downdip production location; injecting the steam at a rate and pressure sufficient to divert the inflowing water around an expanding steam zone; and continuing the fluid production after the steam slug has been injected at least until the water cut has reached a selected limit in at least the farthest downdip production location.

4. The process of claim 1 in which steam is injected into at least one location updip from at least one production location.