CA2015460C - Process for confining steam injected into a heavy oil reservoir - Google Patents

Process for confining steam injected into a heavy oil reservoir

Info

Publication number
CA2015460C
CA2015460C CA 2015460 CA2015460A CA2015460C CA 2015460 C CA2015460 C CA 2015460C CA 2015460 CA2015460 CA 2015460 CA 2015460 A CA2015460 A CA 2015460A CA 2015460 C CA2015460 C CA 2015460C
Authority
CA
Canada
Prior art keywords
reservoir
pattern
portion
steam
depleted
Prior art date
Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
Expired - Lifetime
Application number
CA 2015460
Other languages
French (fr)
Other versions
CA2015460A1 (en
Inventor
Kenneth Edwin Kisman
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Alberta Science and Research Authority
Original Assignee
Alberta Oil Sands Technology and Research Authority
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Alberta Oil Sands Technology and Research Authority filed Critical Alberta Oil Sands Technology and Research Authority
Priority to CA 2015460 priority Critical patent/CA2015460C/en
Publication of CA2015460A1 publication Critical patent/CA2015460A1/en
Application granted granted Critical
Publication of CA2015460C publication Critical patent/CA2015460C/en
Anticipated expiration legal-status Critical
Application status is Expired - Lifetime legal-status Critical

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Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/30Specific pattern of wells, e.g. optimizing the spacing of wells

Abstract

"PROCESS FOR CONFINING STEAM INJECTED INTO
A HEAVY OIL RESERVOIR"

ABSTRACT OF THE DISCLOSURE
The process is practised in the context of a first pattern of wells completed in a first portion of a heavy oil reservoir. The first pattern has undergone steaming and production and the underlying reservoir portion is significantly depleted. A second pattern of wells is completed in a second less-depleted portion of the reservoir. The two reservoir portions are adjacent and in fluid communication. This may be through a laterally extending thief zone high in the reservoir, the thief zone having higher permeability to steam than the main body of the reservoir. Steam injected into the second portion thus will be lost into the depleted portion. The process comprises injecting non-condensable gas into the depleted portion while steaming and producing oil from the less-depleted second portion. The gas is injected at a rate sufficient to maintain the pressure in the two reservoir portions about equal. As a result, the loss of steam to the depleted portion is inhibited.

Description

201~460 1 Field of the Invention 2 This invention relates to an improvement of a steam 3 injection process for the recovery of heavy oil. More 4 particularly, it relates to injecting non-condensable gas into a depleted portion of a reservoir to pressure it up and prevent 6 the escape of steam thereinto, which steam is being injected into 7 an adjacent portion of the reservoir.

8 BACKGROUND OF THE INV~NTION
9 It is conventional practice to inject steam into a heavy oil reservoir to heat the formation and reduce the 11 vlscosity of the oil, thereafter producing the oil onoe it~
12 mobility has been improved. Such an operation is commonly 13 referred to as a "thermal projeat". -14 A problem can arise with respect to a thermal project if a "thief zone" is in communioation with the oil reservoir into 16 which the steam i6 being injected. If this is the case, the 17 in~ected steam will preferentially move into the thief zone.
18 Heating of the oil-saturated portion of the reservoir i~ then ~19 reduo-d.
Prequently the thief zone is a laterally extending 21 section of that portion of the oil-containing reservoir that is 22 to be heated. The sectlon typically will have a relatively high 23 ga~ or water saturat1on. Often it is located at the top of or 24 high in the reservoir.

:

. .

~ , '`' ' ~ 2 201~60 1 A thief zone can al~o occur ln another manner. In 2 heavy oil thermal projects lt i6 common procedure to practice 3 steam injection and oil productlon in a fir6t area and, when the 4 reservoir underlying the area iB 6ignificantly depleted, to then expand the project by commencing operations in an adjacent second 6 area. In some cases, the depleted first portion of the reservoir 7 i9 in fluid communication with the non-depleted second portion 8 of the reservoir. In this situation, steam injected into the ~ non-depleted portion of the reservoir may migrat~ into the depleted portion. As a re6ult, the depleted first portion of the 11 re6ervoir constitutes a thief zone for steam being injected into 12 the second portion.
13 When steam escapes into 6uch a thief zone, it i6 found 14 that injection pre66ure diminishe6 and the temperature in the producing portion of the re~ervoir i6 relatively low. As a 16 result, the oil production rate also drop6 off.
17 There i8 therefore a need for a process that will 18 inhlbit 10~6e6 of injected steam through or into a thief zone.

19 SUMNa~Y OF THE INVENTIO~
Thi6 embodiment of the invention i6 concerned with a 21 situation where there are two adjacent 6team injection and fluid 22 production patterns, both completed in the same re6ervoir. The 23 reservolr portion underlying the fir~t pattern ha6 already 24 experienaed some steam injection and oll produation. Thus it is . .
''" ' ~1~460 1 partially depleted. The reservoir portion underlying the second 2 pattern has experlenced less depletion. There i6 fluid 3 communication between the patterns - stated otherwise, steam 4 injected ~hrough the wells of the second pattern will enter the more depleted reservoir portion.
6 In accordance with the invention, non-condensable gas 7 is injected through wells of the first pattern into the more 8 depleted reservoir portion at the same time that steam is 9 injected through wells of the second pattern. Preferably the non-condensable gas is injected at a rate and in an amount 11 sufficient to substantially equalize the pressure in the more 12 depleted reservoir portion with the pressure in the steam zone 13 in the second reservoir portion. When this is done, steam loss 14 into the more depleted portion of the reservoir is inhibited with a concomitant improvement in oil productlon and steam/oil ratio 16 at the second pattern. The gas injected into the first pattern 17 may also contribute to improved performance in the production 18 wells within the first pattern.

19 DESCRIP~ION OF ~HE DRAWINGS
Figure 1 is a schematic showing the patterns and the 21 gas injection wells which were used in demonstrating the 22 invention at a pilot project;
23 Figure 2 illustrates with logs the nature of the 24 reservoir in the pilot test area;

21~54:60 1 Figure 3 is a plot showing steam injection and bitumen 2 production rates for the B pattern of the pilot test. Arrows on 3 the plot indicate when the injection well BI1 was started up, 4 when BI1 injection was switched from hot water to steam, when the middle zone was completed, when injection wells BI8 and BI9 were 6 started up, when the high steam rate test was conducted, and when 7 outside gas injection began; and 8 Figure 4 is a plot of gas injection rate through the 9 wells identified on the plot.

DESCRIPTION OF THE P~EFERRED EM~O~IMEN~
11 The invention is exemplified by the following example 12 based on a pilot test conducted in the Rearl Lake region of 13 Alberta.
14 The reservoir at the pilot site, depicted in Figure 2, has two oil producing pay zones, a lower zone 1 and a middle zone 16 2. The middle pay zone 1 i8 approximately 35 m thick and has a 17 sand region 3 at its upper end. This region 3 is approximately 18 10 m thick and has signifiaantly higher water saturation than the 19 pay zone 2. The region 3 constitutes a thief zone for steam in~ected through well perforations in the pay zones 1,2.
21 The bitumen in the pay zone 2 is effectively immobile 22 at initlal reservoir conditions.
23 A steam drive pilot was initiated in an A pattern 24 oonsisting of steam ln~ection wells and production wells. The layout of the A pattern wello i6 shown in Figure 1. Each well " '.

"
:; ', . .

l is identified as to pattern (A), nature (injection (I), 2 production (P), or observation (O)) and number. The A pattern 3 was an inverted 7-spot with peripheral steam injection to enclose 4 the pattern and make it eguivalent to an inner pattern in a commercial project. The pattern covered 5.37 acres.
6 At the same time that the A pattern was drilled, an 7 adjacent B pattern was also drilled. The B pattern was 8 originally an inverted 5-spot surrounded by 8 steam injection 9 wells. It was decided to delay start-up of the B pattern to gain operating experience on the A pattern.
11 A steam drive was initiated in December, 1981, in the 12 A pattern and continued for 5 years. Steam was injected into the 13 AI wells and fluid was produced from the AP wells.
14 It became clear that a large volume of steam was being lost from the A pattern, as the steam-oil ratio was very high.
16 As a result of the A pattern experience, changes were 17 made to the B pattern prior to its start-up. It was decided not 18 to inject steam into the peripheral wells of the B pattern.
19 Instead the B pattern was converted from a 5-spot to a 9-spot.
Start-up of the BI1 pattern occurred in February, I985, 21 and start-up of the patterns of BI8 and BI9 was initiated in 22 September, 1987. Steam was injected through the 3 injection 23 wells and fluid produced from the 12 production wells in 24 conventional fashion.
Wells BI2, BI3, BI4, BI5, BI6 and BI7 were also 26 completed in the reservoir as observation wells and were used to 27 monltor temperature and pressure outside the B pattern.

201~60 1The chronology of operatlons in the B pattern and the 2ef~ect on bitumen production is shown ln Flgure 3. Hot water 3injection was initiated into the lower zone 1 of the BI1 pattern 4in February, 1985. Steam injeatlon lnto the lower zone 1 of the 5BI1 pattern began in Au~ust, 1985. Middle zone 2 operations 6began in December, 1986. The BI8 and BI9 patterns were added in 7September, 1987.
8A high rate steam test was conducted in the summer of 91988 in which the steam injection rate was approximately doubled 10for a period of about two months.
11The outside gas injection test was begun in April, 121989, with the injection of natural gas into well~ BI2, BI4 and 13BI6 following perforation of tho6e wells in the region 3 of the 14middle zone 2. Gas injection into wells BI7 and AI2 was 15initiated a few months later, as shown in Figure 4.
16As shown in Figure 3, the high rate steam test resulted 17in a significant increase in bitumen production rates, but the -................................................................................ . :.
18steam-oil ratio did not improve. --19After the high rate steam test, the bitumen production 20rate fell considerably until March, 1989, when the steam- :
21 stimulation of some production wellc began in antioipation of 2~ the outside gas injection test.
23As stated, the outside gaa injection test began in 24April 1989, and i8 still contlnuing. Gas in~ection was conducted ~lmultaneously with steam lnjection. More partlcularly, during 26 the outside gas ln~eation test, the steam injection rate was held 27 ¢on~tant at a rate of only about 60% of that during the high rate 28 ~team test. ~he bltumen produ¢tion rate during the outside gas 29 in~eotlon test .

" ~

20~s4~io 1 started to increase significantly withln one month, and, over the 2 eight month period since gas in~ectlon began, the bitumen 3 production rate has, on average, been more than 80% higher than 4 that prior to gas in~ection.
The instantaneous steam-oll ratio during the outside 6 gas injection test also improved considerably over that observed 7 prior to outside gas injection.
8 No detrimental effects of outside gas injection have 9 been observed. There has been no noticeable increase in gas production at the production wells. The injected gas remains 11 near the top of the payzone 2 due to gravity effects, while 12 liquids are produced through perforated intervals near the base 13 of the pay zone.
14 Prior to outside gas injection, the region 3 allowed fluids to flow out of the B Pattern. In particular, æteam, hot 16 water and hot bitumen flowed out of the B pattern during steam 17 injection within the pattern. This was evidenced by temperature 18 and pressure measurements at the observation wells outside the 19 pattern and by the fact that the pressure within the pattern remained low. When the steam injection rate was increased in the 21 B pattern, a temperature response could be detected even within 22 the A pattern. Thus the A pattern constituted a thief zone in 23 communication with the B pattern.
24 At the time gas injection began into region 3 through wells outside the B pattern, the pressure within the B pattern 26 was only about 800 kPa. The native reservoir pressure is about ~ 300 kPa. Within three months o~ the commencement of outside gas 2 injection, the pressure within the B pattern increased from 800 3 kPa to over 1000 kPa and the pressure within the A pattern 4 increased from about 400 kPa to over 900 kPa. Within the B
pattern, the temperature increased along with the pressure as 6 determined by saturated steam conditions within the B pattern.
7 Prior to and during the outside gas injection 8 operation, wells AP1 and AP3 and AP6 were maintained on g production even though no steam was injected into any wells in the A pattern. Prior to the commencement of outside gas ll injection, the A pattern wells benefitted from heat communication 12 with the B pattern but this heat communication was eliminated 13 when gas injection began. Even though the A pattern wells lost 14 heat communication, the production performance of wells AP1, AP3 and AP6 has increased over that prior to gas injection. This 16 increased production is believed to be related to an improved 17 gravity drainage mechanism due to the increased gas saturation 18 in the A pattern.

Claims (5)

1. A method for recovering heavy oil that is effectively immobile at reservoir conditions, from a reservoir having a partially-depleted portion penetrated by a first pattern of wells and an adjacent less-depleted portion penetrated by a second pattern of steam injection and oil production wells which are completed in said less-depleted portion, the less-depleted portion of the reservoir being in fluid communication with the partially-depleted portion, comprising:
injecting steam into the less-depleted portion of the reservoir through the injection wells of the second pattern, to heat the oil in said portion and render it mobile;
simultaneously injecting non-condensable gas, through at least one well of the first pattern, into the partially-depleted portion of the reservoir at a rate and in an amount sufficient to maintain the pressure in the partially-depleted portion at the gas injection wells about equal with the pressure in the reservoir portion underlying the second pattern and undergoing steam injection; and producing heated oil from the second pattern.
2. The method as set forth in claim 1 wherein:
the non-condensable gas injected is selected from the group consisting of natural gas, flue gas and carbon dioxide.
3. The method as set forth in claim 2 wherein:
the production wells of the second pattern are perforated low in the payzone of the reservoir.
4. The method as set forth in claim 3 wherein:
the reservoir portions are in fluid communication through a thief zone high in the reservoir.
5. The method as set forth in claim 1 wherein:
the reservoir portions are in fluid communication through a thief zone high in the reservoir; and steam and gas injection are continued simultaneously after heat breakthrough at the production wells of the second pattern.
CA 2015460 1990-04-26 1990-04-26 Process for confining steam injected into a heavy oil reservoir Expired - Lifetime CA2015460C (en)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA 2015460 CA2015460C (en) 1990-04-26 1990-04-26 Process for confining steam injected into a heavy oil reservoir

Applications Claiming Priority (1)

Application Number Priority Date Filing Date Title
CA 2015460 CA2015460C (en) 1990-04-26 1990-04-26 Process for confining steam injected into a heavy oil reservoir

Publications (2)

Publication Number Publication Date
CA2015460A1 CA2015460A1 (en) 1991-10-26
CA2015460C true CA2015460C (en) 1993-12-14

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US6581684B2 (en) 2000-04-24 2003-06-24 Shell Oil Company In Situ thermal processing of a hydrocarbon containing formation to produce sulfur containing formation fluids
US6588504B2 (en) 2000-04-24 2003-07-08 Shell Oil Company In situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids
US6698515B2 (en) 2000-04-24 2004-03-02 Shell Oil Company In situ thermal processing of a coal formation using a relatively slow heating rate
US6715546B2 (en) 2000-04-24 2004-04-06 Shell Oil Company In situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore
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US6782947B2 (en) 2001-04-24 2004-08-31 Shell Oil Company In situ thermal processing of a relatively impermeable formation to increase permeability of the formation
US7090014B2 (en) 1999-10-26 2006-08-15 Alberta Science And Research Authority Process for sequentially applying SAGD to adjacent sections of a petroleum reservoir
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