CA1304287C - Steaming process, involving a pair of horizontal wells, for use in heavy oil reservoir - Google Patents
Steaming process, involving a pair of horizontal wells, for use in heavy oil reservoirInfo
- Publication number
- CA1304287C CA1304287C CA000604268A CA604268A CA1304287C CA 1304287 C CA1304287 C CA 1304287C CA 000604268 A CA000604268 A CA 000604268A CA 604268 A CA604268 A CA 604268A CA 1304287 C CA1304287 C CA 1304287C
- Authority
- CA
- Canada
- Prior art keywords
- steam
- wells
- well
- pressure
- temperature
- 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
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
- E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimizing the spacing of wells comprising at least one inclined or horizontal well
Abstract
"STEAMING PROCESS, INVOLVING A PAIR OF HORIZONTAL
WELLS, FOR USE IN HEAVY OIL RESERVOIR"
ABSTRACT OF THE DISCLOSURE
A pair of horizontal parallel co-extensive wells, one spaced closely above the other, are completed so that they extend through a heavy oil reservoir in close proximity to its base.
The upper well is referred to as the injector and the lower a the producer. Each well has a screened liner and an inner tubing string extending the length of the well. Steam is circulated separately through each of the wells to heat by conduction the span of formation extending between the wells and establish fluid communication between them. The circulation is conducted in through the tubing and out through the annulus at an elevated pressure that is less than fracture pressure. The rate of production of effluent from each well is controlled to maintain its temperature just below saturated steam temperature. Once communication is established, steam circulation in the producer is discontinued and the well is produced through the tubing.
Steam is then injected through both the annulus and tubing of the injector. Condensate and oil are produced through the lower well. Steam-assisted gravity drainage is the mechanism thereafter used to heat the reservoir and produce the oil.
Production rate is controlled to maintain the temperature and pressure of the produced fluid just below saturated steam conditions.
WELLS, FOR USE IN HEAVY OIL RESERVOIR"
ABSTRACT OF THE DISCLOSURE
A pair of horizontal parallel co-extensive wells, one spaced closely above the other, are completed so that they extend through a heavy oil reservoir in close proximity to its base.
The upper well is referred to as the injector and the lower a the producer. Each well has a screened liner and an inner tubing string extending the length of the well. Steam is circulated separately through each of the wells to heat by conduction the span of formation extending between the wells and establish fluid communication between them. The circulation is conducted in through the tubing and out through the annulus at an elevated pressure that is less than fracture pressure. The rate of production of effluent from each well is controlled to maintain its temperature just below saturated steam temperature. Once communication is established, steam circulation in the producer is discontinued and the well is produced through the tubing.
Steam is then injected through both the annulus and tubing of the injector. Condensate and oil are produced through the lower well. Steam-assisted gravity drainage is the mechanism thereafter used to heat the reservoir and produce the oil.
Production rate is controlled to maintain the temperature and pressure of the produced fluid just below saturated steam conditions.
Description
z~
1 Field of thQ Inven~ion
1 Field of thQ Inven~ion
2 This invention relates to a thermal method for
3 recovering heavy oil from a reservoir. The msthod involves
4 providing a pair of horizontal wellbores which extend into the reservoir close to its base. The wells are closely spaced, one 6 above the other. The span of formation between the wells is 7 heated by conduction by operating the two wells as `hot fingers' 8 or heating elements, as a first step, so that the oil in the span 9 is rendered mobile and fluid may move through the ~pan. The upper well is then operated as a steam injector, to heat the 11 formation above it and the bottom well is operated as a producer, 12 to drain away and produce heated oil and condensate.
13 BACKGRO~ND OF THE INVENTIQN
14 ~he present invention was developed in connection with the Athabasca oil sands of Northern Alberta. It will be 16 described below in conneckion with that reservoir and the 17 problems involved in producing heavy oil frc,m it. However, it 18 is contemplated that the invention will find app}ication in other 19 heavy oil reservoirs as well.
The expression "heavy oil" is used herein to denote 21 bitumen and viscous petroleum.
22 The Athabasca oil sands have heretofore been 23 produced by following one of two general schemes. In the areas 24 where the reservoir lies close to the ground surface, the overburden may be stripped away, the oil sand mined with 26 draglines, and the oil recovered from the mined oil sand using 27 a slurryin~/flotation process referred to as the `hot water 28 proaess'. In the areas where the oil sand i8 too ~3~ '7 1 deeply buried to ~e mined, the procedures practised normally 2 involve heating the formation by steam injection or forward 3 combustion, to mobilize the oil, and then driving it to a 4 producer well through which it i5 recovered. These latter procedures may be referred to as ' in situ thermal methods' for 6 recovering the oil.
7 There are problems associated with the Athabasca 8 reservoir which make it difficult to recover oil therefrom using 9 oonventlonal thermal techniques. These include:
- That the oil is extremely viscous at reservoir 11 conditions and thus is substantially immobile and 12 it saturates the pores of the unconsolidated sand.
13 Thus the formation has virtually no injecti.vity;
14 - That the lack of injectivity has heretofore necessitated ` that the formation first ~e 16 fractured, in order to inject steam. Fractures 17 typioally climb upwaxds in the Athabasca 18 reservoir, usually in the form of vertical 19 fraotures, thus making it difficult to reliably achieve communication channels between injectors 21 and producers and to obtain gOOa lateral 22 dispersion of the heat through the reservoir;
23 - That reliance on fracturQs can lead to losses of 24 steam into thief zones with which the fractures 25 ~ communicate; and 26 - That the cold sink provided by the non-heated 27 part of the reservoir acts to extract heat 28 from the heated oil moving through the , . . .
i ~l~,, . ;,, ~, 1 fractures and this leads to blockage of the 2 communication channel.
3 There thus exists a need for a method that:
4 - is adapted to reliably establish communication chann~ls leading from the heated zone to a 6 producer;
7 - is adapted to predictably heat and drain a prs-8 determined part of the reservoir; and 9 - is characterized by an economical steam/oil ratio (SOR) and a capability for recovering a high 11 proportion of the oil in place.
12 SUMMARY OF THE INVE~TION
13 In aacordance with the invention, we practice the 14 following combination of steps:
- Provlding a pair of wells which extend through 16 the reservoir, close to its base, in substantially 17 horizontaI,parallelandco-extensivearrangement, 18 one such well ('the injector~) being closely 19 spaced above the other (~the producer'~, within 20 ~ ~ the range of about 3 - 8 metres. Each of the 21 wells is completed with a screened liner (or 22 equivalent member) and an internal tubing string 23 ; extending to the end of the liner;
24 - Initially operating the wells separately and :: :
25~ 6imultaneously as `hot fingers' to heat the 26 span of formation extending between them by ~ 2~7 conduction. ~his is accomplished by ;28 circulating steam at elevated pressure through ~" ~3~Z~7 1 the screened wellbores. The steam is pumped in 2 through the tuhin~ string and a produced fluid 3 comprising condensed water and heated oil is 4 removed through the well annulus. Circulation is practised at elevated pressure that is close to 6 but less than the formation fracturing pre~sure.
7 Preferably, the lower well is operated at a 8 slightly lower pressure than the upper w811, SO9 there is a pressure differential seeking to drive fluid downwardly through the span. The production I1 o~ effluent from the annulus is throttled or 12 controlled to maintain its temperature and 13 pressure just below saturated steam conditions.14 Circulation in thi8 manner is continued until fluid communication between the wells is imminent 16 or established (i.e. fluid transmissibility 17 through the ~pan is established). Such ~18 ~ communication is conveniently indicated by a 19 sudden inability to maintain a pressure differential;
21 - At this point~, the method of operating the pair 22 of wells is changed. Steam circulation is 23 ~ ~ terminated at both wells and steam is now injected 24 into the formation through the annulus and tubing of the lnjector at an elevated constant pressure 26; ~ ~ ~ that is less than the formation fracturing 27 pressura. At the same time, the producer is 28 converted to production. Output from the 29 annulus of the producer is through the tubing (so that f.low in the two annuli is co-31 aurrent). Output ~low from the -- 13~287 1 producer is controlled, in the manner of a 2 thermodynamic steam trap, to ensure that steam is 3 not produced to any significant extent and to 4 minimize significant build-up o~ liquia in the span. Stated otherwiseJ one wants to avoid 6 'short-circuiting' by the steam between the wells 7 or, alternatively, `drowning' of part or all of 8 the length of the producer. These objectives are 9 sought by throttling production from the producer to maintain the temperature and pressure of the ll production stream, at the wellhead, just below 12 saturated steam conditions. T~his can preferably 13 be done by monitoring the temperature and pressure 14 of the production stream and adjusting a valve ~ controlling production output in response thereto, 16~ to maintain the production stream temperature at 17 ~ the desired level~with respeat to the production 18 stream pressure. If production starts to COO1J
19 the productlon valve opens to draw more liquids whereas, if steam is produced, the eystem will 21 throttle back. In this way, production is matched 22 - to the rate of condensation and drainage within 23 ~ ~the reservoir.
24 The invention as described incorporates the following 25 concepts and~mechanisms1 ~ ~
26 - Spacing the wells close enough together so that 27 ~ heating the span, as a first step, by the :~ : :
, ,~1 :`, ~ ~3g~Z~7 1 slow mechanism of conductance, without fracturing, 2 may be accomplished in a reasonably short time3 period, but spacing them far enough apart so that 4 the injected steam does not significantly interfere with liquid dralnacte through the span 6 during the subsequent production phase;
7 - Using conductance as the heating mechanism with 8 the result that the direction of the heat movement 9 is controlled and coupling this approach with utilization of two closely and vertiaally spaced 11 wells,~so that the heat emanates from both of them 12 simultaneously, thereby reducing the time taken 13 to establish thermal communication uslng this slow 14 but predictable system;
- Locating the wells close to the base of the 16 reservolr and utilizing steam assisted gravity 17 drainage as ths process mechanism for heating the 18 reservoir, to create an upwardly and laterally ~ :
19 ~ advancing heated steam chest/cold formation 20 : interfacei 21 ~ - Designing the wells, by judicious selection of 22 hole size, liner size and tubing size, so as to 23~ have very low annular fluid velocities and hence 24 low pressure gradients. This feature allows : :
gravity to automatically adjust drainage to 26 reasonable variations in reservoir quality 27 ~ along the lengths of the wells. The ~3Q~7 1 wells function as constant pressure sources 2 and sinks. ~he reservoir characteristic~
3 therefore determlne the distribution of steam 4 injection and fluid production along the wells;
6 _ Injecting steam at a substantially constant 7 pressure but varying rate during the 8 production phase, to provide a simple method g for coping with the varying steam demand of the enlarging heated steam chamber. The steam 11 travels to the edges of the chamber, 12 condenses, and drains to the bottom. The 13 condensing steam heats (by thermal condllctionj 14 a thin layer of undepleted sand near the boundary of the chamber. This mobilizes the 16 bitumen (or oil) and allows it to drain with 17 the condensate. As the hitumen drains, steam 18 ~ advances into the newly depleted reservoir.
19 The condensate and ~itumen are collected at the bottom production well;
21 Throttling the producer to maintain the 22 temperature of the production stream at the ~23 wellhead just below saturated steam 24 conditions, to thereby avoid short-circuiting by the steam and to m~tch production to the 26 rate of condensation and drainage within the 27 reservoir, thereby avoiding liquid build-up in 28 the span; and ~3~87 1 - During the communication development phase, 2 circulating the steam in through the tubing 3 and out through the annulus. This solves a 4 problem discovered in the pilot operation, in that if one circulates the steam in through 6 the annulus and out the tubing~ there is 7 excessive heat loss from the annulus to the 8 tubing and its ~ontents- Steam entering the g annulus lost heat to both the formation and the tubing, causing it to cond~nse before 11 reaching the end of the well.
13 Figure 1 is a fanciful isometric view showing a 14 subterranean tunnel formed in the competent limestone formation underlying the oil sand reservoir, with three palrs 16 of wells, each extending upwardly from the tunnel into the ~; 17 oil sand and then projecting substantially horizontally and 1~ co-extensively through the reservoir, close to its base, one ~; ~19 well being spaced above the other, with both wells having screened liners positioned in the reservoir;
~ 21 Figure 2 is a fanciful end view showing the wells ; 22 positioned in the reservoir, having formed a steam-heated 23 chamber;
~24 Figure 3 is a plan view showing the layout of ~25 tunnels, horizontal wells, and vertical o~servation wells 26 used in applicants' pilot project;
27 ; Figure 4 is a side view in simplified form of the 2~ tubular goods assemblies in the wells;
~3~4~2~3~7 1 Figure 5 is a schematic side view showing the 2 screened liner and tubing strings;
3 Figure 6 is a schematic side view of the production 4 well control system; and Figure 7 is a plot of injection and production data 6 relating to one pair of wells operated in applicants~ pilot 7 project.
8 DESCRIPTION OF ~HE PREFERRED EMBODIMENT
g The invention is exemplified by a pilot test, carried out by applicants~ which will now be described.
11 The pilot test was carried out in connection with 12 the McMurray heavy oil reservoi.r in the Athabasca region of 13 Northern Alberta. At the test site, the NcMurray formation 14 is about 40 metres thick, with the clean pay zone forming the bottom 20 metres. The pay zone rests on a competent 16 limestone formation and is capped by shale beds. The top of 17 the pay zone is located at a depth of about 140 metres.
18 Porosity and oil saturation in the pay zone are about 30~ and 19 85% respectively and the permeability is estimated at about 0.1 to 15.0 Darcys.
21 Having reerence to Figure 1, a pair of 3 m 22 diameter vertical shafts 1 were sunk into the limestone to a 23 depth of 213 m. 930 m of horizontal 4 m high x 5 m wide 24 tunnels 2 were formed, connecting the shafts 1.
Three pairs of wells 3,4 were drilled, as shown in 26 Figures 1 and 3O The pairs were about 24 m apart. The wells 27 3,4 slanted up from the tunnels 2 and then turned to extend 28 horizontally. Each well 3,4 had a total length of about 160 LZ~37 1m, with a section of about 55 m extending horizontally 2through the oil pay. The wells 3,4 of each pair were 3essentially parallel and co-extensive and they were 4vertically spaced apart about 5 m. The upper well 4 (the
13 BACKGRO~ND OF THE INVENTIQN
14 ~he present invention was developed in connection with the Athabasca oil sands of Northern Alberta. It will be 16 described below in conneckion with that reservoir and the 17 problems involved in producing heavy oil frc,m it. However, it 18 is contemplated that the invention will find app}ication in other 19 heavy oil reservoirs as well.
The expression "heavy oil" is used herein to denote 21 bitumen and viscous petroleum.
22 The Athabasca oil sands have heretofore been 23 produced by following one of two general schemes. In the areas 24 where the reservoir lies close to the ground surface, the overburden may be stripped away, the oil sand mined with 26 draglines, and the oil recovered from the mined oil sand using 27 a slurryin~/flotation process referred to as the `hot water 28 proaess'. In the areas where the oil sand i8 too ~3~ '7 1 deeply buried to ~e mined, the procedures practised normally 2 involve heating the formation by steam injection or forward 3 combustion, to mobilize the oil, and then driving it to a 4 producer well through which it i5 recovered. These latter procedures may be referred to as ' in situ thermal methods' for 6 recovering the oil.
7 There are problems associated with the Athabasca 8 reservoir which make it difficult to recover oil therefrom using 9 oonventlonal thermal techniques. These include:
- That the oil is extremely viscous at reservoir 11 conditions and thus is substantially immobile and 12 it saturates the pores of the unconsolidated sand.
13 Thus the formation has virtually no injecti.vity;
14 - That the lack of injectivity has heretofore necessitated ` that the formation first ~e 16 fractured, in order to inject steam. Fractures 17 typioally climb upwaxds in the Athabasca 18 reservoir, usually in the form of vertical 19 fraotures, thus making it difficult to reliably achieve communication channels between injectors 21 and producers and to obtain gOOa lateral 22 dispersion of the heat through the reservoir;
23 - That reliance on fracturQs can lead to losses of 24 steam into thief zones with which the fractures 25 ~ communicate; and 26 - That the cold sink provided by the non-heated 27 part of the reservoir acts to extract heat 28 from the heated oil moving through the , . . .
i ~l~,, . ;,, ~, 1 fractures and this leads to blockage of the 2 communication channel.
3 There thus exists a need for a method that:
4 - is adapted to reliably establish communication chann~ls leading from the heated zone to a 6 producer;
7 - is adapted to predictably heat and drain a prs-8 determined part of the reservoir; and 9 - is characterized by an economical steam/oil ratio (SOR) and a capability for recovering a high 11 proportion of the oil in place.
12 SUMMARY OF THE INVE~TION
13 In aacordance with the invention, we practice the 14 following combination of steps:
- Provlding a pair of wells which extend through 16 the reservoir, close to its base, in substantially 17 horizontaI,parallelandco-extensivearrangement, 18 one such well ('the injector~) being closely 19 spaced above the other (~the producer'~, within 20 ~ ~ the range of about 3 - 8 metres. Each of the 21 wells is completed with a screened liner (or 22 equivalent member) and an internal tubing string 23 ; extending to the end of the liner;
24 - Initially operating the wells separately and :: :
25~ 6imultaneously as `hot fingers' to heat the 26 span of formation extending between them by ~ 2~7 conduction. ~his is accomplished by ;28 circulating steam at elevated pressure through ~" ~3~Z~7 1 the screened wellbores. The steam is pumped in 2 through the tuhin~ string and a produced fluid 3 comprising condensed water and heated oil is 4 removed through the well annulus. Circulation is practised at elevated pressure that is close to 6 but less than the formation fracturing pre~sure.
7 Preferably, the lower well is operated at a 8 slightly lower pressure than the upper w811, SO9 there is a pressure differential seeking to drive fluid downwardly through the span. The production I1 o~ effluent from the annulus is throttled or 12 controlled to maintain its temperature and 13 pressure just below saturated steam conditions.14 Circulation in thi8 manner is continued until fluid communication between the wells is imminent 16 or established (i.e. fluid transmissibility 17 through the ~pan is established). Such ~18 ~ communication is conveniently indicated by a 19 sudden inability to maintain a pressure differential;
21 - At this point~, the method of operating the pair 22 of wells is changed. Steam circulation is 23 ~ ~ terminated at both wells and steam is now injected 24 into the formation through the annulus and tubing of the lnjector at an elevated constant pressure 26; ~ ~ ~ that is less than the formation fracturing 27 pressura. At the same time, the producer is 28 converted to production. Output from the 29 annulus of the producer is through the tubing (so that f.low in the two annuli is co-31 aurrent). Output ~low from the -- 13~287 1 producer is controlled, in the manner of a 2 thermodynamic steam trap, to ensure that steam is 3 not produced to any significant extent and to 4 minimize significant build-up o~ liquia in the span. Stated otherwiseJ one wants to avoid 6 'short-circuiting' by the steam between the wells 7 or, alternatively, `drowning' of part or all of 8 the length of the producer. These objectives are 9 sought by throttling production from the producer to maintain the temperature and pressure of the ll production stream, at the wellhead, just below 12 saturated steam conditions. T~his can preferably 13 be done by monitoring the temperature and pressure 14 of the production stream and adjusting a valve ~ controlling production output in response thereto, 16~ to maintain the production stream temperature at 17 ~ the desired level~with respeat to the production 18 stream pressure. If production starts to COO1J
19 the productlon valve opens to draw more liquids whereas, if steam is produced, the eystem will 21 throttle back. In this way, production is matched 22 - to the rate of condensation and drainage within 23 ~ ~the reservoir.
24 The invention as described incorporates the following 25 concepts and~mechanisms1 ~ ~
26 - Spacing the wells close enough together so that 27 ~ heating the span, as a first step, by the :~ : :
, ,~1 :`, ~ ~3g~Z~7 1 slow mechanism of conductance, without fracturing, 2 may be accomplished in a reasonably short time3 period, but spacing them far enough apart so that 4 the injected steam does not significantly interfere with liquid dralnacte through the span 6 during the subsequent production phase;
7 - Using conductance as the heating mechanism with 8 the result that the direction of the heat movement 9 is controlled and coupling this approach with utilization of two closely and vertiaally spaced 11 wells,~so that the heat emanates from both of them 12 simultaneously, thereby reducing the time taken 13 to establish thermal communication uslng this slow 14 but predictable system;
- Locating the wells close to the base of the 16 reservolr and utilizing steam assisted gravity 17 drainage as ths process mechanism for heating the 18 reservoir, to create an upwardly and laterally ~ :
19 ~ advancing heated steam chest/cold formation 20 : interfacei 21 ~ - Designing the wells, by judicious selection of 22 hole size, liner size and tubing size, so as to 23~ have very low annular fluid velocities and hence 24 low pressure gradients. This feature allows : :
gravity to automatically adjust drainage to 26 reasonable variations in reservoir quality 27 ~ along the lengths of the wells. The ~3Q~7 1 wells function as constant pressure sources 2 and sinks. ~he reservoir characteristic~
3 therefore determlne the distribution of steam 4 injection and fluid production along the wells;
6 _ Injecting steam at a substantially constant 7 pressure but varying rate during the 8 production phase, to provide a simple method g for coping with the varying steam demand of the enlarging heated steam chamber. The steam 11 travels to the edges of the chamber, 12 condenses, and drains to the bottom. The 13 condensing steam heats (by thermal condllctionj 14 a thin layer of undepleted sand near the boundary of the chamber. This mobilizes the 16 bitumen (or oil) and allows it to drain with 17 the condensate. As the hitumen drains, steam 18 ~ advances into the newly depleted reservoir.
19 The condensate and ~itumen are collected at the bottom production well;
21 Throttling the producer to maintain the 22 temperature of the production stream at the ~23 wellhead just below saturated steam 24 conditions, to thereby avoid short-circuiting by the steam and to m~tch production to the 26 rate of condensation and drainage within the 27 reservoir, thereby avoiding liquid build-up in 28 the span; and ~3~87 1 - During the communication development phase, 2 circulating the steam in through the tubing 3 and out through the annulus. This solves a 4 problem discovered in the pilot operation, in that if one circulates the steam in through 6 the annulus and out the tubing~ there is 7 excessive heat loss from the annulus to the 8 tubing and its ~ontents- Steam entering the g annulus lost heat to both the formation and the tubing, causing it to cond~nse before 11 reaching the end of the well.
13 Figure 1 is a fanciful isometric view showing a 14 subterranean tunnel formed in the competent limestone formation underlying the oil sand reservoir, with three palrs 16 of wells, each extending upwardly from the tunnel into the ~; 17 oil sand and then projecting substantially horizontally and 1~ co-extensively through the reservoir, close to its base, one ~; ~19 well being spaced above the other, with both wells having screened liners positioned in the reservoir;
~ 21 Figure 2 is a fanciful end view showing the wells ; 22 positioned in the reservoir, having formed a steam-heated 23 chamber;
~24 Figure 3 is a plan view showing the layout of ~25 tunnels, horizontal wells, and vertical o~servation wells 26 used in applicants' pilot project;
27 ; Figure 4 is a side view in simplified form of the 2~ tubular goods assemblies in the wells;
~3~4~2~3~7 1 Figure 5 is a schematic side view showing the 2 screened liner and tubing strings;
3 Figure 6 is a schematic side view of the production 4 well control system; and Figure 7 is a plot of injection and production data 6 relating to one pair of wells operated in applicants~ pilot 7 project.
8 DESCRIPTION OF ~HE PREFERRED EMBODIMENT
g The invention is exemplified by a pilot test, carried out by applicants~ which will now be described.
11 The pilot test was carried out in connection with 12 the McMurray heavy oil reservoi.r in the Athabasca region of 13 Northern Alberta. At the test site, the NcMurray formation 14 is about 40 metres thick, with the clean pay zone forming the bottom 20 metres. The pay zone rests on a competent 16 limestone formation and is capped by shale beds. The top of 17 the pay zone is located at a depth of about 140 metres.
18 Porosity and oil saturation in the pay zone are about 30~ and 19 85% respectively and the permeability is estimated at about 0.1 to 15.0 Darcys.
21 Having reerence to Figure 1, a pair of 3 m 22 diameter vertical shafts 1 were sunk into the limestone to a 23 depth of 213 m. 930 m of horizontal 4 m high x 5 m wide 24 tunnels 2 were formed, connecting the shafts 1.
Three pairs of wells 3,4 were drilled, as shown in 26 Figures 1 and 3O The pairs were about 24 m apart. The wells 27 3,4 slanted up from the tunnels 2 and then turned to extend 28 horizontally. Each well 3,4 had a total length of about 160 LZ~37 1m, with a section of about 55 m extending horizontally 2through the oil pay. The wells 3,4 of each pair were 3essentially parallel and co-extensive and they were 4vertically spaced apart about 5 m. The upper well 4 (the
5'injector") was slightly offset from the lower well 3 (the
6"producer"). The lower well 3 extended generally parallel to 7the ~ase of the pay zone and was spaced about 3 m 8thereabove.
gThe completion details of the wells 3,4 is set 10forth in Figures 4 and 5. Each well comprised conductor pipe 116, cemented surface casing 7, and a production liner 8. A
12string of tubing 9 extended the length of the well. ~he 13liner 8 comprised alternating screened joints lO and blank 14casing joints 11, over the last 55 m, and blank casing 15extending back to the wellhead 12.
16The pilot was equipped with vertical observation 17wells and instrumentali2ed, as shown in Figure 3.
18Two separate production control systems A, B wexe 19used in conjunction ~ith the wells. In the producer well 20identified as API, a pneumatic pressure transmitter 15 21monitored line pressure in each well at the wellhead. The 22signals from the transmitter 15 were conveyed to a function 23generator 16. ~he generator 16 had a user-shaped cam (not 24shown) which would convert the pressure signal to a 25temperature signal corresponding to the saturation tboiling) 26curve for water. The generator output was sent as a remote 27set-point signal to temperature controller 17 via a biasing 28regulator l~. The controller 17 controlled production rate 2gby a valve 19. The regulator 1~ subtracted a constant value ~3~3~2~7 1 to the temperature set-point to ensure that the production 2 rate was controlled to yield a production stream having a 3 temperature at about 10 - 40C below saturated steam temperature. The production control system A thus was adapted to automatically maintain the drawdown re~uired to 6 meet the condition that the production stream leave the well
gThe completion details of the wells 3,4 is set 10forth in Figures 4 and 5. Each well comprised conductor pipe 116, cemented surface casing 7, and a production liner 8. A
12string of tubing 9 extended the length of the well. ~he 13liner 8 comprised alternating screened joints lO and blank 14casing joints 11, over the last 55 m, and blank casing 15extending back to the wellhead 12.
16The pilot was equipped with vertical observation 17wells and instrumentali2ed, as shown in Figure 3.
18Two separate production control systems A, B wexe 19used in conjunction ~ith the wells. In the producer well 20identified as API, a pneumatic pressure transmitter 15 21monitored line pressure in each well at the wellhead. The 22signals from the transmitter 15 were conveyed to a function 23generator 16. ~he generator 16 had a user-shaped cam (not 24shown) which would convert the pressure signal to a 25temperature signal corresponding to the saturation tboiling) 26curve for water. The generator output was sent as a remote 27set-point signal to temperature controller 17 via a biasing 28regulator l~. The controller 17 controlled production rate 2gby a valve 19. The regulator 1~ subtracted a constant value ~3~3~2~7 1 to the temperature set-point to ensure that the production 2 rate was controlled to yield a production stream having a 3 temperature at about 10 - 40C below saturated steam temperature. The production control system A thus was adapted to automatically maintain the drawdown re~uired to 6 meet the condition that the production stream leave the well
7 at a temperature just below the temperature of saturated
8 steam at the conditions involved.
9 An improved production control system B was used on o the other two producer wells AP2 and AP3. In this version, 11 the pressure transmitter 15 and function generator 16 were 12 replaced with a vapour pressure transmitter 20. The vapour 13 pressure transmitter 20 was in contact with the production 14 stream and adapted to produce signals indicative of the vapour pressure of water at the line temperature. These 16 signals were supplied as a set-point to a pressure controller 17 21 ~ia a biasing regulator 22. In this case, the regulator 18 was adapted to control production rate, via the controller 21 19 and a valve 23, at 250 - 1000 kPa above saturation pressure.
A steam generator and separator 30 was provided at 21 ground surface for supplying essentially 100% quality steam 22 through suitable conduits to the tunnel. A second separator 23 (not shown) in the tunnel removed condensate and supplied dry 24 steam to the wells.
In the initial communication development phase, 26 steam was circulated through each of the producer wells 3 and 27 injector wells 4. The steam was introduced through the 28 tubing 9 and removed from the annulus 41. It was circulated 29 at a varying rate, to maintain a substantially constant 4~ 7 1 pressure. In the case of the upper injector wells 4, the 2 pressure was maintained at about 2800 kPa, which was less 3 than the fracture pressure for the reservoir, estimated to be about 3,000 kPa. In the case of the lower producer wells 3, the pressure was maintained at about 2450 XPa. The 6 production rate of aZl of the wells was controlled, to 7 maintain tAe temperature of the effluent about 10 - 40C
8 below the saturated steam temperature. ~his operation was g continued until steam breakthrough between a pair of wells 1~ was experienced.
11 Once breakthrough was established, the production 12 phase was initiated. This inrolved terminating production 13 from and commencing injection to the annulus and tubing of 14 the injector wells, terminating steam circulation in the producer wells, switching production to the tubing, and 16 continuing to control the production from the producer wells 17 in the same manner as was practiced in the communication 18 development phase.
19 ExamPle The results of the pilot operation of a pair o~
21 wells ~one an upper injector and the other a lower producer) 22 is now provided, in conjunction with Figure 7. The 23 chronology of events was:
24 Aug. 88: Circulation was commenced in both wells and continued for 3 weeks.
26 Sept. 88: Due to external circumstances, both wells 27 were shut in for the month, interrupting ~3~ 37 1 the communication phase. Significant 2 heat remained in the formaiion, however.
3 oct. 88: Circulation was resumed on the 10th and 4 continued for the last 20 days of the month. Annulus pressures in AI2 and AP2 6 were about 2 800 an d 2500 kPa, 7 respectively.
8 Nov. 88: Circulation was continued at the g beginning of the month, as in October.
Strong bitumen shows were observed in the 11 : circulation returns on the 5th through 12 the 7th, indicating communication. On 13 the 11th, circulation was discontinued 14 and AIZ was placed on injection and AP2 on production. Production and injection 16 rates increased thereafter, with water 17 and bltumen production growin g ~8 commensurate to steam injection.
19As of June, 1989, the first well pair to be 20operated had recovered in excess of ~0% of the original oil 21in place (OOlP) at a cumulative steam oil ratio of less than 223.0 (based on 95% quality steam). Recovery for all three 23well pairs in the test exaeeded 30~ OOlP at approximately the 24same cumulative SO~, and was expected to exceed ~0% in less 25than two years o~ further operation. All production wells 26flow to surface without pumping and produce essentially no 27sand.
~28To compare these results with other thermal 29recovery processes in the Athabasca oil sands, no test that ~ 3~ 7 1 we know of has exceeded 20% recovery nor achieved a steam oil 2 ratio of less than 5Ø Indeed, mOrQ typical values would be 3 less than 15% recovery and a steam oil ratio greater than 4 7Ø
A steam generator and separator 30 was provided at 21 ground surface for supplying essentially 100% quality steam 22 through suitable conduits to the tunnel. A second separator 23 (not shown) in the tunnel removed condensate and supplied dry 24 steam to the wells.
In the initial communication development phase, 26 steam was circulated through each of the producer wells 3 and 27 injector wells 4. The steam was introduced through the 28 tubing 9 and removed from the annulus 41. It was circulated 29 at a varying rate, to maintain a substantially constant 4~ 7 1 pressure. In the case of the upper injector wells 4, the 2 pressure was maintained at about 2800 kPa, which was less 3 than the fracture pressure for the reservoir, estimated to be about 3,000 kPa. In the case of the lower producer wells 3, the pressure was maintained at about 2450 XPa. The 6 production rate of aZl of the wells was controlled, to 7 maintain tAe temperature of the effluent about 10 - 40C
8 below the saturated steam temperature. ~his operation was g continued until steam breakthrough between a pair of wells 1~ was experienced.
11 Once breakthrough was established, the production 12 phase was initiated. This inrolved terminating production 13 from and commencing injection to the annulus and tubing of 14 the injector wells, terminating steam circulation in the producer wells, switching production to the tubing, and 16 continuing to control the production from the producer wells 17 in the same manner as was practiced in the communication 18 development phase.
19 ExamPle The results of the pilot operation of a pair o~
21 wells ~one an upper injector and the other a lower producer) 22 is now provided, in conjunction with Figure 7. The 23 chronology of events was:
24 Aug. 88: Circulation was commenced in both wells and continued for 3 weeks.
26 Sept. 88: Due to external circumstances, both wells 27 were shut in for the month, interrupting ~3~ 37 1 the communication phase. Significant 2 heat remained in the formaiion, however.
3 oct. 88: Circulation was resumed on the 10th and 4 continued for the last 20 days of the month. Annulus pressures in AI2 and AP2 6 were about 2 800 an d 2500 kPa, 7 respectively.
8 Nov. 88: Circulation was continued at the g beginning of the month, as in October.
Strong bitumen shows were observed in the 11 : circulation returns on the 5th through 12 the 7th, indicating communication. On 13 the 11th, circulation was discontinued 14 and AIZ was placed on injection and AP2 on production. Production and injection 16 rates increased thereafter, with water 17 and bltumen production growin g ~8 commensurate to steam injection.
19As of June, 1989, the first well pair to be 20operated had recovered in excess of ~0% of the original oil 21in place (OOlP) at a cumulative steam oil ratio of less than 223.0 (based on 95% quality steam). Recovery for all three 23well pairs in the test exaeeded 30~ OOlP at approximately the 24same cumulative SO~, and was expected to exceed ~0% in less 25than two years o~ further operation. All production wells 26flow to surface without pumping and produce essentially no 27sand.
~28To compare these results with other thermal 29recovery processes in the Athabasca oil sands, no test that ~ 3~ 7 1 we know of has exceeded 20% recovery nor achieved a steam oil 2 ratio of less than 5Ø Indeed, mOrQ typical values would be 3 less than 15% recovery and a steam oil ratio greater than 4 7Ø
Claims (4)
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A thermal method for recovering heavy oil from a reservoir in which the oil is substantially immobile, comprising:
(a) providing a pair of wells, each having a wellhead, which extend through the reservoir close to its base in vertically spaced apart and substantially horizontal, parallel and co-extensive arrangement, said wells being separated a distance within the range of about 3 to 8 meters, each well having a liner communicating with the reservoir and a string of tubing within the liner, said tubing extending through substantially the full length of the liner and combining therewith to form an annulus;
(b) heating by conduction the span of reservoir extending between the wells by simultaneously circulating steam in each of the wells at an elevated pressure that is less than fracture pressure, said circulation being accomplished by injecting steam through the tubing at a substantially constant pressure and producing effluent through the annulus, the rate of production of effluent being controlled to maintain its temperature just below saturated steam until fluid transmissibility is established between the wells;
(c) then injecting steam into the reservoir through the upper well at a substantially constant elevated pressure that is less than fracture pressure, at least part of the steam being injected through the tubing, while simultaneously producing substantially steam-free fluid through the tubing of the lower well, the rate of production from the lower well being throttled to maintain the temperature and pressure of the produced fluid just below saturated steam conditions.
(a) providing a pair of wells, each having a wellhead, which extend through the reservoir close to its base in vertically spaced apart and substantially horizontal, parallel and co-extensive arrangement, said wells being separated a distance within the range of about 3 to 8 meters, each well having a liner communicating with the reservoir and a string of tubing within the liner, said tubing extending through substantially the full length of the liner and combining therewith to form an annulus;
(b) heating by conduction the span of reservoir extending between the wells by simultaneously circulating steam in each of the wells at an elevated pressure that is less than fracture pressure, said circulation being accomplished by injecting steam through the tubing at a substantially constant pressure and producing effluent through the annulus, the rate of production of effluent being controlled to maintain its temperature just below saturated steam until fluid transmissibility is established between the wells;
(c) then injecting steam into the reservoir through the upper well at a substantially constant elevated pressure that is less than fracture pressure, at least part of the steam being injected through the tubing, while simultaneously producing substantially steam-free fluid through the tubing of the lower well, the rate of production from the lower well being throttled to maintain the temperature and pressure of the produced fluid just below saturated steam conditions.
2. The method as set forth in claim 1 comprising:
during step (b), monitoring at each wellhead the temperature and pressure of the effluent and controlling the rate of circulation from each well in response to said temperature and pressure to maintain the temperature of the effluent just below saturated steam temperature; and during step (c), monitoring at the wellhead the temperature and pressure of the production fluid from the lower well and throttling the rate of production from said well in response to said temperature and pressure to maintain the temperature of the fluid just below saturated steam temperature.
during step (b), monitoring at each wellhead the temperature and pressure of the effluent and controlling the rate of circulation from each well in response to said temperature and pressure to maintain the temperature of the effluent just below saturated steam temperature; and during step (c), monitoring at the wellhead the temperature and pressure of the production fluid from the lower well and throttling the rate of production from said well in response to said temperature and pressure to maintain the temperature of the fluid just below saturated steam temperature.
3. The method as set forth in claims 1 or 2 comprising:
injecting steam in step (c) through both the tubing and annulus of the upper well.
injecting steam in step (c) through both the tubing and annulus of the upper well.
4. The method as set forth in claims 1 or 2 comprising;
maintaining the pressure of circulation at the lower well less than that at the upper well so that a pressure differential is maintained between the wells during step (b); and injecting steam in step (c) through both the tubing and annulus of the upper well.
maintaining the pressure of circulation at the lower well less than that at the upper well so that a pressure differential is maintained between the wells during step (b); and injecting steam in step (c) through both the tubing and annulus of the upper well.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000604268A CA1304287C (en) | 1989-06-28 | 1989-06-28 | Steaming process, involving a pair of horizontal wells, for use in heavy oil reservoir |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA000604268A CA1304287C (en) | 1989-06-28 | 1989-06-28 | Steaming process, involving a pair of horizontal wells, for use in heavy oil reservoir |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1304287C true CA1304287C (en) | 1992-06-30 |
Family
ID=4140270
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000604268A Expired - Lifetime CA1304287C (en) | 1989-06-28 | 1989-06-28 | Steaming process, involving a pair of horizontal wells, for use in heavy oil reservoir |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA1304287C (en) |
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