CA2169808C - Single horizontal wellbore process for the in-situ extraction of viscous oil by steam stimulation - Google Patents
Single horizontal wellbore process for the in-situ extraction of viscous oil by steam stimulation Download PDFInfo
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- CA2169808C CA2169808C CA 2169808 CA2169808A CA2169808C CA 2169808 C CA2169808 C CA 2169808C CA 2169808 CA2169808 CA 2169808 CA 2169808 A CA2169808 A CA 2169808A CA 2169808 C CA2169808 C CA 2169808C
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- steam
- wellbore
- formation
- horizontal wellbore
- horizontal
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- 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
Disclosed is a method for recovering highly viscous oil from a formation penetrated by a single horizontal wellbore using steam stimulation. A wellbore is drilled into the formation comprising a substantially vertical section and a substantially horizontal section. The vertical section of the wellbore is completed with a casing and a production tubing that extends from the surface to the beginning of the horizontal wellbore. The horizontal section of the wellbore is completed with a slotted lined and the entire wellbore is completed with an injection tubing that extends from the surface to the far end of the horizontal wellbore. After the wellbore is completed, steam is circulated in and out the horizontal wellbore at a pressure below the formation's fracture pressure to heat the formation surrounding the horizontal wellbore by transient conduction and steam-lift fluids from the horizontal wellbore. Circulation of the steam is continued until the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure. Thereafter, a slug of steam is injected into the horizontal wellbore below fracture pressure followed by a short soak period. The well is then flowed back until the amount of produced fluids substantially decline. Steam circulation is resumed and steam-lifted fluids including oil are recovered until the oil recovery is unfavorable.
The sequence of steam slug injection, soak period, flow back and steam circulation is repeated for a plurality of cycles until the rate of oil is then favorable.
The sequence of steam slug injection, soak period, flow back and steam circulation is repeated for a plurality of cycles until the rate of oil is then favorable.
Description
~ Docket No. 7817 21 69~08 SINGLE HORIZONTAL WELLBORE PROCESS FOR THE IN-SITU
EXTRACTION OF VISCOUS OIL BY STEAM STIMULATION
FIELD OF THE Ihv~llON
This invention relates to a process for the recovery of highly viscous oil or hydrocarbonaceous fluids from subterranean oil reservoirs. Specifically, the invention relates to recovering highly viscous oil using steam stimulation in a single horizontal well.
BACKGROUND OF THE INVENTION
World energy supplies are substantially impacted by the world's heavy oil resources. Indeed, heavy oil comprises 2,100 billion barrels of the world's total oil reserves. Processes for the economic recovery of these viscous reserves are clearly important.
Asphalt, tar, and heavy oil are typically deposited near the surface with overburden depths that span a few feet to a few thousands of feet. In Canada, vast deposits of heavy oil are found in the A~hAh~cca, Cold Lake, Celtic, Lloydminster and McMurray reservoirs. In California, heavy oil is found in the South Belridge, Midway Sunset, Kern River and other reservoirs.
In large Athabasca and Cold Lake bitumen deposits oil is essentially immobile - unable to flow under normal natural drive primary recovery mechanisms. Furthermore, oil saturations in these formations are typically large.
This limits the injectivity of a fluid (heated or cold) into the formation. Moreover, many of these deposits are too deep below the surface to be mined effectively and economically.
In-situ teçhniques of recovering viscous oil and bitumen have been the subject of much previous investigation. These techniques can be split into three categories: 1) cyclic processes involving injecting and producing a viscosity reducing agent; 2) continuous ' Docket No. 7817 21 69~08 steaming processes which involve injecting a heated fluid ~ at one well and displacing oil to another set of wells; and 3) the relatively new Steam (or Solvent) Assisted Gravity Drainage process.
Each of these techniques have large limitations if economic application to the very viscous AthAhAsca or Cold Lake reservoirs is desired.
Cyclic steam or solvent stimulation in these two reservoirs are severely hampered by the lack of any significant steam injectivity into the respective formations. Hence, in the case of vertical wells a formation fracture is required to obtain any significant injectivity into the formation. Some success with a fracturing technique has been obtained in the Cold Lake reservoir at locations not having any significant underlying water aquifer. However, if a water aquifer exists beneath the vertical well located in the oil bearing formation, fracturing during steam injection results in early and large water influx during the production phase.
Also with fracturing it is very difficult to confine steam where it is desired. This substantially lowers the economic performance of wells. In addition, cyclic steaming techniques are not continuous in nature thereby reducing the economic viability of the process. Clearly, steam stimulation techniques in Cold Lake and AthAhAsca are severely limited.
Vertical well continuous steaming processes are not technically or economically feasible in the very viscous bitumen reservoirs. Oil mobility is simply far too small to be produced from a cold production well as is done in California type of reservoirs. Steam injection from one well and production from a remote production well is not possible unless a formation fracture is again formed.
Formation fractures between wells are very difficult to control and there are operational problems Assoçiated with fracturing in such a controlled manner as to intersect an entire pattern of wells. Hence, classical steam flooding, even in the presence of initial fluid injectivity Docket No. 7817 2 i 69808 artificially induced by a fracture has significant limitations.
Steam Assisted Gravity Drainage (SAGD) is disclosed in U.S. Patent 4,344,485 which issued to Butler in 1982. SAGD
uses a pair of horizontal wells connected by a vertical fracture. The process has several advantages to steam stimulation or continuous steam injection. One advantage is that initial steam injectivity is not needed as steam rises by gravity above the upper well thereby replacing oil produced at the lower well. Another advantage is that since the process is gravity dominated and steam replaces voided oil, good sweep efficiency is obtained. Yet another advantage is since horizontal wells are utilized, good oil rates may be obtained by simply extending the length of the well to contact more of the oil bearing formation. In the SAGD process, steam is injected in the upper horizontal well while oil and water are produced at the lower horizontal well. Steam production from the lower well is controlled so that the entire process remains in the gravity dominated regime. A steam chamber rises above the upper well and oil warmed by conduction drains along the outside of the chamber to the lower production well. The process has the advantages of high oil rates and good overall recovery. It can be used in the absence of a vertical fracture.
However, one serious limitation of this process in practical application is the need to have two parallel horizontal wells - one beneath the other. Those skilled in the art of drilling horizontal wells will immediately recognize the difficulty in drilling two parallel horizontal wells, one above the other, in thin formation with any real accuracy for any real horizontal distance from the surface.
U.S. Pat. Nos. 4,116,275, Butler et al; 5,148,869, Sanchez and 5,215,149, Lu discloses steam stimulation processes for recovering heavy oil using a single horizontal well bore.
~1 6~08 Docket No. 7817 SUMMARY OF THE Ihv~ ON
In accordance with the present invention, highly viscous oil is recovered from a subterranean formation using a single horizontal wellbore subjected to steam stimulation. First, a wellbore is drilled to penetrate the formation comprising a substantially vertical section and a substantially horizontal section. The vertical section of the wellbore is cased and the horizontal section of the wellbore is completed with a slotted liner. The wellbore is completed with an injection tubing that extends from the surface to the far end of the horizontal wellbore and a production tubing that extends from the surface to the beginning of the horizontal wellbore. After the wellbore is suitably completed, steam is continuously circulated in lS and out of the horizontal wellbore at a pressure below the formation's fracture pressure thereby conduction heating the formation surrounding the horizontal wellbore to reduce the viscosity of the viscous oil. This step is continued until the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure. Thereafter, a slug of steam is injected into the horizontal wellbore at a pressure below the formation's fracture pressure. Thereafter, the formation is allowed to soak for a short period, preferably 1 to 7 days. After the soak period, the well is then flowed back until the production of fluids including oil substantially declines.
Thereafter, steam circulation in and out the horizontal wellbore is resumed at a pressure below the formation's fracture pressure thereby heating the formation surrounding the horizontal wellbore by conduction and convective heat to reduce the viscosity of the viscous oil and steam-lifting fluids including oil from the horizontal wellbore.
Steam circulation is continued until oil recovery is unfavorable. The sequence of injecting a slug of steam, soak period, flow back and steam circulation are repeated for a plurality of cycles until the rate of oil recovery is unfavorable. As the cycle number increases, the size of each succe~cive steam slug and cycle lengths also Docket No. 7817 21 69~08 increases. During later cycle oil production rates may be increAce~ by pumping the fluids from the well via the production tubing instead of using steam circulation to lift the fluids.
The present process enables the use of standard drilling equipment and is more efficient in heating the reservoir, thus increasing oil recovery because it makes use of convective heating in addition to conduction heating of the reservoir. Convective heating enhances the heating of the reservoir 4 to 6 times, thus increasing oil recovery.
BRIEF DESCRIPTION OF THE DRAWINGS
The drawing is a schematic longitudinal sectional view of a horizontal well utilized in carrying out the process of the invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
This invention is directed to a method for removing immobile or highly viscous oil from a formation or reservoir which formation is penetrated by a horizontal wellbore using steam stimulation. Referring to the drawing, the drawing illustrates a subterranean formation or reservoir 10 which contains highly viscous oil below the earth's surface 12, beneath an overburden 14. A wellbore 16 having a substantial vertical section 18 and a substantially horizontal section 20 has been drilled to penetrate the formation 10 and to extend therethrough. The wellbore 16 is subsequently cased down to the beginning of the horizontal wellbore 20. The entire length of the horizontal wellbore section 20 section is lined and the liner 22 has slots 24 over its entire surface. The horizontal wellbore 20 and surrounding formation are in fluid communication through slots 24. An injection tubing 26 is run inside the wellbore 16 from the surface to the far end of the slotted liner 22. The injection tubing 26 is insulated to ensure that the quality of injected steam exiting at the end of the tubing is as high as possible. A
production tubing 28 is run between the wellbore 16 and the injection tubing 26 from the surface to the lower end of 21 S9~08 Docket No. 7817 the vertical section 18 of the wellbore. The annular space 30 between the vertical wellbore casing and the injection/production tubings may be filled with an inert gas, preferably nitrogen. The nitrogen blanket serves three major purposes: (1) reducing heat losses to the over-burden for better thermal efficiency and for casing protection, (2) initiating steam-lift production mechanism after flow-back, and (3) providing a direct measurement of downhole pressure. Gauges may be used to monitor bottomhole temperature and pressure directly.
Initially, after the well has been completed the formation surrounding the horizontal wellbore is conditioned by continuously circulating steam in and out of the horizontal wellbore at a pressure below the formation's fracture pressure for a time sufficient to heat the formation surrounding the horizontal wellbore by transient conduction. It is important not to fracture the formation because then it would be very difficult to confine the steam around the horizontal wellbore. Steam injection pressure during this first step can be controlled at the surface by adjusting chokes positioned in injection tubing 26. The steam is injected into tubing 26 at a pressure so that the pressure of the steam in the horizontal wellbore 20 does not exceed the formation's fracture pressure.
While circulating steam, the bottomhole flow pressure is controlled at the surface by adjusting steam circulation rate and the choke settings in the production tubing 28.
The steam circulates down the tubing 26 to the far end of the slotted liner 22 and back toward the heal of the horizontal wellbore through the annular space 32 between injection tubing 26 and the slotted liner and then up to the surface via production tubing 28. Therefore, initially the steam just circulates in and out of the horizontal wellbore 20 and heats the area surrounding the horizontal wellbore by transient conduction since penetration of the steam into the formation 10 at these early stages is almost nil. As the formation 10 around the horizontal wellbore 20 heats up the viscous oil becomes reduced in viscosity and Docket No. 7817 drains into the horizontal wellbore through slots 24 in the liner 22 creating some voidage in the formation. The drainage of formation fluids (oil and water) is gravity dominated. The creation of voidages in the formation 10 allows subsequent injection of steam slugs into the formation that results in convective heating of the formation in addition to conductive heating. Convective heat transfer increases effective thermal conductivity by 4 to 6 times. The conditioning of the formation around the horizontal wellbore 20 is complete when the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure. This may also be indicated by a substantial amount of oil in the produced fluids. Conditioning of the horizontal wellbore 20 is usually complete after a period of 1 to 7 days depending upon the injection and production pressure and steam circulation rate. After the formation surrounding the horizontal wellbore 20 has been suitably conditioned, a slug of steam is injected into the horizontal wellbore 20 below fracture pressure followed by a short soak period of 1 to 7 days. After the soak period, the well is flowed back until the produced fluids substantially decline.
Thereafter steam circulation in and out the horizontal wellbore is resumed at a pressure below the formation's fracture pressure and fluids including oil are steam lifted from the horizontal wellbore to the surface via production tubing 28. Although steam circulation continues to heat the formation 10 surrounding the horizontal wellbore 20 it is not normally enough to expand the heated volume around the horizontal wellbore and oil production eventually declines or ceases to flow. Steam circulation is continued until the rate of oil recovery in the steam-lifted produced fluids is unfavorable. The above sequence of injecting a slug of steam followed by a soak period, flow back and steam circulation is repeated for a plurality of cycles until the rate of oil recovery is unfavorable. As the cycle number increases, the size of each sU~Ccive steam slug and cycle lengths also increase. The size of each Docket No. 7817 successive steam slug and the cycle length will depend upon the characterization of the formation. Entering of steam into the reservoir and the drainage of reservoir fluids (oil and water) is gravity dominated. Also, although steam is injected below fracture pressure, some degree of local failure of sand in shear (dilation) takes place and is advantageous to the process as it facilitates the entering of steam into the formation, thus resulting in convective heating. Further, on a cyclic basis, the cold water equivalent of total injected fluids equals the total produced fluids. It is preferred that the steam quality be as high as possible to provide more heat to the formation and thereby increase oil production. Preferably the steam quality is at least 80% quality.
In another variation of the process, during later cycles oil production rates may be increased by pumping the fluids from the well rather than using steam circulation to lift the fluids. The pump is located in the lower end of the production tubing 28. In addition, the production of fluids are regulated to minimize steam production. In still another variation of the process, it is also possible that under some reservoir conditions and with different levels of injection pressures, the cyclic phase of the process can be avoided, thus resulting in a process of continuous steam injection and oil production. In this embodiment steam is continuously injected in and out the formation to heat the formation and lift the fluids until the rate of oil recovery is unfavorable.
EXTRACTION OF VISCOUS OIL BY STEAM STIMULATION
FIELD OF THE Ihv~llON
This invention relates to a process for the recovery of highly viscous oil or hydrocarbonaceous fluids from subterranean oil reservoirs. Specifically, the invention relates to recovering highly viscous oil using steam stimulation in a single horizontal well.
BACKGROUND OF THE INVENTION
World energy supplies are substantially impacted by the world's heavy oil resources. Indeed, heavy oil comprises 2,100 billion barrels of the world's total oil reserves. Processes for the economic recovery of these viscous reserves are clearly important.
Asphalt, tar, and heavy oil are typically deposited near the surface with overburden depths that span a few feet to a few thousands of feet. In Canada, vast deposits of heavy oil are found in the A~hAh~cca, Cold Lake, Celtic, Lloydminster and McMurray reservoirs. In California, heavy oil is found in the South Belridge, Midway Sunset, Kern River and other reservoirs.
In large Athabasca and Cold Lake bitumen deposits oil is essentially immobile - unable to flow under normal natural drive primary recovery mechanisms. Furthermore, oil saturations in these formations are typically large.
This limits the injectivity of a fluid (heated or cold) into the formation. Moreover, many of these deposits are too deep below the surface to be mined effectively and economically.
In-situ teçhniques of recovering viscous oil and bitumen have been the subject of much previous investigation. These techniques can be split into three categories: 1) cyclic processes involving injecting and producing a viscosity reducing agent; 2) continuous ' Docket No. 7817 21 69~08 steaming processes which involve injecting a heated fluid ~ at one well and displacing oil to another set of wells; and 3) the relatively new Steam (or Solvent) Assisted Gravity Drainage process.
Each of these techniques have large limitations if economic application to the very viscous AthAhAsca or Cold Lake reservoirs is desired.
Cyclic steam or solvent stimulation in these two reservoirs are severely hampered by the lack of any significant steam injectivity into the respective formations. Hence, in the case of vertical wells a formation fracture is required to obtain any significant injectivity into the formation. Some success with a fracturing technique has been obtained in the Cold Lake reservoir at locations not having any significant underlying water aquifer. However, if a water aquifer exists beneath the vertical well located in the oil bearing formation, fracturing during steam injection results in early and large water influx during the production phase.
Also with fracturing it is very difficult to confine steam where it is desired. This substantially lowers the economic performance of wells. In addition, cyclic steaming techniques are not continuous in nature thereby reducing the economic viability of the process. Clearly, steam stimulation techniques in Cold Lake and AthAhAsca are severely limited.
Vertical well continuous steaming processes are not technically or economically feasible in the very viscous bitumen reservoirs. Oil mobility is simply far too small to be produced from a cold production well as is done in California type of reservoirs. Steam injection from one well and production from a remote production well is not possible unless a formation fracture is again formed.
Formation fractures between wells are very difficult to control and there are operational problems Assoçiated with fracturing in such a controlled manner as to intersect an entire pattern of wells. Hence, classical steam flooding, even in the presence of initial fluid injectivity Docket No. 7817 2 i 69808 artificially induced by a fracture has significant limitations.
Steam Assisted Gravity Drainage (SAGD) is disclosed in U.S. Patent 4,344,485 which issued to Butler in 1982. SAGD
uses a pair of horizontal wells connected by a vertical fracture. The process has several advantages to steam stimulation or continuous steam injection. One advantage is that initial steam injectivity is not needed as steam rises by gravity above the upper well thereby replacing oil produced at the lower well. Another advantage is that since the process is gravity dominated and steam replaces voided oil, good sweep efficiency is obtained. Yet another advantage is since horizontal wells are utilized, good oil rates may be obtained by simply extending the length of the well to contact more of the oil bearing formation. In the SAGD process, steam is injected in the upper horizontal well while oil and water are produced at the lower horizontal well. Steam production from the lower well is controlled so that the entire process remains in the gravity dominated regime. A steam chamber rises above the upper well and oil warmed by conduction drains along the outside of the chamber to the lower production well. The process has the advantages of high oil rates and good overall recovery. It can be used in the absence of a vertical fracture.
However, one serious limitation of this process in practical application is the need to have two parallel horizontal wells - one beneath the other. Those skilled in the art of drilling horizontal wells will immediately recognize the difficulty in drilling two parallel horizontal wells, one above the other, in thin formation with any real accuracy for any real horizontal distance from the surface.
U.S. Pat. Nos. 4,116,275, Butler et al; 5,148,869, Sanchez and 5,215,149, Lu discloses steam stimulation processes for recovering heavy oil using a single horizontal well bore.
~1 6~08 Docket No. 7817 SUMMARY OF THE Ihv~ ON
In accordance with the present invention, highly viscous oil is recovered from a subterranean formation using a single horizontal wellbore subjected to steam stimulation. First, a wellbore is drilled to penetrate the formation comprising a substantially vertical section and a substantially horizontal section. The vertical section of the wellbore is cased and the horizontal section of the wellbore is completed with a slotted liner. The wellbore is completed with an injection tubing that extends from the surface to the far end of the horizontal wellbore and a production tubing that extends from the surface to the beginning of the horizontal wellbore. After the wellbore is suitably completed, steam is continuously circulated in lS and out of the horizontal wellbore at a pressure below the formation's fracture pressure thereby conduction heating the formation surrounding the horizontal wellbore to reduce the viscosity of the viscous oil. This step is continued until the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure. Thereafter, a slug of steam is injected into the horizontal wellbore at a pressure below the formation's fracture pressure. Thereafter, the formation is allowed to soak for a short period, preferably 1 to 7 days. After the soak period, the well is then flowed back until the production of fluids including oil substantially declines.
Thereafter, steam circulation in and out the horizontal wellbore is resumed at a pressure below the formation's fracture pressure thereby heating the formation surrounding the horizontal wellbore by conduction and convective heat to reduce the viscosity of the viscous oil and steam-lifting fluids including oil from the horizontal wellbore.
Steam circulation is continued until oil recovery is unfavorable. The sequence of injecting a slug of steam, soak period, flow back and steam circulation are repeated for a plurality of cycles until the rate of oil recovery is unfavorable. As the cycle number increases, the size of each succe~cive steam slug and cycle lengths also Docket No. 7817 21 69~08 increases. During later cycle oil production rates may be increAce~ by pumping the fluids from the well via the production tubing instead of using steam circulation to lift the fluids.
The present process enables the use of standard drilling equipment and is more efficient in heating the reservoir, thus increasing oil recovery because it makes use of convective heating in addition to conduction heating of the reservoir. Convective heating enhances the heating of the reservoir 4 to 6 times, thus increasing oil recovery.
BRIEF DESCRIPTION OF THE DRAWINGS
The drawing is a schematic longitudinal sectional view of a horizontal well utilized in carrying out the process of the invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
This invention is directed to a method for removing immobile or highly viscous oil from a formation or reservoir which formation is penetrated by a horizontal wellbore using steam stimulation. Referring to the drawing, the drawing illustrates a subterranean formation or reservoir 10 which contains highly viscous oil below the earth's surface 12, beneath an overburden 14. A wellbore 16 having a substantial vertical section 18 and a substantially horizontal section 20 has been drilled to penetrate the formation 10 and to extend therethrough. The wellbore 16 is subsequently cased down to the beginning of the horizontal wellbore 20. The entire length of the horizontal wellbore section 20 section is lined and the liner 22 has slots 24 over its entire surface. The horizontal wellbore 20 and surrounding formation are in fluid communication through slots 24. An injection tubing 26 is run inside the wellbore 16 from the surface to the far end of the slotted liner 22. The injection tubing 26 is insulated to ensure that the quality of injected steam exiting at the end of the tubing is as high as possible. A
production tubing 28 is run between the wellbore 16 and the injection tubing 26 from the surface to the lower end of 21 S9~08 Docket No. 7817 the vertical section 18 of the wellbore. The annular space 30 between the vertical wellbore casing and the injection/production tubings may be filled with an inert gas, preferably nitrogen. The nitrogen blanket serves three major purposes: (1) reducing heat losses to the over-burden for better thermal efficiency and for casing protection, (2) initiating steam-lift production mechanism after flow-back, and (3) providing a direct measurement of downhole pressure. Gauges may be used to monitor bottomhole temperature and pressure directly.
Initially, after the well has been completed the formation surrounding the horizontal wellbore is conditioned by continuously circulating steam in and out of the horizontal wellbore at a pressure below the formation's fracture pressure for a time sufficient to heat the formation surrounding the horizontal wellbore by transient conduction. It is important not to fracture the formation because then it would be very difficult to confine the steam around the horizontal wellbore. Steam injection pressure during this first step can be controlled at the surface by adjusting chokes positioned in injection tubing 26. The steam is injected into tubing 26 at a pressure so that the pressure of the steam in the horizontal wellbore 20 does not exceed the formation's fracture pressure.
While circulating steam, the bottomhole flow pressure is controlled at the surface by adjusting steam circulation rate and the choke settings in the production tubing 28.
The steam circulates down the tubing 26 to the far end of the slotted liner 22 and back toward the heal of the horizontal wellbore through the annular space 32 between injection tubing 26 and the slotted liner and then up to the surface via production tubing 28. Therefore, initially the steam just circulates in and out of the horizontal wellbore 20 and heats the area surrounding the horizontal wellbore by transient conduction since penetration of the steam into the formation 10 at these early stages is almost nil. As the formation 10 around the horizontal wellbore 20 heats up the viscous oil becomes reduced in viscosity and Docket No. 7817 drains into the horizontal wellbore through slots 24 in the liner 22 creating some voidage in the formation. The drainage of formation fluids (oil and water) is gravity dominated. The creation of voidages in the formation 10 allows subsequent injection of steam slugs into the formation that results in convective heating of the formation in addition to conductive heating. Convective heat transfer increases effective thermal conductivity by 4 to 6 times. The conditioning of the formation around the horizontal wellbore 20 is complete when the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure. This may also be indicated by a substantial amount of oil in the produced fluids. Conditioning of the horizontal wellbore 20 is usually complete after a period of 1 to 7 days depending upon the injection and production pressure and steam circulation rate. After the formation surrounding the horizontal wellbore 20 has been suitably conditioned, a slug of steam is injected into the horizontal wellbore 20 below fracture pressure followed by a short soak period of 1 to 7 days. After the soak period, the well is flowed back until the produced fluids substantially decline.
Thereafter steam circulation in and out the horizontal wellbore is resumed at a pressure below the formation's fracture pressure and fluids including oil are steam lifted from the horizontal wellbore to the surface via production tubing 28. Although steam circulation continues to heat the formation 10 surrounding the horizontal wellbore 20 it is not normally enough to expand the heated volume around the horizontal wellbore and oil production eventually declines or ceases to flow. Steam circulation is continued until the rate of oil recovery in the steam-lifted produced fluids is unfavorable. The above sequence of injecting a slug of steam followed by a soak period, flow back and steam circulation is repeated for a plurality of cycles until the rate of oil recovery is unfavorable. As the cycle number increases, the size of each sU~Ccive steam slug and cycle lengths also increase. The size of each Docket No. 7817 successive steam slug and the cycle length will depend upon the characterization of the formation. Entering of steam into the reservoir and the drainage of reservoir fluids (oil and water) is gravity dominated. Also, although steam is injected below fracture pressure, some degree of local failure of sand in shear (dilation) takes place and is advantageous to the process as it facilitates the entering of steam into the formation, thus resulting in convective heating. Further, on a cyclic basis, the cold water equivalent of total injected fluids equals the total produced fluids. It is preferred that the steam quality be as high as possible to provide more heat to the formation and thereby increase oil production. Preferably the steam quality is at least 80% quality.
In another variation of the process, during later cycles oil production rates may be increased by pumping the fluids from the well rather than using steam circulation to lift the fluids. The pump is located in the lower end of the production tubing 28. In addition, the production of fluids are regulated to minimize steam production. In still another variation of the process, it is also possible that under some reservoir conditions and with different levels of injection pressures, the cyclic phase of the process can be avoided, thus resulting in a process of continuous steam injection and oil production. In this embodiment steam is continuously injected in and out the formation to heat the formation and lift the fluids until the rate of oil recovery is unfavorable.
Claims (8)
1. A method for recovering viscous oil from a subterranean formation or reservoir containing fluids including viscous oil comprising;
(a) drilling a wellbore into said formation comprising a substantially vertical section and a substantially horizontal section:
(b) completing the vertical section of the wellbore with a casing and a production tubing that extends from the surface to the beginning of the horizontal wellbore and completing the horizontal section of the wellbore with a slotted liner to provide fluid communication between the formation and the horizontal wellbore and completing the entire wellbore with an injection tubing that extends from the surface to the far end of the horizontal wellbore;
(c) circulating steam continuously in and out of the horizontal wellbore that flows down the injection tubing to the end of the horizontal wellbore, back through the annular space between the injection tubing and the slotted liner at a pressure below the formation's fracture pressure and exiting through the production tubing to the surface so as to substantially avoid steam entry into the formation except by gravitional forces, thereby heating the formation surrounding the horizontal wellbore by conduction heating to reduce the viscosity of the viscous oil and steam-lift fluids including oil from the horizontal wellbore;
(d) injecting a slug of steam into the formation surrounding the horizontal wellbore through the injection tubing and the slotted liner below the formation's fracture pressure resulting in convective and conduction heating of the formation surrounding the horizontal wellbore to reduce the viscosity of the viscous oil;
(e) allowing the formation to soak for a period of time;
(f) flowing back the wellbore to produce fluids including oil from the formation until the production of fluids substantially declines;
(g) repeating step (c) and producing steam-lifted fluids including oil from the formation until the rate of oil recovery in unfavorable; and (h) repeating steps (d) through (g) for a plurality of cycles until the rate of oil recovery is unfavorable.
(a) drilling a wellbore into said formation comprising a substantially vertical section and a substantially horizontal section:
(b) completing the vertical section of the wellbore with a casing and a production tubing that extends from the surface to the beginning of the horizontal wellbore and completing the horizontal section of the wellbore with a slotted liner to provide fluid communication between the formation and the horizontal wellbore and completing the entire wellbore with an injection tubing that extends from the surface to the far end of the horizontal wellbore;
(c) circulating steam continuously in and out of the horizontal wellbore that flows down the injection tubing to the end of the horizontal wellbore, back through the annular space between the injection tubing and the slotted liner at a pressure below the formation's fracture pressure and exiting through the production tubing to the surface so as to substantially avoid steam entry into the formation except by gravitional forces, thereby heating the formation surrounding the horizontal wellbore by conduction heating to reduce the viscosity of the viscous oil and steam-lift fluids including oil from the horizontal wellbore;
(d) injecting a slug of steam into the formation surrounding the horizontal wellbore through the injection tubing and the slotted liner below the formation's fracture pressure resulting in convective and conduction heating of the formation surrounding the horizontal wellbore to reduce the viscosity of the viscous oil;
(e) allowing the formation to soak for a period of time;
(f) flowing back the wellbore to produce fluids including oil from the formation until the production of fluids substantially declines;
(g) repeating step (c) and producing steam-lifted fluids including oil from the formation until the rate of oil recovery in unfavorable; and (h) repeating steps (d) through (g) for a plurality of cycles until the rate of oil recovery is unfavorable.
2. A method as recited in claim 1 wherein the soak period in step (e) is for 1 to 7 days.
3. A method as recited in claim 1 wherein the annular space between the vertical section of the wellbore casing and the injection/production tubing is filled with nitrogen.
4. A method as recited in claim 1 wherein step (c) is continued until the temperature of the horizontal wellbore reaches the saturation temperature of steam at horizontal wellbore pressure.
5. A method as recited in claim 1 wherein step (c) is continued until oil appears in the produced fluids.
6. A method as recited in claim 1 wherein during later cycles the fluids including oil are pumped from the formation during step (g) instead of being steam-lifted.
7. A method as recited in claim 1 wherein the injection tubing is substantially insulated.
8. A method as recited in claim 1 wherein the steam is a quality of about 80%.
Priority Applications (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2169808 CA2169808C (en) | 1996-02-19 | 1996-02-19 | Single horizontal wellbore process for the in-situ extraction of viscous oil by steam stimulation |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA 2169808 CA2169808C (en) | 1996-02-19 | 1996-02-19 | Single horizontal wellbore process for the in-situ extraction of viscous oil by steam stimulation |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2169808A1 CA2169808A1 (en) | 1997-08-20 |
| CA2169808C true CA2169808C (en) | 2001-04-17 |
Family
ID=4157597
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA 2169808 Expired - Lifetime CA2169808C (en) | 1996-02-19 | 1996-02-19 | Single horizontal wellbore process for the in-situ extraction of viscous oil by steam stimulation |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2169808C (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10890057B2 (en) | 2015-07-28 | 2021-01-12 | NCS Multistage, LLC | Method for injecting fluid into a formation to produce oil |
Families Citing this family (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN112145163A (en) * | 2019-06-26 | 2020-12-29 | 中国石油化工股份有限公司 | Experimental device and experimental method for simulating staged fracturing horizontal well foam discharging process |
| CN113137219B (en) * | 2020-01-19 | 2022-10-04 | 中国石油天然气股份有限公司 | Method for developing natural gas hydrate by injecting air |
-
1996
- 1996-02-19 CA CA 2169808 patent/CA2169808C/en not_active Expired - Lifetime
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10890057B2 (en) | 2015-07-28 | 2021-01-12 | NCS Multistage, LLC | Method for injecting fluid into a formation to produce oil |
Also Published As
| Publication number | Publication date |
|---|---|
| CA2169808A1 (en) | 1997-08-20 |
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