CA2740941C - Process for solvent assisted in situ bitumen recovery startup - Google Patents
Process for solvent assisted in situ bitumen recovery startup Download PDFInfo
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- CA2740941C CA2740941C CA2740941A CA2740941A CA2740941C CA 2740941 C CA2740941 C CA 2740941C CA 2740941 A CA2740941 A CA 2740941A CA 2740941 A CA2740941 A CA 2740941A CA 2740941 C CA2740941 C CA 2740941C
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- 239000002904 solvent Substances 0.000 title claims abstract description 194
- 238000000034 method Methods 0.000 title claims abstract description 139
- 230000008569 process Effects 0.000 title claims abstract description 133
- 239000010426 asphalt Substances 0.000 title claims abstract description 79
- 238000011065 in-situ storage Methods 0.000 title claims abstract description 47
- 238000011084 recovery Methods 0.000 title claims abstract description 19
- 238000002347 injection Methods 0.000 claims abstract description 130
- 239000007924 injection Substances 0.000 claims abstract description 130
- 239000012530 fluid Substances 0.000 claims abstract description 120
- 238000004519 manufacturing process Methods 0.000 claims abstract description 96
- 238000010796 Steam-assisted gravity drainage Methods 0.000 claims abstract description 27
- 238000004891 communication Methods 0.000 claims abstract description 21
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 26
- YXFVVABEGXRONW-UHFFFAOYSA-N Toluene Chemical compound CC1=CC=CC=C1 YXFVVABEGXRONW-UHFFFAOYSA-N 0.000 claims description 12
- VLKZOEOYAKHREP-UHFFFAOYSA-N n-Hexane Chemical compound CCCCCC VLKZOEOYAKHREP-UHFFFAOYSA-N 0.000 claims description 12
- OFBQJSOFQDEBGM-UHFFFAOYSA-N n-pentane Natural products CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 claims description 12
- 230000008021 deposition Effects 0.000 claims description 9
- IMNFDUFMRHMDMM-UHFFFAOYSA-N N-Heptane Chemical compound CCCCCCC IMNFDUFMRHMDMM-UHFFFAOYSA-N 0.000 claims description 8
- 150000001335 aliphatic alkanes Chemical class 0.000 claims description 7
- 239000011877 solvent mixture Substances 0.000 claims description 6
- CTQNGGLPUBDAKN-UHFFFAOYSA-N O-Xylene Chemical compound CC1=CC=CC=C1C CTQNGGLPUBDAKN-UHFFFAOYSA-N 0.000 claims description 4
- 150000001491 aromatic compounds Chemical class 0.000 claims description 4
- 239000001273 butane Substances 0.000 claims description 4
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical compound CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 claims description 4
- 239000008096 xylene Substances 0.000 claims description 4
- -1 diesel Chemical compound 0.000 claims description 3
- 239000000203 mixture Substances 0.000 description 7
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- 238000012360 testing method Methods 0.000 description 5
- 239000003921 oil Substances 0.000 description 4
- 238000013459 approach Methods 0.000 description 3
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- 238000002156 mixing Methods 0.000 description 3
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- AMRUKLMZDPPJNU-IOLLQWDPSA-N (2-hydroxy-3-octadecanoyloxypropyl) (5e,8e,11e,14e)-icosa-5,8,11,14-tetraenoate Chemical compound CCCCCCCCCCCCCCCCCC(=O)OCC(O)COC(=O)CCC\C=C\C\C=C\C\C=C\C\C=C\CCCCC AMRUKLMZDPPJNU-IOLLQWDPSA-N 0.000 description 2
- 230000008901 benefit Effects 0.000 description 2
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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
- E21B43/162—Injecting fluid from longitudinally spaced locations in injection well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK 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
- E21B43/2406—Steam assisted gravity drainage [SAGD]
- E21B43/2408—SAGD in combination with other methods
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- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
- Working-Up Tar And Pitch (AREA)
Abstract
An in situ bitumen recovery startup process for an in situ bitumen recovery system having a well pair including a horizontal injection well and a horizontal production well located above it separated by an interwell region, includes injecting a solvent containing startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well; providing a pressure sink in the production well to promote pressure drive of the solvent from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well. This enables effective solvent assisted startup of in situ operations such as SAGD. A startup process may also include isolating intervals and injecting solvent into the intervals along the well pair. This enables enhanced solvent assisted startup of in situ operations such as SAGD.
Description
PROCESS FOR SOLVENT ASSISTED IN SITU BITUMEN RECOVERY
STARTUP
FIELD OF THE INVENTION
in particular relates to a process for solvent assisted in situ startup such as SAGD.
BACKGROUND
reservoirs. One technique called Steam Assisted Gravity Drainage (SAGD) has become a widespread process of recovering heavy oil and bitumen particularly in the oil sands of Northern Alberta. The SAGD process involves well pairs each of which consists of two horizontal wells drilled in the oil sands and aligned in pads for hundreds of meters. The well pairs of a group often extend parallel generally parallel to one another.
Once a SAGD well pair is drilled and completed, the first phase of SAGD
operations is the so-called startup phase. In the startup phase, fluid the injection and production wells. It is important for an effective SAGD
operation to reduce the viscosity of the bitumen between injection and production wells and produce it. This procedure, establishing heat communication between two wells at the initial stages of SAGD, can be done by circulating steam into both injection and production wells. The wells act as hot fingers in the reservoir and heating is by conduction. When initial steam injectivity is possible, steam may be injected in the top well and production obtained from the bottom well. After the pre-heat period the displacement and production of the bitumen in the region between wells is the step responsible for the initiation of the steam chamber.
takes between three and six months.
Solvent injection for SAGD startup and initialization has been attempted with limited success. In particular, it has been proposed to provide solvent via the injection and production wells and to allow a solvent soak period to reduce the A solvent pre-soak process includes the injection of solvent in advance to the The known processes for in situ recovery operations startup, such as for SAGD, have a variety of disadvantages.
STARTUP
FIELD OF THE INVENTION
in particular relates to a process for solvent assisted in situ startup such as SAGD.
BACKGROUND
reservoirs. One technique called Steam Assisted Gravity Drainage (SAGD) has become a widespread process of recovering heavy oil and bitumen particularly in the oil sands of Northern Alberta. The SAGD process involves well pairs each of which consists of two horizontal wells drilled in the oil sands and aligned in pads for hundreds of meters. The well pairs of a group often extend parallel generally parallel to one another.
Once a SAGD well pair is drilled and completed, the first phase of SAGD
operations is the so-called startup phase. In the startup phase, fluid the injection and production wells. It is important for an effective SAGD
operation to reduce the viscosity of the bitumen between injection and production wells and produce it. This procedure, establishing heat communication between two wells at the initial stages of SAGD, can be done by circulating steam into both injection and production wells. The wells act as hot fingers in the reservoir and heating is by conduction. When initial steam injectivity is possible, steam may be injected in the top well and production obtained from the bottom well. After the pre-heat period the displacement and production of the bitumen in the region between wells is the step responsible for the initiation of the steam chamber.
takes between three and six months.
Solvent injection for SAGD startup and initialization has been attempted with limited success. In particular, it has been proposed to provide solvent via the injection and production wells and to allow a solvent soak period to reduce the A solvent pre-soak process includes the injection of solvent in advance to the The known processes for in situ recovery operations startup, such as for SAGD, have a variety of disadvantages.
SUMMARY OF THE INVENTION
The present invention provides a process for solvent assisted in situ startup such as for SAGD.
More particularly, the present invention provides an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a well pair comprising a horizontal injection well and a horizontal production well located below the horizontal injection well and separated by an interwell region. The process includes injecting a solvent-containing startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well; providing a pressure sink in the production well to promote pressure drive of the solvent from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
In one aspect, the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
In another aspect, the solvent-containing startup fluid contains a solvent selected from aromatic compounds and alkanes. The solvent in the solvent-containing startup fluid may include at least one of toluene, xylene, diesel, butane, pentane, hexane, heptane and naphtha. Preferably, the solvent in the solvent-containing startup fluid comprises or consists of naphtha. In anther aspect, the solvent-containing startup fluid further comprises water.
In another aspect, the process includes halting the injection and the production upon reaching an upper solvent concentration threshold in the produced fluid.
The produced fluid may include between about 20% and about 50% volume of solvent based on the total volume of bitumen and solvent mixture. The upper solvent concentration threshold may be 50% volume based on the total volume of the bitumen and solvent mixture.
, , In another optional aspect, the solvent is selected to avoid asphaltene deposition.
In another optional aspect, the solvent containing startup fluid is formulated to avoid asphaltene deposition.
In another optional aspect, the solvent containing startup fluid is injected at a temperature between the initial reservoir temperature 8 and about 150 C. In another optional aspect, the solvent containing startup fluid is injected at a temperature above 100 C.
In another optional aspect, the solvent containing startup fluid is injected at a pressure between about initial reservoir pressure and about 100 kPa below the fracturing pressure of the reservoir proximate the injection well.
In another optional aspect, the interwell region is about 3 m to about 10m high.
Preferably, the interwell region is about 5 m high.
In another optional aspect, the in situ system is a SAGD system.
In another optional aspect, the process includes:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent containing startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the solvent from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
The isolating may be performed using packers, using at least one diverter and/or 5 using balls and/or sliding sleeves.
In another optional aspect, the injecting of the solvent-containing startup fluid is only done via the injection well. In another optional aspect, the providing the pressure sink is done only in the production well.
In another optional aspect, the in situ system comprises a plurality of the well pairs arranged in parallel relationship to one another and the process comprises performing solvent assisted startup on the plurality of well pairs.
In another embodiment, the invention provides an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region. The process includes injecting a solvent-containing startup fluid into one of the wells below a fracturing pressure of the reservoir; providing a pressure sink in the other of the wells to promote pressure drive of the solvent from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
In one aspect, the one well is the horizontal injection well and the other well is the horizontal production well.
In another optional aspect, the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
This process may also have any number of features and aspects as described herein-above related to solvent use, configurations and operation thereof.
The present invention provides a process for solvent assisted in situ startup such as for SAGD.
More particularly, the present invention provides an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a well pair comprising a horizontal injection well and a horizontal production well located below the horizontal injection well and separated by an interwell region. The process includes injecting a solvent-containing startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well; providing a pressure sink in the production well to promote pressure drive of the solvent from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
In one aspect, the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
In another aspect, the solvent-containing startup fluid contains a solvent selected from aromatic compounds and alkanes. The solvent in the solvent-containing startup fluid may include at least one of toluene, xylene, diesel, butane, pentane, hexane, heptane and naphtha. Preferably, the solvent in the solvent-containing startup fluid comprises or consists of naphtha. In anther aspect, the solvent-containing startup fluid further comprises water.
In another aspect, the process includes halting the injection and the production upon reaching an upper solvent concentration threshold in the produced fluid.
The produced fluid may include between about 20% and about 50% volume of solvent based on the total volume of bitumen and solvent mixture. The upper solvent concentration threshold may be 50% volume based on the total volume of the bitumen and solvent mixture.
, , In another optional aspect, the solvent is selected to avoid asphaltene deposition.
In another optional aspect, the solvent containing startup fluid is formulated to avoid asphaltene deposition.
In another optional aspect, the solvent containing startup fluid is injected at a temperature between the initial reservoir temperature 8 and about 150 C. In another optional aspect, the solvent containing startup fluid is injected at a temperature above 100 C.
In another optional aspect, the solvent containing startup fluid is injected at a pressure between about initial reservoir pressure and about 100 kPa below the fracturing pressure of the reservoir proximate the injection well.
In another optional aspect, the interwell region is about 3 m to about 10m high.
Preferably, the interwell region is about 5 m high.
In another optional aspect, the in situ system is a SAGD system.
In another optional aspect, the process includes:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent containing startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the solvent from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
The isolating may be performed using packers, using at least one diverter and/or 5 using balls and/or sliding sleeves.
In another optional aspect, the injecting of the solvent-containing startup fluid is only done via the injection well. In another optional aspect, the providing the pressure sink is done only in the production well.
In another optional aspect, the in situ system comprises a plurality of the well pairs arranged in parallel relationship to one another and the process comprises performing solvent assisted startup on the plurality of well pairs.
In another embodiment, the invention provides an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region. The process includes injecting a solvent-containing startup fluid into one of the wells below a fracturing pressure of the reservoir; providing a pressure sink in the other of the wells to promote pressure drive of the solvent from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
In one aspect, the one well is the horizontal injection well and the other well is the horizontal production well.
In another optional aspect, the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
This process may also have any number of features and aspects as described herein-above related to solvent use, configurations and operation thereof.
In another embodiment, the invention provides an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region. The process includes:
(i) isolating a first horizontal startup interval of one of the wells;
(ii) injecting a solvent-containing startup fluid into the first horizontal startup interval;
(iii) mobilizing bitumen of the interwell region proximate the first horizontal startup interval;
(iv) establishing fluid communication between the pair of wells in the first horizontal startup interval;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
In one aspect, steps (ii) to (iv) include injecting the solvent-containing startup fluid into the one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the solvent from the one well toward the other well to mobilize the bitumen in the interwell region in the first horizontal startup interval; and establishing fluid communication between the pair of wells.
In another optional aspect, the horizontal startup intervals are sized to have lengths in accordance with well conformance.
In another optional aspect, the horizontal startup intervals are sized to have lengths in accordance with well conformance.
(i) isolating a first horizontal startup interval of one of the wells;
(ii) injecting a solvent-containing startup fluid into the first horizontal startup interval;
(iii) mobilizing bitumen of the interwell region proximate the first horizontal startup interval;
(iv) establishing fluid communication between the pair of wells in the first horizontal startup interval;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
In one aspect, steps (ii) to (iv) include injecting the solvent-containing startup fluid into the one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the solvent from the one well toward the other well to mobilize the bitumen in the interwell region in the first horizontal startup interval; and establishing fluid communication between the pair of wells.
In another optional aspect, the horizontal startup intervals are sized to have lengths in accordance with well conformance.
In another optional aspect, the horizontal startup intervals are sized to have lengths in accordance with well conformance.
In another optional aspect, the horizontal startup intervals are sized to have lengths of at most about 100 m.
In another optional aspect, the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
In another optional aspect, there is provided an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a well pair comprising a horizontal injection well and a horizontal production well located below the horizontal injection well and separated by an interwell region, the process comprising:
injecting a startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of the startup fluid from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
In another optional aspect, there is provided an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region, the process comprising:
injecting a startup fluid into one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the startup fluid from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
7a In another optional aspect, there is provided an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region, the process comprising:
(I) isolating a first horizontal startup interval of one of the wells;
(ii) injecting a startup fluid into the first horizontal startup interval;
(iii) mobilizing bitumen of the interwell region proximate the first horizontal startup interval;
(iv) establishing fluid communication between the pair of wells in the first horizontal startup interval;
(v) halting startup fluid injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
This process may also have any number of optional features and aspects as described herein-above related to solvent use, configurations and operation thereof.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig 1 is transverse cut view of a SAGD well pair.
Fig 2 is a side plan view of a SAGD operation showing one SADG well pair.
Fig 3 is a transverse cut view of two well pairs with solvent halo areas.
7b Fig 4 is a graph of viscosity versus solvent concentration at different temperatures for bitumen-naphtha mixtures.
DETAILED DESCRIPTION
In an aspect of the present invention, the process is an in situ bitumen recovery startup process, such as a SAGD startup process. It should be understood that the in situ bitumen recovery startup process may also be adapted and used in connection with other steam or fluid assisted recovery processes.
In one embodiment, the process is a solvent assisted SAGD startup process. As illustrated in Fig 2, the SAGD startup process includes the steps of providing an injection well 10 having a vertical portion 12 and a horizontal portion 14 extending from its vertical portion and a production well 16 having a vertical portion 18 and a horizontal portion 20 extending from its vertical portion. The horizontal portion 20 of the production well 16 is downwardly spaced away from the horizontal portion 14 of the injection well 10 defining a bitumen interval 22 in between.
In another optional aspect, the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
In another optional aspect, there is provided an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a well pair comprising a horizontal injection well and a horizontal production well located below the horizontal injection well and separated by an interwell region, the process comprising:
injecting a startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of the startup fluid from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
In another optional aspect, there is provided an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region, the process comprising:
injecting a startup fluid into one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the startup fluid from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
7a In another optional aspect, there is provided an in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region, the process comprising:
(I) isolating a first horizontal startup interval of one of the wells;
(ii) injecting a startup fluid into the first horizontal startup interval;
(iii) mobilizing bitumen of the interwell region proximate the first horizontal startup interval;
(iv) establishing fluid communication between the pair of wells in the first horizontal startup interval;
(v) halting startup fluid injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
This process may also have any number of optional features and aspects as described herein-above related to solvent use, configurations and operation thereof.
BRIEF DESCRIPTION OF THE DRAWINGS
Fig 1 is transverse cut view of a SAGD well pair.
Fig 2 is a side plan view of a SAGD operation showing one SADG well pair.
Fig 3 is a transverse cut view of two well pairs with solvent halo areas.
7b Fig 4 is a graph of viscosity versus solvent concentration at different temperatures for bitumen-naphtha mixtures.
DETAILED DESCRIPTION
In an aspect of the present invention, the process is an in situ bitumen recovery startup process, such as a SAGD startup process. It should be understood that the in situ bitumen recovery startup process may also be adapted and used in connection with other steam or fluid assisted recovery processes.
In one embodiment, the process is a solvent assisted SAGD startup process. As illustrated in Fig 2, the SAGD startup process includes the steps of providing an injection well 10 having a vertical portion 12 and a horizontal portion 14 extending from its vertical portion and a production well 16 having a vertical portion 18 and a horizontal portion 20 extending from its vertical portion. The horizontal portion 20 of the production well 16 is downwardly spaced away from the horizontal portion 14 of the injection well 10 defining a bitumen interval 22 in between.
The injection well 10, the production well 16 and the bitumen interval 22 are also shown in Fig 1.
The injection and production wells form a well pair 24 and there are preferably multiple well pairs arranged in parallel to one another in the reservoir. The well pairs 24 are connected to above ground equipment on a pad 26.
In one aspect, the solvent assisted SAGD startup process includes injecting a solvent containing startup fluid 27 into the injection well 10 and providing a pressure sink in the production well 16. The injection of solvent or a mixture of at least one solvent with water in the injection well is performed below the fracturing pressure of the reservoir. The injection of the solvent containing startup fluid 27 may be performed at a pressure between about initial reservoir pressure, e.g.
between 500 and 1000 kPa and about 100 kPa, preferably at a pressure at least 100 kPa below the fracturing pressure of the reservoir proximate the injection which will depend on the depth of the injection well. The solvent injection may begin at an initial pressure which may be increased until solvent-bitumen fluid flow occurs in the production well or up to at most the fracturing pressure of the reservoir. This solvent injection pressure constraint along with the pressure sink of the production well, promote downward pressure drive of the solvent from the injection well toward the production well, to mobilize the bitumen interval.
The process also includes producing fluid from the production well using a pump or any other means to lower pressure in the producer.
In another optional aspect of the present invention, the solvent assisted startup process is utilized with well pairs for which the interwell region has a lower amount of bitumen to improve sweeping of the solvent through the length or interval of the interwell region.
Referring to Fig 2, a subsurface pump 28 may be provided to provide the pressure sink in the production well 16. A drive 30 which may be surface or subsurface may also be provided.
The injection and production wells form a well pair 24 and there are preferably multiple well pairs arranged in parallel to one another in the reservoir. The well pairs 24 are connected to above ground equipment on a pad 26.
In one aspect, the solvent assisted SAGD startup process includes injecting a solvent containing startup fluid 27 into the injection well 10 and providing a pressure sink in the production well 16. The injection of solvent or a mixture of at least one solvent with water in the injection well is performed below the fracturing pressure of the reservoir. The injection of the solvent containing startup fluid 27 may be performed at a pressure between about initial reservoir pressure, e.g.
between 500 and 1000 kPa and about 100 kPa, preferably at a pressure at least 100 kPa below the fracturing pressure of the reservoir proximate the injection which will depend on the depth of the injection well. The solvent injection may begin at an initial pressure which may be increased until solvent-bitumen fluid flow occurs in the production well or up to at most the fracturing pressure of the reservoir. This solvent injection pressure constraint along with the pressure sink of the production well, promote downward pressure drive of the solvent from the injection well toward the production well, to mobilize the bitumen interval.
The process also includes producing fluid from the production well using a pump or any other means to lower pressure in the producer.
In another optional aspect of the present invention, the solvent assisted startup process is utilized with well pairs for which the interwell region has a lower amount of bitumen to improve sweeping of the solvent through the length or interval of the interwell region.
Referring to Fig 2, a subsurface pump 28 may be provided to provide the pressure sink in the production well 16. A drive 30 which may be surface or subsurface may also be provided.
The process includes establishing fluid communication between the injection well and the production well.
Referring to Fig 2, the solvent containing startup fluid 27 may be provided via a solvent module 31 or a piping configuration for supplying solvent into the injection Thus, the efficiency of the pre-soak process is improved by creating a pressure sink in one of the wells driving the solvent from one well to the other. This process promotes confinement of the solvent to the volume between wells estimating that the decrease of the amount of solvent needed to approximately 1/4 of the solvent In addition, the process may also include monitoring of the solvent/bitumen produced allowing real-time assessment of the efficiency, corrective actions if required and direct evidence of the bitumen free path developed between wells.
Fig 3 illustrates a comparison between solvent soaking into both injection and For solvent soak:
20% naphtha content in the mobilized volume= 2,000 m3 50 % naphtha content in the mobilized volume = 8,000 m3 For solvent injection with pressure sink:
Bitumen volume = 2,000 m3 20% naphtha content in the mobilized volume = 500 m3 50 % naphtha content in the mobilized volume = 2000, m3 In addition, the following is for an extreme case accounting for unoptimized For solvent soak:
90 % naphtha content in the mobilized volume = 72,000 m3 For solvent injection with pressure sink:
90 % naphtha content in the mobilized volume = 18,000 m3 of the injection well 24 and connecting these isolated intervals one at a time using solvent injection. Referring to Fig 2, the injection well 24 may be divided into several isolated intervals illustrated as isolated startup intervals 32a, 32b, 32c, 32d and 32e. The solvent injection techniques described above may be An interval-based approach to the solvent assisted startup process has a number of advantages. First, the interval-based approach enables adjustability to adapt solvent assisted startup conditions and procedures to each interval along the well region running from the heel to the toe of the well pair, solvent injection along the entire length of the injection well may tend to have increased penetration at high permeability locations in the interwell region. Such high permeability locations may consist of low bitumen pockets or locations with naturally occurring higher be addressed in a number of other ways optionally in combination with the interval-based approach. The solvent injection pressure and the production well pressure sink may be provided or modulated to promote uniform solvent penetration. Special injection or production well completions may be utilized to The isolating of the horizontal startup intervals may be done in a number of ways.
startup intervals. A further method uses a diverter to block the flow through the annulus between the formation and the exterior surface of the liner which can improve the efficiency of the process improving the containment in the selected startup intervals 32a, 32b, 32c, 32d and 32e. It should be noted that any other In another possible aspect, the horizontal startup intervals may be provided alternating on the upper and lower wells and the solvent injection and pressure sink may accordingly be provided to inject and produce from alternating wells.
For instance, a first interval is isolated in the upper injection well and the pressure The startup process then uses injection of a solvent containing fluid into one of provided in accordance with conformance of the well pair and detected geological features.
The injection regime may be controlled in a number of ways. In one optional aspect, the injection regime is continuous such that the solvent containing startup fluid is continuously injected through the injection well until the produced fluid from the production well reaches a solvent fluid to bitumen ratio sufficiently high to halt injection and production. In another optional aspect, the injection regime is alternating such that a slug of the solvent containing startup fluid is injected followed by a slug of water. The solvent containing slug may have a volume depending on the given startup interval or based on calculations, estimates or field data from the reservoir or field, to provide an effective amount of solvent for achieving startup. The water slug enables improved efficiency of solvent use, since the hydraulic pressure on the solvent slug injection is enabled by the upstream water slug and thus solvent use is maximized for bitumen solubilization in the interwell region rather than merely providing sufficient hydraulics in the system. The alternating slug method may also be used by injecting a first pair of solvent and water slugs followed by subsequent pairs of solvent and water slugs, each subsequent pair of slugs decreasing in volume to continue the startup process while reducing the possibility of wasting solvent. In a further optional aspect, the solvent containing fluid and/or water slugs may be injected at a constant pressure or varying pressures. The solvent or slugs may be injected at progressively increasing or decreasing pressures depending on various factors such as the solvent content in the produced fluid. Pressure changes in the injection can alter and improve the solvent sweep efficiency, making it possible to sweep more bitumen from the interwell region.
In a further optional aspect, the injection and production well pressurization regime may be controlled to promote distribution of the solvent across the length of the horizontal startup interval or the injection well, as the case may be.
More particularly, the solvent may be initially injected while the production well has no pressure sink, for a sufficient time to allow the solvent to begin penetrating generally across the entire length of the horizontal startup interval or the injection well. The production well is then activated to create the pressure sink to draw the solvent toward the production well and promote more uniform communication between the injection and production well over the length of the well pair.
5 The solvent containing startup fluid 27 may contain one or more of a number of solvents. Solvent may include aromatic compounds such as toluene or xylene or aromatic containing fluids such as diesel and the like. Solvent may include alkanes such as butane, pentane, hexane, heptane and the like or a combination of such alkanes. Solvent may be selected as an oil sands processing or by-10 product stream and in accordance with site availability and location. In one preferred aspect, solvent includes naphtha which may be available on site.
Naphtha may be used as diluent in the produced bitumen containing stream and thus the naphtha addition may be seen as a diluent pre-treatement. In one optional aspect, the amount of naphtha diluent used in the startup process 15 produces a market ready diluted bitumen stream, e.g. as "dilbit", thus avoiding further treatment of the produced bitumen stream as would normally be required.
The solvent containing fluid may contain for example about 50% naphtha and about 50% water. The proportion of the solvent and water may be varied and optimized to achieve various results such as efficient solvent usage and depending on other operating conditions such as pressure and temperature. In another optional aspect, the process includes a step of performing a bitumen-solvent compatibility test for each batch of solvent to be used. The solvent is preferably selected to have no undesired interaction with bitumen in downhole conditions, such as asphaltene precipitation or deposition which could lead to fouling and various problems. The solvent may be provided in a concentration in the solvent containing startup fluid sufficent to minimize asphaltene deposition, such as a solvent concentration below the asphaltene precipitation threshold in the case of alkane solvents.
Based on bitumen and naphtha studies, the process preferably uses naphtha which does not show adverse interactions with bitumen and which with a content between 20% and 50% of naphtha in the final bitumen naphtha mixture, which lowers the cold bitumen viscosity to a point where it is mobile. Thus, a naphtha content above 20% allows fluid mobility. In one aspect, the produced fluid 34 will have an initial concentration around 20% naphtha and this concentration will increase over time as the startup process continues to mobilize bitumen in the interwell region and establish fluid communication. When the produced fluid 34 reaches an upper threshold, such as 50% naphtha, production is halted. For instance, after a given amount of solvent has been injected and bitumen content is low in the produced fluid stream 34 as a result of completion of the sweep process, injection and production are halted.
Fig 4 shows viscosity versus solvent concentration at different temperatures for bitumen-naphtha mixtures. The naphtha allows a marked viscosity reduction of the bitumen.
The process of the present invention provides faster and more efficient solvent assisted startup of SAGD allowing pressure differential to drive the solvent and minimize losses. Injecting solvent or a mixture of one or more solvents with water in the injection well and producing fluid from the production well with a pressure sink drives fluid from the injection well to the production well making the process fast and efficient with less solvent loses. Solvent lowers the bitumen viscosity while simultaneous injection/production keeps the solvent contained in the interwell region and drives solvent diluted bitumen to the production well.
Packers or diverter or any other means improves the conformance of the process along the horizontal intervals of the well. The elimination of the typical SAGD
wells preheat lowers the steam to oil ratio (SOR) and allows earlier start-up with the associated financial benefit. The solvent assisted SADG startup process allows significant gas savings due to faster startup and reduced steam use.
In one example case, the injection well is given a completion including three down-hole pressure sensors with real-time surface reading, downhole temperature sensors with real-time surface reading, well head flow meter for water, well head flow meter for bitumen-naphtha mixture and a spinner log for horizontal wells. The production well is given a completion including PCP pump landed as close as possible to the reservoir, three down-hole pressure sensors with real-time surface reading, downhole temperature sensors with real-time surface reading.
In an optional aspect, the startup process includes a preliminary detection stage for assessing various features of the reservoir and wells such as cold water mobility and cold solvent mobility.
The cold water mobility test may include:
- Starting the producer PCP while keeping constant downhole pressure,; registering pressure in the injection well and adjacent well pairs; when a pressure drop is detected at an adjacent well pair or after a given time interval, e.g. 48 hrs, pumping; and stopping production and wait for pressure recovery.
-Starting the producer PCP while keeping constant downhole pressure, injecting cold water in the injector at about 50% of the maximum allowed injection pressure; waiting for pressure and flow stabilization;
and running spinner log in injection well.
The cold solvent mobility test may include:
- Keeping an injection/production ratio below about 0.7; adding solvent to the injection stream until 50 % v/vi is reached; waiting for pressure and flow stabilization; running spinner log in injection well; taking samples of produced bitumen, for instance to determine viscosity and naphtha content; measuring water cut; when production is stable (water cut), increasing the solvent content until 100 % solvent is injected; waiting for pressure and flow stabilization; and running spinner log in injection well.
The following is an example procedural overview for implementation of an embodiment of the present invention:
- Conformance control:
o When production is stable (water cut and naphtha content of the bitumen produced as determined by density measurement in the field) inject a slug of diverter to control the conformance of the process.
o Repeat the cold solvent mobility step alternating with diverter slugs several times, e.g. at least four times.
- Warm water mobility:
O Increase the bottom-hole temperature of the injected water to about 50 C, which will require steam at the well head.
Repeat steps with solvent and diverter.
O Increase the bottom-hole temperature to 100 C. Repeat steps with solvent and diverter.
-Circulate steam in the injector and the producer with slight pressure changes to evaluate communication between wells and start them up in SAGD mode.
Various optional aspects of the present invention may help to mitigate technical challenges of the SAGD startup process. For instance, the cold water infectivity tests prior to performing the process allows adjustments for low injectivity.
Driving solvent from one well to the other by creating a pregsure sink in the producer and actually producing fluids as well as maintaining injection/production ratio below 0.7 helps to minimize solvent loss. Using diverter or the like to improve conformance along the well can make a particularly significant difference especially in early behavior of the wells. Furthermore, performing and analyzing compatibility samples and testing to asphaltene deposition can help quickly evaluate this potential challenge and solvent selection can be modified, e.g.
from an alkane based solvent to a naphtha-based solvent.
Referring to Fig 2, the surface equipment provided to inject the solvent may include pumps and holding tanks along with monitoring equipment to monitor pressure, flow of solvent, slug volumes, and the like as the case may be. The surface equipment may include mixing means (not illustrated) to mix pure solvent with water to create the solvent containing startup fluid 27. The mixing equipment may include static mixers, tee pipe junctions, to generally provide sufficient mixing energy to blend the solvent and water. The surface equipment may also include tanks 36 for the produced fluid 34 and pumps 38 for supplying the produced fluid to desired locations, recycling, solvent removal or downstream processing as the case may be. There may be multiple tanks for holding the production fluid 34 produced at different periods of the startup process, e.g. a holding tank for receiving bitumen-rich produced fluid, a holding tank for receiving solvent-rich produced fluid and a holding tank for receiving produced fluid with a composition suitable to be considered "dilbit".
Finally, various other variants, embodiment and aspects may also be used in under the present invention.
Referring to Fig 2, the solvent containing startup fluid 27 may be provided via a solvent module 31 or a piping configuration for supplying solvent into the injection Thus, the efficiency of the pre-soak process is improved by creating a pressure sink in one of the wells driving the solvent from one well to the other. This process promotes confinement of the solvent to the volume between wells estimating that the decrease of the amount of solvent needed to approximately 1/4 of the solvent In addition, the process may also include monitoring of the solvent/bitumen produced allowing real-time assessment of the efficiency, corrective actions if required and direct evidence of the bitumen free path developed between wells.
Fig 3 illustrates a comparison between solvent soaking into both injection and For solvent soak:
20% naphtha content in the mobilized volume= 2,000 m3 50 % naphtha content in the mobilized volume = 8,000 m3 For solvent injection with pressure sink:
Bitumen volume = 2,000 m3 20% naphtha content in the mobilized volume = 500 m3 50 % naphtha content in the mobilized volume = 2000, m3 In addition, the following is for an extreme case accounting for unoptimized For solvent soak:
90 % naphtha content in the mobilized volume = 72,000 m3 For solvent injection with pressure sink:
90 % naphtha content in the mobilized volume = 18,000 m3 of the injection well 24 and connecting these isolated intervals one at a time using solvent injection. Referring to Fig 2, the injection well 24 may be divided into several isolated intervals illustrated as isolated startup intervals 32a, 32b, 32c, 32d and 32e. The solvent injection techniques described above may be An interval-based approach to the solvent assisted startup process has a number of advantages. First, the interval-based approach enables adjustability to adapt solvent assisted startup conditions and procedures to each interval along the well region running from the heel to the toe of the well pair, solvent injection along the entire length of the injection well may tend to have increased penetration at high permeability locations in the interwell region. Such high permeability locations may consist of low bitumen pockets or locations with naturally occurring higher be addressed in a number of other ways optionally in combination with the interval-based approach. The solvent injection pressure and the production well pressure sink may be provided or modulated to promote uniform solvent penetration. Special injection or production well completions may be utilized to The isolating of the horizontal startup intervals may be done in a number of ways.
startup intervals. A further method uses a diverter to block the flow through the annulus between the formation and the exterior surface of the liner which can improve the efficiency of the process improving the containment in the selected startup intervals 32a, 32b, 32c, 32d and 32e. It should be noted that any other In another possible aspect, the horizontal startup intervals may be provided alternating on the upper and lower wells and the solvent injection and pressure sink may accordingly be provided to inject and produce from alternating wells.
For instance, a first interval is isolated in the upper injection well and the pressure The startup process then uses injection of a solvent containing fluid into one of provided in accordance with conformance of the well pair and detected geological features.
The injection regime may be controlled in a number of ways. In one optional aspect, the injection regime is continuous such that the solvent containing startup fluid is continuously injected through the injection well until the produced fluid from the production well reaches a solvent fluid to bitumen ratio sufficiently high to halt injection and production. In another optional aspect, the injection regime is alternating such that a slug of the solvent containing startup fluid is injected followed by a slug of water. The solvent containing slug may have a volume depending on the given startup interval or based on calculations, estimates or field data from the reservoir or field, to provide an effective amount of solvent for achieving startup. The water slug enables improved efficiency of solvent use, since the hydraulic pressure on the solvent slug injection is enabled by the upstream water slug and thus solvent use is maximized for bitumen solubilization in the interwell region rather than merely providing sufficient hydraulics in the system. The alternating slug method may also be used by injecting a first pair of solvent and water slugs followed by subsequent pairs of solvent and water slugs, each subsequent pair of slugs decreasing in volume to continue the startup process while reducing the possibility of wasting solvent. In a further optional aspect, the solvent containing fluid and/or water slugs may be injected at a constant pressure or varying pressures. The solvent or slugs may be injected at progressively increasing or decreasing pressures depending on various factors such as the solvent content in the produced fluid. Pressure changes in the injection can alter and improve the solvent sweep efficiency, making it possible to sweep more bitumen from the interwell region.
In a further optional aspect, the injection and production well pressurization regime may be controlled to promote distribution of the solvent across the length of the horizontal startup interval or the injection well, as the case may be.
More particularly, the solvent may be initially injected while the production well has no pressure sink, for a sufficient time to allow the solvent to begin penetrating generally across the entire length of the horizontal startup interval or the injection well. The production well is then activated to create the pressure sink to draw the solvent toward the production well and promote more uniform communication between the injection and production well over the length of the well pair.
5 The solvent containing startup fluid 27 may contain one or more of a number of solvents. Solvent may include aromatic compounds such as toluene or xylene or aromatic containing fluids such as diesel and the like. Solvent may include alkanes such as butane, pentane, hexane, heptane and the like or a combination of such alkanes. Solvent may be selected as an oil sands processing or by-10 product stream and in accordance with site availability and location. In one preferred aspect, solvent includes naphtha which may be available on site.
Naphtha may be used as diluent in the produced bitumen containing stream and thus the naphtha addition may be seen as a diluent pre-treatement. In one optional aspect, the amount of naphtha diluent used in the startup process 15 produces a market ready diluted bitumen stream, e.g. as "dilbit", thus avoiding further treatment of the produced bitumen stream as would normally be required.
The solvent containing fluid may contain for example about 50% naphtha and about 50% water. The proportion of the solvent and water may be varied and optimized to achieve various results such as efficient solvent usage and depending on other operating conditions such as pressure and temperature. In another optional aspect, the process includes a step of performing a bitumen-solvent compatibility test for each batch of solvent to be used. The solvent is preferably selected to have no undesired interaction with bitumen in downhole conditions, such as asphaltene precipitation or deposition which could lead to fouling and various problems. The solvent may be provided in a concentration in the solvent containing startup fluid sufficent to minimize asphaltene deposition, such as a solvent concentration below the asphaltene precipitation threshold in the case of alkane solvents.
Based on bitumen and naphtha studies, the process preferably uses naphtha which does not show adverse interactions with bitumen and which with a content between 20% and 50% of naphtha in the final bitumen naphtha mixture, which lowers the cold bitumen viscosity to a point where it is mobile. Thus, a naphtha content above 20% allows fluid mobility. In one aspect, the produced fluid 34 will have an initial concentration around 20% naphtha and this concentration will increase over time as the startup process continues to mobilize bitumen in the interwell region and establish fluid communication. When the produced fluid 34 reaches an upper threshold, such as 50% naphtha, production is halted. For instance, after a given amount of solvent has been injected and bitumen content is low in the produced fluid stream 34 as a result of completion of the sweep process, injection and production are halted.
Fig 4 shows viscosity versus solvent concentration at different temperatures for bitumen-naphtha mixtures. The naphtha allows a marked viscosity reduction of the bitumen.
The process of the present invention provides faster and more efficient solvent assisted startup of SAGD allowing pressure differential to drive the solvent and minimize losses. Injecting solvent or a mixture of one or more solvents with water in the injection well and producing fluid from the production well with a pressure sink drives fluid from the injection well to the production well making the process fast and efficient with less solvent loses. Solvent lowers the bitumen viscosity while simultaneous injection/production keeps the solvent contained in the interwell region and drives solvent diluted bitumen to the production well.
Packers or diverter or any other means improves the conformance of the process along the horizontal intervals of the well. The elimination of the typical SAGD
wells preheat lowers the steam to oil ratio (SOR) and allows earlier start-up with the associated financial benefit. The solvent assisted SADG startup process allows significant gas savings due to faster startup and reduced steam use.
In one example case, the injection well is given a completion including three down-hole pressure sensors with real-time surface reading, downhole temperature sensors with real-time surface reading, well head flow meter for water, well head flow meter for bitumen-naphtha mixture and a spinner log for horizontal wells. The production well is given a completion including PCP pump landed as close as possible to the reservoir, three down-hole pressure sensors with real-time surface reading, downhole temperature sensors with real-time surface reading.
In an optional aspect, the startup process includes a preliminary detection stage for assessing various features of the reservoir and wells such as cold water mobility and cold solvent mobility.
The cold water mobility test may include:
- Starting the producer PCP while keeping constant downhole pressure,; registering pressure in the injection well and adjacent well pairs; when a pressure drop is detected at an adjacent well pair or after a given time interval, e.g. 48 hrs, pumping; and stopping production and wait for pressure recovery.
-Starting the producer PCP while keeping constant downhole pressure, injecting cold water in the injector at about 50% of the maximum allowed injection pressure; waiting for pressure and flow stabilization;
and running spinner log in injection well.
The cold solvent mobility test may include:
- Keeping an injection/production ratio below about 0.7; adding solvent to the injection stream until 50 % v/vi is reached; waiting for pressure and flow stabilization; running spinner log in injection well; taking samples of produced bitumen, for instance to determine viscosity and naphtha content; measuring water cut; when production is stable (water cut), increasing the solvent content until 100 % solvent is injected; waiting for pressure and flow stabilization; and running spinner log in injection well.
The following is an example procedural overview for implementation of an embodiment of the present invention:
- Conformance control:
o When production is stable (water cut and naphtha content of the bitumen produced as determined by density measurement in the field) inject a slug of diverter to control the conformance of the process.
o Repeat the cold solvent mobility step alternating with diverter slugs several times, e.g. at least four times.
- Warm water mobility:
O Increase the bottom-hole temperature of the injected water to about 50 C, which will require steam at the well head.
Repeat steps with solvent and diverter.
O Increase the bottom-hole temperature to 100 C. Repeat steps with solvent and diverter.
-Circulate steam in the injector and the producer with slight pressure changes to evaluate communication between wells and start them up in SAGD mode.
Various optional aspects of the present invention may help to mitigate technical challenges of the SAGD startup process. For instance, the cold water infectivity tests prior to performing the process allows adjustments for low injectivity.
Driving solvent from one well to the other by creating a pregsure sink in the producer and actually producing fluids as well as maintaining injection/production ratio below 0.7 helps to minimize solvent loss. Using diverter or the like to improve conformance along the well can make a particularly significant difference especially in early behavior of the wells. Furthermore, performing and analyzing compatibility samples and testing to asphaltene deposition can help quickly evaluate this potential challenge and solvent selection can be modified, e.g.
from an alkane based solvent to a naphtha-based solvent.
Referring to Fig 2, the surface equipment provided to inject the solvent may include pumps and holding tanks along with monitoring equipment to monitor pressure, flow of solvent, slug volumes, and the like as the case may be. The surface equipment may include mixing means (not illustrated) to mix pure solvent with water to create the solvent containing startup fluid 27. The mixing equipment may include static mixers, tee pipe junctions, to generally provide sufficient mixing energy to blend the solvent and water. The surface equipment may also include tanks 36 for the produced fluid 34 and pumps 38 for supplying the produced fluid to desired locations, recycling, solvent removal or downstream processing as the case may be. There may be multiple tanks for holding the production fluid 34 produced at different periods of the startup process, e.g. a holding tank for receiving bitumen-rich produced fluid, a holding tank for receiving solvent-rich produced fluid and a holding tank for receiving produced fluid with a composition suitable to be considered "dilbit".
Finally, various other variants, embodiment and aspects may also be used in under the present invention.
Claims (68)
1. An in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a well pair comprising a horizontal injection well and a horizontal production well located below the horizontal injection well and separated by an interwell region, the process comprising:
injecting a solvent-containing startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of the solvent from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
injecting a solvent-containing startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of the solvent from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
2. The process of claim 1, wherein the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
3. The process of claim 1 or 2, wherein the solvent-containing startup fluid contains a solvent selected from aromatic compounds and alkanes.
4. The process of claim 3, wherein the solvent in the solvent-containing startup fluid comprises at least one of toluene, xylene, diesel, butane, pentane, hexane, heptane and naphtha.
5. The process of claim 4, wherein the solvent in the solvent-containing startup fluid comprises naphtha.
6. The process of claim 5, wherein the solvent in the solvent-containing startup fluid consists of naphtha.
7. The process of any one of claims 1 to 6, wherein the solvent-containing startup fluid further comprises water.
8. The process of any one of claims 1 to 7, comprising halting the injection and the production upon reaching an upper solvent concentration threshold in the produced fluid.
9. The process of claim 8, wherein the produced fluid comprises between about 20% and about 50% volume of solvent based on the total volume of bitumen and solvent mixture.
10. The process of claim 8 or 9, wherein the upper solvent concentration threshold is 50% volume based on the total volume of the bitumen and solvent mixture.
11. The process of any one of claims 1 to 10, wherein the solvent is selected to avoid asphaltene deposition.
12. The process of any one of claims 1 to 11, wherein the solvent-containing startup fluid is formulated to avoid asphaltene deposition.
13. The process of any one of claims 1 to 12, wherein the solvent-containing startup fluid is injected at a temperature between the initial reservoir temperature 8 and about 150°C.
14. The process of any one of claims 1 to 13, wherein the solvent-containing startup fluid is injected at a temperature above 100°C.
15. The process of any one of claims 1 to 14, wherein the solvent-containing startup fluid is injected at a pressure between about initial reservoir pressure and about 100 kPa below the fracturing pressure of the reservoir proximate the injection well.
16. The process of any one of claims 1 to 15, wherein the interwell region is about 3 m to about 10m high.
17. The process of any one of claims 1 to 16, wherein the interwell region is about 5 m high.
18. The process of any one of claims 1 to 17, wherein the in situ system is a SAGD system.
19. The process of any one of claims 1 to 18, comprising:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent-containing startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the solvent from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent-containing startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the solvent from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
20. The process of claim 19, wherein the isolating is performed using packers.
21. The process of claim 19, wherein the isolating is performed using at least one diverter.
22. The process of claim 19, wherein the isolating is performed using balls and/or sliding sleeves.
23. The process of any one of claims 1 to 22, wherein the injecting of the solvent-containing startup fluid is only done via the injection well.
24. The process of any one of claims 1 to 23, wherein the providing the pressure sink is done only in the production well.
25. The process of any one of claims 1 to 24, wherein the in situ system comprises a plurality of the well pairs arranged in parallel relationship to one another and the process comprises performing solvent assisted startup on the plurality of well pairs.
26. An in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells, a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region, the process comprising:
injecting a solvent-containing startup fluid into one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the solvent from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
injecting a solvent-containing startup fluid into one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the solvent from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
27. The process of claim 26, wherein the one well is the horizontal injection well and the other well is the horizontal production well.
28. The process of claim 27, wherein the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
29. The process of any one of claims 26 to 28, wherein the solvent-containing startup fluid contains a solvent selected from aromatic compounds and alkanes.
30. The process of claim 29, wherein the solvent in the solvent-containing startup fluid comprises at least one of toluene, xylene, diesel, butane, pentane, hexane, heptane and naphtha.
31. The process of claim 30, wherein the solvent in the solvent-containing startup fluid comprises naphtha.
32. The process of claim 31, wherein the solvent in the solvent-containing startup fluid consists of naphtha.
33. The, process of any one of claims 26 to 32, wherein the solvent-containing startup fluid further comprises water.
34. The process of any one of claims 26 to 33, comprising halting the injection and the pressure sink upon reaching an upper solvent concentration threshold in the produced fluid.
35. The process of claim 34, wherein the produced fluid comprises between about 20% and about 50% volume of solvent based on the total volume of bitumen and solvent mixture.
36. The process of claim 34 or 35, wherein the upper solvent concentration threshold is 50% volume based on the total volume of the bitumen and solvent mixture.
37. The process of any one of claims 26 to 36, wherein the solvent is selected to avoid asphaltene deposition.
38. The process of any one of claims 26 to 37, wherein the solvent-containing startup fluid is formulated to avoid asphaltene deposition.
39. The process of any one of claims 26 to 38, wherein the solvent-containing startup fluid is injected at a temperature between the initial reservoir temperature 8 and about 150°C.
40. The process of any one of claims 26 to 39, wherein the solvent-containing startup fluid is injected at a temperature above 100°C.
41. The process of any one of claims 26 to 40, wherein the solvent-containing startup fluid is injected at a pressure between about initial reservoir pressure and about 100 kPa below the fracturing pressure of the reservoir proximate the injection well.
42. The process of any one of claims 26 to 41, wherein the interwell region is about 3 m to about 10m high.
43. The process of any one of claims 26 to 42, wherein the interwell region is about 5 m high.
44. The process of any one of claims 26 to 43, wherein the in situ system is a SAGD system.
45. The process of any one of claims 26 to 44, comprising:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent-containing startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the solvent from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the solvent-containing startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the solvent from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting solvent injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
46. The process of claim 45, wherein the isolating is performed using packers.
47. The process of claim 45, wherein the isolating is performed using at least one diverter.
48. The process of claim 45, wherein the isolating is performed using balls and /
or sliding sleeves.
or sliding sleeves.
49. The process of any one of claims 26 to 48, wherein the injecting of the solvent-containing startup fluid is only done via the one well.
50. The process of any one of claims 26 to 49, wherein the providing the pressure sink is done only in the other well.
51. The process of any one of claims 26 to 50, wherein the in situ system comprises a plurality of the well pairs arranged in parallel relationship to one another and the process comprises performing solvent assisted startup on the plurality of well pairs.
52. An in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a well pair comprising a horizontal injection well and a horizontal production well located below the horizontal injection well and separated by an interwell region, the process comprising:
injecting a startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of the startup fluid from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
injecting a startup fluid into the injection well below a fracturing pressure of the reservoir proximate the injection well;
providing a pressure sink in the production well to promote pressure drive of the startup fluid from the injection well toward the production well to mobilize bitumen in the interwell region; and establishing fluid communication between the injection well and the production well.
53. An in situ bitumen recovery startup process for an in situ system in a bitumen containing reservoir, the in situ system comprising a pair of wells comprising a horizontal injection well and a horizontal production well located below the horizontal injection well, the wells being separated by an interwell region, the process comprising:
injecting a startup fluid into one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the startup fluid from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
injecting a startup fluid into one of the wells below a fracturing pressure of the reservoir;
providing a pressure sink in the other of the wells to promote pressure drive of the startup fluid from the one well toward the other well to mobilize bitumen in the interwell region; and establishing fluid communication between the pair of wells.
54. The process of claim 53, wherein the one well is the horizontal injection well and the other well is the horizontal production well.
55. The process of claim 54, wherein the pressure sink is created by a pump associate with the production well for producing fluids therefrom.
56. The process of any one of claims 53 to 55, wherein the startup fluid contains a solvent.
57. The process of any one of claims 53 to 56, wherein the startup fluid further comprises water.
58. The process of any one of claims 53 to 57, wherein the startup fluid is injected at a temperature between the initial reservoir temperature 8 and about 150°C.
59. The process of any one of claims 53 to 58, wherein the startup fluid is injected at a temperature above 100°C.
60. The process of any one of claims 53 to 59, wherein the startup fluid is injected at a pressure between about initial reservoir pressure and about 100 kPa below the fracturing pressure of the reservoir proximate the injection well.
61. The process of any one of claims 53 to 60, wherein the interwell region is about 3 m to about 10m high.
62. The process of any one of claims 53 to 61, wherein the in situ system is a SAGD system.
63. The process of any one of claims 53 to 62, comprising:
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the startup fluid from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting startup fluid injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
(i) isolating a first horizontal startup interval of the well pair;
(ii) injecting the startup fluid into the injection well at the first horizontal startup interval;
(iii) providing the pressure sink in the production well to promote downward pressure drive of the startup fluid from the injection well toward the production well at the first horizontal startup interval, to mobilize bitumen in a first portion of the interwell region;
(iv) establishing fluid communication between the injection well and the production well in the first portion of the interwell region;
(v) halting startup fluid injection and production in the first horizontal startup interval; and (vi) isolating additional horizontal startup intervals one-by-one and repeating steps (ii) to (v) for each of the additional horizontal startup intervals.
64. The process of claim 63, wherein the isolating is performed using packers.
65. The process of claim 63, wherein the isolating is performed using at least one diverter.
66. The process of claim 63, wherein the isolating is performed using balls and/or sliding sleeves.
67. The process of any one of claims 53 to 66, wherein the injecting of the startup fluid is only done via the one well.
68. The process of any one of claims 53 to 67, wherein the providing the pressure sink is done only in the other well.
Priority Applications (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2740941A CA2740941C (en) | 2011-05-20 | 2011-05-20 | Process for solvent assisted in situ bitumen recovery startup |
| CA2778135A CA2778135C (en) | 2011-05-20 | 2012-05-18 | Solvent assisted startup techniques for in situ bitumen recovery with sagd well pairs, infill wells or step-out wells |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| CA2740941A CA2740941C (en) | 2011-05-20 | 2011-05-20 | Process for solvent assisted in situ bitumen recovery startup |
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|---|---|
| CA2740941A1 CA2740941A1 (en) | 2012-11-20 |
| CA2740941C true CA2740941C (en) | 2014-04-08 |
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| CA2740941A Active CA2740941C (en) | 2011-05-20 | 2011-05-20 | Process for solvent assisted in situ bitumen recovery startup |
| CA2778135A Active CA2778135C (en) | 2011-05-20 | 2012-05-18 | Solvent assisted startup techniques for in situ bitumen recovery with sagd well pairs, infill wells or step-out wells |
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| CA2778135A Active CA2778135C (en) | 2011-05-20 | 2012-05-18 | Solvent assisted startup techniques for in situ bitumen recovery with sagd well pairs, infill wells or step-out wells |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US9551207B2 (en) | 2011-05-19 | 2017-01-24 | Jason Swist | Pressure assisted oil recovery |
| CA2762451C (en) | 2011-12-16 | 2019-02-26 | Imperial Oil Resources Limited | Method and system for lifting fluids from a reservoir |
| US9587480B2 (en) | 2013-03-14 | 2017-03-07 | Suncor Energy Inc. | Cellar oil recovery techniques for in situ operations |
| CA2917260A1 (en) * | 2013-07-05 | 2015-01-08 | Nexen Energy Ulc | Accelerated solvent-aided sagd start-up |
| CA2826494C (en) | 2013-09-09 | 2017-03-07 | Imperial Oil Resources Limited | Improving recovery from a hydrocarbon reservoir |
| CN103615224B (en) * | 2013-11-08 | 2016-02-10 | 中国石油天然气股份有限公司 | Solvent improves method and the well pattern structure of exploiting thickened oil through steam assisted gravity drainage Tibetan |
| CA2837475C (en) | 2013-12-19 | 2020-03-24 | Imperial Oil Resources Limited | Improving recovery from a hydrocarbon reservoir |
| CN104405348B (en) * | 2014-10-27 | 2017-01-11 | 中国石油天然气股份有限公司 | Solvent reinforcement method for communicating between horizontal wells |
| CA2915596C (en) | 2014-12-18 | 2023-04-25 | Chevron U.S.A. Inc. | Method for upgrading in situ heavy oil |
| AR103391A1 (en) | 2015-01-13 | 2017-05-03 | Bp Corp North America Inc | METHODS AND SYSTEMS TO PRODUCE HYDROCARBONS FROM ROCA HYDROCARBON PRODUCER THROUGH THE COMBINED TREATMENT OF THE ROCK AND INJECTION OF BACK WATER |
| CN104632164A (en) * | 2015-01-29 | 2015-05-20 | 中国石油天然气股份有限公司 | Method for breaking through interlayer in oil layer during double-horizontal-well SAGD exploiting |
| CN105986794A (en) * | 2015-03-05 | 2016-10-05 | 中国石油天然气股份有限公司 | Oil extraction method for steam assisted gravity drainage (SAGD) dual horizontal well and tubular column equipment of oil extraction method |
| CA2900711A1 (en) | 2015-08-18 | 2017-02-18 | Statoil Canada Limited | Pressure swing solvent assisted well stimulation |
| CN105178931B (en) * | 2015-09-06 | 2017-11-07 | 中国石油天然气股份有限公司 | A kind of method that speed is produced on raising SAGD initial stages |
| RU2749703C1 (en) * | 2021-01-26 | 2021-06-16 | Публичное акционерное общество «Татнефть» имени В.Д. Шашина | Method for developing layer of ultra-viscous oil by uniform vapor-gravity action |
-
2011
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| Publication number | Publication date |
|---|---|
| CA2778135A1 (en) | 2012-11-20 |
| CA2778135C (en) | 2014-04-08 |
| CA2740941A1 (en) | 2012-11-20 |
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