CA2915661A1 - Multilateral well completions to improve individual branch control - Google Patents
Multilateral well completions to improve individual branch control Download PDFInfo
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- CA2915661A1 CA2915661A1 CA2915661A CA2915661A CA2915661A1 CA 2915661 A1 CA2915661 A1 CA 2915661A1 CA 2915661 A CA2915661 A CA 2915661A CA 2915661 A CA2915661 A CA 2915661A CA 2915661 A1 CA2915661 A1 CA 2915661A1
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- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 41
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 41
- 238000000034 method Methods 0.000 claims abstract description 30
- 238000004519 manufacturing process Methods 0.000 claims description 122
- 238000002347 injection Methods 0.000 claims description 75
- 239000007924 injection Substances 0.000 claims description 75
- 239000012530 fluid Substances 0.000 claims description 69
- 239000004215 Carbon black (E152) Substances 0.000 claims description 40
- 238000005553 drilling Methods 0.000 claims description 14
- 238000005086 pumping Methods 0.000 claims description 7
- 239000011877 solvent mixture Substances 0.000 claims description 6
- 238000011084 recovery Methods 0.000 abstract description 13
- 238000010796 Steam-assisted gravity drainage Methods 0.000 description 11
- 239000003921 oil Substances 0.000 description 11
- 239000000295 fuel oil Substances 0.000 description 7
- 238000009826 distribution Methods 0.000 description 5
- 238000005516 engineering process Methods 0.000 description 5
- 238000010793 Steam injection (oil industry) Methods 0.000 description 4
- 230000008901 benefit Effects 0.000 description 3
- 239000000839 emulsion Substances 0.000 description 3
- 230000006872 improvement Effects 0.000 description 3
- 238000010794 Cyclic Steam Stimulation Methods 0.000 description 2
- 230000015572 biosynthetic process Effects 0.000 description 2
- 238000007796 conventional method Methods 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 230000035699 permeability Effects 0.000 description 2
- 238000004513 sizing Methods 0.000 description 2
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 2
- 239000008186 active pharmaceutical agent Substances 0.000 description 1
- 238000007792 addition Methods 0.000 description 1
- 230000004075 alteration Effects 0.000 description 1
- 239000010426 asphalt Substances 0.000 description 1
- 230000000712 assembly Effects 0.000 description 1
- 238000000429 assembly Methods 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 230000005484 gravity Effects 0.000 description 1
- 238000010438 heat treatment Methods 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
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- 239000011343 solid material Substances 0.000 description 1
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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
- E21B43/24—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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- 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
- E21B43/14—Obtaining from a multiple-zone well
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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)
Abstract
Methods and systems for enhanced thermal recovery of subsurface hydrocarbons comprising the use of multilateral branches, wherein the multilateral wells are completed in a manner to improve individual branch control.
Description
MULTILATERAL WELL COMPLETIONS TO IMPROVE
INDIVIDUAL BRANCH CONTROL
Field of the Invention The present invention relates to thermal hydrocarbon recovery techniques, and particularly to the =
use of multilateral wells in hydrocarbon recovery.
Background of the Invention Heavy oil is a term commonly applied to describe oils having a specific gravity less than about degrees API. These oils, which include bitumen, are not readily producible by conventional techniques. Their viscosity is so high that the oil cannot easily be mobilized and driven to a production well by a pressure drive. Therefore, a recovery process is required to reduce the 15 viscosity and then produce the oil.
Thermal recovery methods as applied in heavy oil have the common objective of accelerating the recovery process. Raising the temperature of the host formation reduces the heavy oil viscosity allowing the near solid material at original temperature to flow as a liquid.
For heavy oil 20 reservoirs, steam injection from the surface into the formation is used as a conventional method to heat the heavy oil in situ, reducing its viscosity to a level where the oil is amenable to displacement. Typical methods of recovering oil from an oil sands reservoir include cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
Electromagnetic (EM) heating, or EMH, has also been considered as a viable alternative to steam-based thermal processes.
The effective drilling and completion of a well consisting of a single parent/main bore with a junction leading to two or more lateral branches, also known as a multilateral well, can provide a further improvement in thermal recovery in appropriate situations. These wells can be vertical, horizontal or slanted in orientation. The junction can be placed at a variety of depths and in a variety of azimuthal directions, thus allowing the subsequent branches to reach different depths and in different directions. The significant advantage in applying this junction technology is to reduce the surface footprint thereby reducing cost, affected land area, and environmental disturbance.
The use of multilateral wells may provide improved recovery of heavy oil resources, but there are various challenges facing their implementation. In particular, controlling the performance of a single well can be difficult depending on the contextual specifics, but adding in one or more lateral branching wells complicates the system even further and makes performance control far more challenging.
Summary of the Invention The present invention therefore seeks to provide completion mechanisms for use with multilateral wells in thermal hydrocarbon recovery operations. Specifically, the following techniques are disclosed in the context of multilateral well systems:
= The use of mechanical restrictions such as steam splitters for injection wells and inflow control devices for production wells = The use of multilateral tubing strings following the path of the multilateral branches = The use of more than one pump to provide separate pressure points in the branches = The use of blank liners selected so as to restrict injection and/or production of fluid According to a first broad aspect of the present invention, there is provided a method for producing hydrocarbon from a subsurface reservoir, the method comprising the steps of:
drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the injection well;
determining an optimal local fluid flow level for regions along the injection well and the at least one lateral well;
providing flow control devices in each of the injection well and the at least one lateral well for positioning adjacent the regions, each of the flow control devices selected to allow the optimal fluid flow therethrough for the respective region;
INDIVIDUAL BRANCH CONTROL
Field of the Invention The present invention relates to thermal hydrocarbon recovery techniques, and particularly to the =
use of multilateral wells in hydrocarbon recovery.
Background of the Invention Heavy oil is a term commonly applied to describe oils having a specific gravity less than about degrees API. These oils, which include bitumen, are not readily producible by conventional techniques. Their viscosity is so high that the oil cannot easily be mobilized and driven to a production well by a pressure drive. Therefore, a recovery process is required to reduce the 15 viscosity and then produce the oil.
Thermal recovery methods as applied in heavy oil have the common objective of accelerating the recovery process. Raising the temperature of the host formation reduces the heavy oil viscosity allowing the near solid material at original temperature to flow as a liquid.
For heavy oil 20 reservoirs, steam injection from the surface into the formation is used as a conventional method to heat the heavy oil in situ, reducing its viscosity to a level where the oil is amenable to displacement. Typical methods of recovering oil from an oil sands reservoir include cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD).
Electromagnetic (EM) heating, or EMH, has also been considered as a viable alternative to steam-based thermal processes.
The effective drilling and completion of a well consisting of a single parent/main bore with a junction leading to two or more lateral branches, also known as a multilateral well, can provide a further improvement in thermal recovery in appropriate situations. These wells can be vertical, horizontal or slanted in orientation. The junction can be placed at a variety of depths and in a variety of azimuthal directions, thus allowing the subsequent branches to reach different depths and in different directions. The significant advantage in applying this junction technology is to reduce the surface footprint thereby reducing cost, affected land area, and environmental disturbance.
The use of multilateral wells may provide improved recovery of heavy oil resources, but there are various challenges facing their implementation. In particular, controlling the performance of a single well can be difficult depending on the contextual specifics, but adding in one or more lateral branching wells complicates the system even further and makes performance control far more challenging.
Summary of the Invention The present invention therefore seeks to provide completion mechanisms for use with multilateral wells in thermal hydrocarbon recovery operations. Specifically, the following techniques are disclosed in the context of multilateral well systems:
= The use of mechanical restrictions such as steam splitters for injection wells and inflow control devices for production wells = The use of multilateral tubing strings following the path of the multilateral branches = The use of more than one pump to provide separate pressure points in the branches = The use of blank liners selected so as to restrict injection and/or production of fluid According to a first broad aspect of the present invention, there is provided a method for producing hydrocarbon from a subsurface reservoir, the method comprising the steps of:
drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the injection well;
determining an optimal local fluid flow level for regions along the injection well and the at least one lateral well;
providing flow control devices in each of the injection well and the at least one lateral well for positioning adjacent the regions, each of the flow control devices selected to allow the optimal fluid flow therethrough for the respective region;
- 2 -injecting a fluid through the injection well and the at least one lateral well through the flow control devices and into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the production well.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
The step of determining the optimal local fluid flow level for the regions preferably comprises assessing the regions of the reservoir along the injection well and the at least one lateral well where fluid injection requires enhancement or restriction to optimize mobilization of the hydrocarbon.
The flow control devices are preferably steam splitters.
The fluid may be steam, a steam-solvent mixture or a non-condensable gas.
According to a second broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and flow control devices in each of the injection well and the at least one lateral well for allowing passage of an injected fluid therethrough, the flow control devices selected to allow an optimal fluid flow therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
The flow control devices are preferably steam splitters.
According to a third broad aspect of the present invention, there is provided a method for producing hydrocarbon from a subsurface reservoir, the method comprising the steps of:
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the production well.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
The step of determining the optimal local fluid flow level for the regions preferably comprises assessing the regions of the reservoir along the injection well and the at least one lateral well where fluid injection requires enhancement or restriction to optimize mobilization of the hydrocarbon.
The flow control devices are preferably steam splitters.
The fluid may be steam, a steam-solvent mixture or a non-condensable gas.
According to a second broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and flow control devices in each of the injection well and the at least one lateral well for allowing passage of an injected fluid therethrough, the flow control devices selected to allow an optimal fluid flow therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
The flow control devices are preferably steam splitters.
According to a third broad aspect of the present invention, there is provided a method for producing hydrocarbon from a subsurface reservoir, the method comprising the steps of:
- 3 -drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the production well;
determining an optimal local fluid flow level for regions along the production well and the at least one lateral well;
providing inflow control devices in each of the production well and the at least one lateral well for positioning adjacent the regions, each of the inflow control devices selected to allow the optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the inflow control devices and the production well and the at least one lateral well.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
The step of determining the optimal local fluid flow level for the regions preferably comprises assessing the regions along the production well and the at least one lateral well where production requires enhancement or restriction.
The fluid may be steam, a steam-solvent mixture or a non-condensable gas.
According to a fourth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and inflow control devices in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the inflow control devices selected to allow an optimal fluid flow therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the production well;
determining an optimal local fluid flow level for regions along the production well and the at least one lateral well;
providing inflow control devices in each of the production well and the at least one lateral well for positioning adjacent the regions, each of the inflow control devices selected to allow the optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the inflow control devices and the production well and the at least one lateral well.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
The step of determining the optimal local fluid flow level for the regions preferably comprises assessing the regions along the production well and the at least one lateral well where production requires enhancement or restriction.
The fluid may be steam, a steam-solvent mixture or a non-condensable gas.
According to a fourth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and inflow control devices in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the inflow control devices selected to allow an optimal fluid flow therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
- 4 -According to a fifth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a tubing string in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the tubing string in the at least one lateral well connected to the tubing string in the production well by a tubing junction tool to form a unitary production tubing string.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells. Each tubing string preferably comprises an associated packer assembly.
According to a sixth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a pump assembly in each of the production well and the at least one lateral well for pumping produced fluid, the pump assembly in the at least one lateral well comprising at least two pumps.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells. The at least two pumps of each pump assembly may run on separate individual tubing strings, or alternatively may run in series.
Each pump assembly may further comprise variable pumping rate means, which means preferably comprises a variable frequency drive.
According to a seventh broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a tubing string in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the tubing string in the at least one lateral well connected to the tubing string in the production well by a tubing junction tool to form a unitary production tubing string.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells. Each tubing string preferably comprises an associated packer assembly.
According to a sixth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a pump assembly in each of the production well and the at least one lateral well for pumping produced fluid, the pump assembly in the at least one lateral well comprising at least two pumps.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells. The at least two pumps of each pump assembly may run on separate individual tubing strings, or alternatively may run in series.
Each pump assembly may further comprise variable pumping rate means, which means preferably comprises a variable frequency drive.
According to a seventh broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
- 5 -an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and at least one blank liner in each of the injection well and the at least one lateral well for restricting passage of an injected fluid therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
According to an eighth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and at least one blank liner in each of the production well and the at least one lateral well for restricting passage of a produced fluid therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
One skilled in the art will also realize that the installation of electrical cables into the various branches of a well can be used to individually control the amount of energy deployed into each branch and section of a branch.
A detailed description of exemplary embodiments of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to these embodiments.
Brief Description of the Drawings In the accompanying drawings, which illustrate exemplary embodiments of the present invention:
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and at least one blank liner in each of the injection well and the at least one lateral well for restricting passage of an injected fluid therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
According to an eighth broad aspect of the present invention, there is provided a system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and at least one blank liner in each of the production well and the at least one lateral well for restricting passage of a produced fluid therethrough.
In some exemplary embodiments, the at least one lateral well is a plurality of lateral wells.
One skilled in the art will also realize that the installation of electrical cables into the various branches of a well can be used to individually control the amount of energy deployed into each branch and section of a branch.
A detailed description of exemplary embodiments of the present invention is given in the following. It is to be understood, however, that the invention is not to be construed as being limited to these embodiments.
Brief Description of the Drawings In the accompanying drawings, which illustrate exemplary embodiments of the present invention:
- 6 -Figure 1 is a schematic elevation view of a prior art injector well showing the use of steam splitters;
Figure 2a is a schematic elevation view of a prior art well with flow control devices;
Figure 2b is a schematic elevation view of a multilateral well configuration according to the present invention with flow control devices in both wells;
Figure 3a is a schematic elevation view of a prior art well with inflow control devices;
Figure 3b is a schematic elevation view of a multilateral well configuration according to the present invention with inflow control devices in both wells;
Figure 4a is a schematic elevation view of prior art wells with pumps; and Figure 4b is a schematic elevation view of a multilateral well configuration according to the present invention with two pumps in series in a wellbore.
Exemplary embodiments of the present invention will now be described with reference to the accompanying drawings.
Detailed Description of Exemplary Embodiments Throughout the following description specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the invention is not intended to be exhaustive or to limit the invention to the precise forms of any exemplary embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.
Figure 2a is a schematic elevation view of a prior art well with flow control devices;
Figure 2b is a schematic elevation view of a multilateral well configuration according to the present invention with flow control devices in both wells;
Figure 3a is a schematic elevation view of a prior art well with inflow control devices;
Figure 3b is a schematic elevation view of a multilateral well configuration according to the present invention with inflow control devices in both wells;
Figure 4a is a schematic elevation view of prior art wells with pumps; and Figure 4b is a schematic elevation view of a multilateral well configuration according to the present invention with two pumps in series in a wellbore.
Exemplary embodiments of the present invention will now be described with reference to the accompanying drawings.
Detailed Description of Exemplary Embodiments Throughout the following description specific details are set forth in order to provide a more thorough understanding to persons skilled in the art. However, well known elements may not have been shown or described in detail to avoid unnecessarily obscuring the disclosure. The following description of examples of the invention is not intended to be exhaustive or to limit the invention to the precise forms of any exemplary embodiment. Accordingly, the description and drawings are to be regarded in an illustrative, rather than a restrictive, sense.
- 7 -As was stated above, it is believed that the use of multilateral well techniques may provide advantages for hydrocarbon recovery, including in the field of thermal recovery of heavy oil from subsurface reservoirs. The exemplary embodiments of the present invention are directed to improvements related to the use of multilateral wells in thermal hydrocarbon recovery operations, and specifically to completion technologies in the context of multilateral well arrangements.
Exemplary methods and systems will now be disclosed in sufficient detail to allow someone skilled in the art to determine the best technique or combination of techniques for their individual reservoir and well configuration. It is well known to those skilled in the art that the specific completions techniques employed must be selected for the particular context including the nature of the reservoir.
The present invention involves the use of completion techniques to improve individual branch control in a multilateral well arrangement. While multilateral well arrangements are known in the art, the various lateral wells or branches are conventionally treated in the same manner as the main well. The present invention is directed to ways to provide enhanced control of the lateral wells or branches in an attempt to improve overall performance of the hydrocarbon production operation.
The description, including the drawings, is directed to a single lateral well, but it is understood that an individual main well could have several lateral wells extending therefrom.
Use of Flow Control Devices According to a first broad aspect of the present invention, there is provided a method for producing hydrocarbon from a subsurface reservoir comprising the use of flow control devices.
In one exemplary embodiment, the flow control devices are steam splitters connected to an injection well of a SAGD well pair and one or more lateral wells or branches extending from the injection well.
Exemplary methods and systems will now be disclosed in sufficient detail to allow someone skilled in the art to determine the best technique or combination of techniques for their individual reservoir and well configuration. It is well known to those skilled in the art that the specific completions techniques employed must be selected for the particular context including the nature of the reservoir.
The present invention involves the use of completion techniques to improve individual branch control in a multilateral well arrangement. While multilateral well arrangements are known in the art, the various lateral wells or branches are conventionally treated in the same manner as the main well. The present invention is directed to ways to provide enhanced control of the lateral wells or branches in an attempt to improve overall performance of the hydrocarbon production operation.
The description, including the drawings, is directed to a single lateral well, but it is understood that an individual main well could have several lateral wells extending therefrom.
Use of Flow Control Devices According to a first broad aspect of the present invention, there is provided a method for producing hydrocarbon from a subsurface reservoir comprising the use of flow control devices.
In one exemplary embodiment, the flow control devices are steam splitters connected to an injection well of a SAGD well pair and one or more lateral wells or branches extending from the injection well.
- 8 -Steam splitters are known for use in SAGD hydrocarbon recovery operations to direct steam to various target areas of a reservoir adjacent the well pair. For example, the use of steam splitters as part of an injection well is shown in Figure 1, which illustration is taken from a 2015 Annual Performance Presentation to the Alberta Energy Regulator for the present applicant's Sunrise Thermal Project, available at the time of the present application filing date at:
http iwww. aer. c aido cuments/oi lsandsinsitu-presentati o ns12015 A thab as calluskyS unri s eS AGD 10419 p d f. The steam splitter is labelled as a "port" in Figure 1. A further example of flow control devices in a SAGD
context is found in United States Patent Application Publication No. 2013/0213652, which teaches the use of inflow control devices in the improvement of conventional straight SAGD wells.
To control the distribution of steam in a single SAGD well as illustrated in Figure 1, engineers and geoscientists conventionally make a determination as to the most desirable steam placement by considering the geological parameters of porosity, water saturation, pay and permeability, with further consideration given to the kinematic viscosity of the oil, and hydraulic parameters of injecting steam into the well.
However, to control the distribution of steam in a branched SAGD well, engineers and geoscientists would have a much more complicated set of variables to consider, including steam distribution to a larger area, and hydraulics of the branched system including the potential for elevation changes between branches. The present invention provides a method and system enabling a desirable level of control over individual branches in an effort to improve overall operation performance.
Turning to Figure 2a, a prior art system 10 is illustrated. The prior art system 10 comprises a wellbore having a liner 12, with tubing 14 extending therethrough. The tubing 14 is provided with flow control devices 16 at spaced-apart locations along the horizontal leg of the tubing 14.
Turning now to Figure 2b, an exemplary system 20 according to the present invention comprises a well pair ¨ an injection well 22 and a production well (not shown) from the surface to the reservoir ¨ and one lateral well 24 off of the injection well 22. In some embodiments there may
http iwww. aer. c aido cuments/oi lsandsinsitu-presentati o ns12015 A thab as calluskyS unri s eS AGD 10419 p d f. The steam splitter is labelled as a "port" in Figure 1. A further example of flow control devices in a SAGD
context is found in United States Patent Application Publication No. 2013/0213652, which teaches the use of inflow control devices in the improvement of conventional straight SAGD wells.
To control the distribution of steam in a single SAGD well as illustrated in Figure 1, engineers and geoscientists conventionally make a determination as to the most desirable steam placement by considering the geological parameters of porosity, water saturation, pay and permeability, with further consideration given to the kinematic viscosity of the oil, and hydraulic parameters of injecting steam into the well.
However, to control the distribution of steam in a branched SAGD well, engineers and geoscientists would have a much more complicated set of variables to consider, including steam distribution to a larger area, and hydraulics of the branched system including the potential for elevation changes between branches. The present invention provides a method and system enabling a desirable level of control over individual branches in an effort to improve overall operation performance.
Turning to Figure 2a, a prior art system 10 is illustrated. The prior art system 10 comprises a wellbore having a liner 12, with tubing 14 extending therethrough. The tubing 14 is provided with flow control devices 16 at spaced-apart locations along the horizontal leg of the tubing 14.
Turning now to Figure 2b, an exemplary system 20 according to the present invention comprises a well pair ¨ an injection well 22 and a production well (not shown) from the surface to the reservoir ¨ and one lateral well 24 off of the injection well 22. In some embodiments there may
- 9 -be a number of lateral wells branching off of the injection well, although this will depend on the operation requirements as determinable by the skilled person. The wells 22, 24 are provided with liners 28a,b in a conventional manner. The system 20 further comprises flow control devices 26 in both the injection well 22 and the lateral well 24 for allowing passage of an injected fluid therethrough, the flow control devices 26 individually adjustable to allow a variable fluid flow therethrough. The flow control devices 26 are preferably controlled from surface using technology known to the skilled person.
As indicated above, these flow control devices 26 are preferably steam splitters, and the sizing of individual steam splitters would be dictated by the reservoir and operational context, which sizing may vary from one steam splitter to another along the length of the well.
In an exemplary method, the production well would be drilled from the surface to the reservoir, and the injection well 22 would also be drilled from the surface to the reservoir, the production well situated below the injection well 22 in a conventional SAGD arrangement.
Using multilateral well drilling techniques, the lateral well or branch 24 would be drilled off of the injection well 22. The skilled person would determine an optimal local fluid flow level for each of the regions of the reservoir along the well, and the flow control devices 26 would be selected accordingly based primarily on flowthrough passage size but also potentially other factors depending on the particular device design. To determine the optimal local fluid flow level for each of the flow control devices 26, the skilled worker would preferably assess the regions of the reservoir along the injection well 22 and the lateral well 24 where fluid injection requires enhancement or restriction to optimize mobilization of the hydrocarbon. The selected flow control devices 26 would then be provided in each of the injection well 22 and the lateral well 24 to allow the optimal fluid flow therethrough. Alternatively, in the event that flow control devices are available that allow an adjustable flowthrough passage, such could be used with the present invention and controlled from surface, as would be clear to one skilled in the art.
With the flow control devices 26 in place, a fluid ¨ which could be steam, a steam-solvent mixture or a non-condensable gas ¨ would be injected from surface down through the injection well 22 and the lateral well 24, and through the flow control devices 26. The injected fluid is
As indicated above, these flow control devices 26 are preferably steam splitters, and the sizing of individual steam splitters would be dictated by the reservoir and operational context, which sizing may vary from one steam splitter to another along the length of the well.
In an exemplary method, the production well would be drilled from the surface to the reservoir, and the injection well 22 would also be drilled from the surface to the reservoir, the production well situated below the injection well 22 in a conventional SAGD arrangement.
Using multilateral well drilling techniques, the lateral well or branch 24 would be drilled off of the injection well 22. The skilled person would determine an optimal local fluid flow level for each of the regions of the reservoir along the well, and the flow control devices 26 would be selected accordingly based primarily on flowthrough passage size but also potentially other factors depending on the particular device design. To determine the optimal local fluid flow level for each of the flow control devices 26, the skilled worker would preferably assess the regions of the reservoir along the injection well 22 and the lateral well 24 where fluid injection requires enhancement or restriction to optimize mobilization of the hydrocarbon. The selected flow control devices 26 would then be provided in each of the injection well 22 and the lateral well 24 to allow the optimal fluid flow therethrough. Alternatively, in the event that flow control devices are available that allow an adjustable flowthrough passage, such could be used with the present invention and controlled from surface, as would be clear to one skilled in the art.
With the flow control devices 26 in place, a fluid ¨ which could be steam, a steam-solvent mixture or a non-condensable gas ¨ would be injected from surface down through the injection well 22 and the lateral well 24, and through the flow control devices 26. The injected fluid is
- 10 -then allowed to mobilize the hydrocarbon in a conventional manner, and the target hydrocarbon can be produced to the surface through the production well.
By providing flow control devices ¨ steam splitters in the exemplary embodiment ¨ at various points on both the main injection well and the lateral well or wells, the operator can better control steam distribution throughout the entire branched injection system.
For example, the operator can consider the geology of the reservoir and adjust the steam injection accordingly.
Where, for example, a branched injection system is present in an area where shale layers predominate, the operator could use the steam splitters to limit steam injection in those areas by having a smaller steam splitter at that point on the tubing string. In an area with thick pay, in contrast, the operator could use a larger steam splitter to enable greater volume of steam injection in those areas. The operator is also better able to consider the vertical placement of the multiple branches so that the hydraulic weight of the fluid to be dispersed can be included in an appropriate design.
Use of Inflow Control Devices While the above exemplary aspect of the present invention addressed a system and method for controlling fluid injection into a branched SAGD operation, a multilateral well arrangement would also benefit from improved controls for production.
It is known in the art to provide variable production along the length of a production well using inflow control devices, such as for example the ResFlowTm devices available from Sehlumberger. The inflow control devices are selected by the person skilled in the art to accept flow from the various areas along the well which are determined to be beneficial for the distribution of flow along the entire well. Some considerations that an operator normally considers are the pay thickness above the production well, the offset distance between the injection well and production well, and the local reservoir properties including vertical permeability, water saturation and the presence, or lack of presence, of heterogeneities.
By providing flow control devices ¨ steam splitters in the exemplary embodiment ¨ at various points on both the main injection well and the lateral well or wells, the operator can better control steam distribution throughout the entire branched injection system.
For example, the operator can consider the geology of the reservoir and adjust the steam injection accordingly.
Where, for example, a branched injection system is present in an area where shale layers predominate, the operator could use the steam splitters to limit steam injection in those areas by having a smaller steam splitter at that point on the tubing string. In an area with thick pay, in contrast, the operator could use a larger steam splitter to enable greater volume of steam injection in those areas. The operator is also better able to consider the vertical placement of the multiple branches so that the hydraulic weight of the fluid to be dispersed can be included in an appropriate design.
Use of Inflow Control Devices While the above exemplary aspect of the present invention addressed a system and method for controlling fluid injection into a branched SAGD operation, a multilateral well arrangement would also benefit from improved controls for production.
It is known in the art to provide variable production along the length of a production well using inflow control devices, such as for example the ResFlowTm devices available from Sehlumberger. The inflow control devices are selected by the person skilled in the art to accept flow from the various areas along the well which are determined to be beneficial for the distribution of flow along the entire well. Some considerations that an operator normally considers are the pay thickness above the production well, the offset distance between the injection well and production well, and the local reservoir properties including vertical permeability, water saturation and the presence, or lack of presence, of heterogeneities.
- 11-Turning to Figure 3a, a prior art production well 30 provided with a liner 32 is illustrated, with production tubing 34 extending therethrough. The production tubing 34 is provided with inflow control devices 36 and packers 38 to isolate the regions along the well 30.
Figure 3b illustrates an exemplary embodiment of the present invention, in which a production system 40 comprises a main production well 42 and a lateral well 44 extending off of the production well 42, the production well 42 and the lateral well 44 housed within conventional liners 46a,b. As will be clear, more than one lateral well 44 may be run off the production well 42. The SAGD system would also include an injection well, not shown.
Production tubing 48 is run through the production well 42 and the lateral well 44.
The production tubing 48 in both the production well 42 and the lateral well 44 is provided with a plurality of inflow control devices 50, with packers 52 at appropriate locations as selected by the skilled person.
To enable enhanced control of the branched system, the system 40 positions the inflow control devices 50 in each of the production well 42 and the lateral well 44 for allowing passage of a produced fluid therethrough, such as for example oil and emulsion. The inflow control devices 50 are selected as a specific desirable size based on the determined optimal production flowthrough, as described below, but where inflow control devices having an adjustable flowthrough passage are available they may also be individually adjustable to a number of positions, between fully open and fully closed, from surface to allow a variable fluid flow therethrough.
In an exemplary method according to the present invention, the production well 42 and the injection well would be drilled from surface to the reservoir, and at least one lateral well 44 drilled off of the production well 42. The operator would determine an optimal local production flow for regions along the wells, and inflow control devices 50 would be selected accordingly.
The inflow control devices 50 would then be provided in both the production well 42 and the lateral well or wells 44 adjacent the respective regions.
Figure 3b illustrates an exemplary embodiment of the present invention, in which a production system 40 comprises a main production well 42 and a lateral well 44 extending off of the production well 42, the production well 42 and the lateral well 44 housed within conventional liners 46a,b. As will be clear, more than one lateral well 44 may be run off the production well 42. The SAGD system would also include an injection well, not shown.
Production tubing 48 is run through the production well 42 and the lateral well 44.
The production tubing 48 in both the production well 42 and the lateral well 44 is provided with a plurality of inflow control devices 50, with packers 52 at appropriate locations as selected by the skilled person.
To enable enhanced control of the branched system, the system 40 positions the inflow control devices 50 in each of the production well 42 and the lateral well 44 for allowing passage of a produced fluid therethrough, such as for example oil and emulsion. The inflow control devices 50 are selected as a specific desirable size based on the determined optimal production flowthrough, as described below, but where inflow control devices having an adjustable flowthrough passage are available they may also be individually adjustable to a number of positions, between fully open and fully closed, from surface to allow a variable fluid flow therethrough.
In an exemplary method according to the present invention, the production well 42 and the injection well would be drilled from surface to the reservoir, and at least one lateral well 44 drilled off of the production well 42. The operator would determine an optimal local production flow for regions along the wells, and inflow control devices 50 would be selected accordingly.
The inflow control devices 50 would then be provided in both the production well 42 and the lateral well or wells 44 adjacent the respective regions.
- 12 -With the inflow control devices 50 in place adjacent their respective regions, a fluid ¨ which could be steam, a steam-solvent mixture or a non-condensable gas ¨ would be injected from surface down through the injection well and allowed to mobilize the hydrocarbon in a conventional manner. The target hydrocarbon can then be produced to the surface through the inflow control devices 50 and both the production well 42 and the lateral well or wells 44.
The operator can consider the production well and the lateral well as a single system and give further attention to such considerations as the heterogeneity and geology throughout the system.
A further complicating factor in a multilateral system is the vertical displacement of the main production well and the lateral well. The hydraulic head of the production fluid must be factored into the determination of the appropriate placement for the packers and inflow control devices within this branched system.
The inflow control devices can be operated so as to distribute the inflow of emulsion from the production well and lateral wells as desired by the operator. One skilled in the art will realize that the single lateral well illustrated in Figure 3b for simplification can be extended to a multitude of branches.
Use of Multi-Branched Tubing Strings Turning now to Figures 2b and 3b, a yet further aspect of the present invention is illustrated, namely using multi-branched tubing strings to further enhance control of lateral wells in a multilateral well system.
According to the illustrated embodiments, the system comprises a well pair, namely an injection well and a production well, and at least one lateral well extending from either the injection well or the production well. In Figure 2b there is an injection well 22 (the production well not shown) and a lateral well 24 run off of the injection well 22. In Figure 3b there is a production well 42 (the injection well not shown) and a lateral well 44 run off of the production well 42.
The operator can consider the production well and the lateral well as a single system and give further attention to such considerations as the heterogeneity and geology throughout the system.
A further complicating factor in a multilateral system is the vertical displacement of the main production well and the lateral well. The hydraulic head of the production fluid must be factored into the determination of the appropriate placement for the packers and inflow control devices within this branched system.
The inflow control devices can be operated so as to distribute the inflow of emulsion from the production well and lateral wells as desired by the operator. One skilled in the art will realize that the single lateral well illustrated in Figure 3b for simplification can be extended to a multitude of branches.
Use of Multi-Branched Tubing Strings Turning now to Figures 2b and 3b, a yet further aspect of the present invention is illustrated, namely using multi-branched tubing strings to further enhance control of lateral wells in a multilateral well system.
According to the illustrated embodiments, the system comprises a well pair, namely an injection well and a production well, and at least one lateral well extending from either the injection well or the production well. In Figure 2b there is an injection well 22 (the production well not shown) and a lateral well 24 run off of the injection well 22. In Figure 3b there is a production well 42 (the injection well not shown) and a lateral well 44 run off of the production well 42.
- 13 -In each of those illustrations, the tubing string in the main well (either an injector or a producer) is connected to the tubing string in the lateral well. This connection is preferably by means of a tubing junction tool, and various types of such tools would be within the knowledge of the skilled person and clear based on the within teaching.
By connecting the tubing string in the lateral wells with the tubing string in the main well from which the laterals branch off, a unitary system is created for passage of fluid ¨ either injected fluid (such as steam) or produced fluid (such as oil).
Each tubing string preferably comprises an associated packer assembly where considered necessary by the operator.
Use of Multiple Pumps It is known in the art to use pumping equipment to control the inflow of production fluids.
Figure 4a illustrates a prior art system 60 comprising a main production well 62 and lateral well 64, the production well 62 having a liner 66 and the lateral well 64 having a liner 68. Production tubing 70, 72 is run into the liners 62, 64, and each of the tubing strings 70, 72 have a pump 74a,b.
However, in the context of multilateral well systems greater control may be achieved if a different pump arrangement is employed. According to another exemplary embodiment of the present invention, a system is provided for producing hydrocarbon from a subsurface reservoir, wherein pump assemblies are present in each of the main production well and the lateral branch well or wells, and the pump assembly in the lateral branch well comprises at least two pumps, thus allowing greater control of the individual lateral wells.
Turning to Figure 4b, an exemplary system 80 comprises an injection well (not shown) and a production well 82, with a lateral well 84 off of the production well 82. The production well 82 is provided with a liner 86 and the lateral well 84 is provided with a liner 88. A production
By connecting the tubing string in the lateral wells with the tubing string in the main well from which the laterals branch off, a unitary system is created for passage of fluid ¨ either injected fluid (such as steam) or produced fluid (such as oil).
Each tubing string preferably comprises an associated packer assembly where considered necessary by the operator.
Use of Multiple Pumps It is known in the art to use pumping equipment to control the inflow of production fluids.
Figure 4a illustrates a prior art system 60 comprising a main production well 62 and lateral well 64, the production well 62 having a liner 66 and the lateral well 64 having a liner 68. Production tubing 70, 72 is run into the liners 62, 64, and each of the tubing strings 70, 72 have a pump 74a,b.
However, in the context of multilateral well systems greater control may be achieved if a different pump arrangement is employed. According to another exemplary embodiment of the present invention, a system is provided for producing hydrocarbon from a subsurface reservoir, wherein pump assemblies are present in each of the main production well and the lateral branch well or wells, and the pump assembly in the lateral branch well comprises at least two pumps, thus allowing greater control of the individual lateral wells.
Turning to Figure 4b, an exemplary system 80 comprises an injection well (not shown) and a production well 82, with a lateral well 84 off of the production well 82. The production well 82 is provided with a liner 86 and the lateral well 84 is provided with a liner 88. A production
- 14 -tubing string 90 is run into the liner 86 of the production well 82, and a production tubing string 92 is run into the liner 88 of the lateral well 84.
The production tubing string 90 of the production well 82 is provided with a pump 94 to aid in producing fluid from the main production well 82. However, the production tubing string 92 of the lateral well 84 is provided with two pumps 96a,b in series.
While the pumps 96a,b are shown as running in series on a single tubing string 92, it is also possible to run each of the pumps on separate strings.
Also, each pump assembly may further comprise variable pumping rate means, which would preferably comprise a variable frequency drive.
This novel arrangement of pumps can be used to allow for the production of greater volumes of emulsion. Also, the operator can control the rates of the various pumps within the system by changing the current through a variable frequency drive, allowing for more flexibility in the system to account for changing operating characteristics.
Although only shown with respect to the lateral well, multiple pumps could also be employed within the production well.
Use of Blank Liners In a yet further exemplary embodiment of the present invention, blank liners are provided in the injection/production well and the lateral well to restrict the flow of injection/production fluids.
As described above with respect to flow control devices such as steam splitters (on an injection well and associated lateral well(s)) and inflow control devices (on a production well and associated lateral well(s)), restricting flow of injection fluid into a reservoir or flow of production fluid out of a reservoir may be advantageous to an operator. It is known to use blank liners in injection and production wells to substantially block flow of fluids.
The production tubing string 90 of the production well 82 is provided with a pump 94 to aid in producing fluid from the main production well 82. However, the production tubing string 92 of the lateral well 84 is provided with two pumps 96a,b in series.
While the pumps 96a,b are shown as running in series on a single tubing string 92, it is also possible to run each of the pumps on separate strings.
Also, each pump assembly may further comprise variable pumping rate means, which would preferably comprise a variable frequency drive.
This novel arrangement of pumps can be used to allow for the production of greater volumes of emulsion. Also, the operator can control the rates of the various pumps within the system by changing the current through a variable frequency drive, allowing for more flexibility in the system to account for changing operating characteristics.
Although only shown with respect to the lateral well, multiple pumps could also be employed within the production well.
Use of Blank Liners In a yet further exemplary embodiment of the present invention, blank liners are provided in the injection/production well and the lateral well to restrict the flow of injection/production fluids.
As described above with respect to flow control devices such as steam splitters (on an injection well and associated lateral well(s)) and inflow control devices (on a production well and associated lateral well(s)), restricting flow of injection fluid into a reservoir or flow of production fluid out of a reservoir may be advantageous to an operator. It is known to use blank liners in injection and production wells to substantially block flow of fluids.
- 15 -However, it is not known to use such blank liners as part of a system for providing enhanced individual control of lateral wells in a multilateral branched well system.
According to a further exemplary embodiment of the present invention, a system comprises an injector-producer well pair, and at least one lateral well off of the injection well. One or more blank liners are provided in each of the injection well and the lateral well(s) for restricting passage of an injected fluid therethrough. The blank liner would be positioned at a desirable location in the wells by the operator based on conventional knowledge and techniques.
According to a further exemplary embodiment of the present invention, a system comprises an injector-producer well pair, and at least one lateral well off of the production well. One or more blank liners are provided in each of the production well and the lateral well(s) for restricting passage of a produced fluid therethrough. The blank liner would be positioned at a desirable location in the wells by the operator based on conventional knowledge and techniques.
Both the main well (the injector or the producer, as the case may be) and the lateral well or wells can be configured with one, two or another specific number of blank liner joints to prevent steam from being injected or fluids from being produced. This might be useful, for example, in a production well that has been drilled along the base of geological pay to produce cellar oil.
During the steam stimulation phase, an operator does not want steam to reach the production well. In these sections, one or more blank liner joints could be placed.
As will be clear from the above, those skilled in the art would be readily able to determine obvious variants capable of providing the described functionality, and all such variants and functional equivalents are intended to fall within the scope of the present invention.
Specific examples have been described herein for purposes of illustration.
These are only examples. The technology provided herein can be applied to contexts other than the exemplary contexts described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes
According to a further exemplary embodiment of the present invention, a system comprises an injector-producer well pair, and at least one lateral well off of the injection well. One or more blank liners are provided in each of the injection well and the lateral well(s) for restricting passage of an injected fluid therethrough. The blank liner would be positioned at a desirable location in the wells by the operator based on conventional knowledge and techniques.
According to a further exemplary embodiment of the present invention, a system comprises an injector-producer well pair, and at least one lateral well off of the production well. One or more blank liners are provided in each of the production well and the lateral well(s) for restricting passage of a produced fluid therethrough. The blank liner would be positioned at a desirable location in the wells by the operator based on conventional knowledge and techniques.
Both the main well (the injector or the producer, as the case may be) and the lateral well or wells can be configured with one, two or another specific number of blank liner joints to prevent steam from being injected or fluids from being produced. This might be useful, for example, in a production well that has been drilled along the base of geological pay to produce cellar oil.
During the steam stimulation phase, an operator does not want steam to reach the production well. In these sections, one or more blank liner joints could be placed.
As will be clear from the above, those skilled in the art would be readily able to determine obvious variants capable of providing the described functionality, and all such variants and functional equivalents are intended to fall within the scope of the present invention.
Specific examples have been described herein for purposes of illustration.
These are only examples. The technology provided herein can be applied to contexts other than the exemplary contexts described above. Many alterations, modifications, additions, omissions and permutations are possible within the practice of this invention. This invention includes
- 16 -variations on described embodiments that would be apparent to the skilled person, including variations obtained by: replacing features, elements and/or acts with equivalent features, elements and/or acts; mixing and matching of features, elements and/or acts from different embodiments; combining features, elements and/or acts from embodiments as described herein with features, elements and/or acts of other technology; and/or omitting combining features, elements and/or acts from described embodiments.
The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiments set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.
The foregoing is considered as illustrative only of the principles of the invention. The scope of the claims should not be limited by the exemplary embodiments set forth in the foregoing, but should be given the broadest interpretation consistent with the specification as a whole.
- 17 -
Claims (27)
1. A method for producing hydrocarbon from a subsurface reservoir, the method comprising the steps of:
drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the injection well;
determining an optimal local fluid flow level for regions along the injection well and the at least one lateral well;
providing flow control devices in each of the injection well and the at least one lateral well for positioning adjacent the regions, each of the flow control devices selected to allow the optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well and the at least one lateral well through the flow control devices and into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the production well.
drilling a production well from surface to the reservoir;
drilling an injection well from the surface to the reservoir;
drilling at least one lateral well off of the injection well;
determining an optimal local fluid flow level for regions along the injection well and the at least one lateral well;
providing flow control devices in each of the injection well and the at least one lateral well for positioning adjacent the regions, each of the flow control devices selected to allow the optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well and the at least one lateral well through the flow control devices and into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the production well.
2. The method of claim 1 wherein the at least one lateral well is a plurality of lateral wells.
3. The method of claim 1 wherein the step of determining the optimal local fluid flow level for the regions comprises assessing the regions of the reservoir along the injection well and the at least one lateral well where fluid injection requires enhancement or restriction to optimize mobilization of the hydrocarbon.
4. The method of claim 1 wherein the flow control devices are steam splitters.
5. The method of claim 1 wherein the fluid is steam, a steam-solvent mixture or a non-condensable gas.
6. A system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and flow control devices in each of the injection well and the at least one lateral well for allowing passage of an injected fluid therethrough, the flow control devices selected to allow an optimal fluid flow therethrough.
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and flow control devices in each of the injection well and the at least one lateral well for allowing passage of an injected fluid therethrough, the flow control devices selected to allow an optimal fluid flow therethrough.
7. The system of claim 6 wherein the flow control devices are steam splitters.
8. The system of claim 6 wherein the at least one lateral well is a plurality of lateral wells.
9. A method for producing hydrocarbon from a subsurface reservoir, the method comprising the steps of:
drilling a production well from the surface to the reservoir;
drilling an injection well from surface to the reservoir;
drilling at least one lateral well off of the production well;
determining an optimal local fluid flow level for regions along the production well and the at least one lateral well;
providing inflow control devices in each of the production well and the at least one lateral well for positioning adjacent the regions, each of the inflow control devices selected to allow the optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the inflow control devices and the production well and the at least one lateral well.
drilling a production well from the surface to the reservoir;
drilling an injection well from surface to the reservoir;
drilling at least one lateral well off of the production well;
determining an optimal local fluid flow level for regions along the production well and the at least one lateral well;
providing inflow control devices in each of the production well and the at least one lateral well for positioning adjacent the regions, each of the inflow control devices selected to allow the optimal fluid flow therethrough for the respective region;
injecting a fluid through the injection well into the reservoir;
allowing the fluid to mobilize the hydrocarbon; and producing the hydrocarbon to the surface through the inflow control devices and the production well and the at least one lateral well.
10. The method of claim 9 wherein the at least one lateral well is a plurality of lateral wells.
11. The method of claim 9 wherein the step of determining the optimal local fluid flow level for the regions comprises assessing the regions of the reservoir along the production well and the at least one lateral well where production requires enhancement or restriction.
12. The method of claim 9 wherein the fluid is steam, a steam-solvent mixture or a non-condensable gas.
13. A system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and inflow control devices in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the inflow control devices selected to allow an optimal fluid flow therethrough.
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and inflow control devices in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the inflow control devices selected to allow an optimal fluid flow therethrough.
14. The system of claim 13 wherein the at least one lateral well is a plurality of lateral wells.
15. A system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a tubing string in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the tubing string in the at least one lateral well connected to the tubing string in the production well by a tubing junction tool to form a unitary production tubing string.
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a tubing string in each of the production well and the at least one lateral well for allowing passage of a produced fluid therethrough, the tubing string in the at least one lateral well connected to the tubing string in the production well by a tubing junction tool to form a unitary production tubing string.
16. The system of claim 15 wherein the at least one lateral well is a plurality of lateral wells.
17. The system of claim 15 wherein each tubing string comprises an associated packer assembly.
18. A system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a pump assembly in each of the production well and the at least one lateral well for pumping produced fluid, the pump assembly in the at least one lateral well comprising at least two pumps.
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and a pump assembly in each of the production well and the at least one lateral well for pumping produced fluid, the pump assembly in the at least one lateral well comprising at least two pumps.
19. The system of claim 18 wherein the at least one lateral well is a plurality of lateral wells.
20. The system of claim 18 wherein the at least two pumps of each pump assembly run on separate individual tubing strings.
21. The system of claim 18 wherein the at least two pumps of each pump assembly run in series.
22. The system of claim 18 wherein each pump assembly comprises variable pumping rate means.
23. The system of claim 22 wherein the variable pumping rate means comprises a variable frequency drive.
24. A system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and at least one blank liner in each of the injection well and the at least one lateral well for restricting passage of an injected fluid therethrough.
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the injection well; and at least one blank liner in each of the injection well and the at least one lateral well for restricting passage of an injected fluid therethrough.
25. The system of claim 24 wherein the at least one lateral well is a plurality of lateral wells.
26. A system for producing hydrocarbon from a subsurface reservoir, the system comprising:
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and at least one blank liner in each of the production well and the at least one lateral well for restricting passage of a produced fluid therethrough.
an injection well from surface to the reservoir;
a production well from the surface to the reservoir;
at least one lateral well off of the production well; and at least one blank liner in each of the production well and the at least one lateral well for restricting passage of a produced fluid therethrough.
27. The system of claim 26 wherein the at least one lateral well is a plurality of lateral wells.
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| US201462096048P | 2014-12-23 | 2014-12-23 | |
| US62/096,048 | 2014-12-23 |
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| CA2915661A Abandoned CA2915661A1 (en) | 2014-12-23 | 2015-12-21 | Multilateral well completions to improve individual branch control |
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| US (1) | US20160177685A1 (en) |
| CA (1) | CA2915661A1 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10292968B2 (en) | 2014-12-11 | 2019-05-21 | Zenith Epigenetics Ltd. | Substituted heterocycles as bromodomain inhibitors |
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10774625B2 (en) | 2018-01-19 | 2020-09-15 | Saudi Arabian Oil Company | Method of producing from a hydrocarbon bearing zone with laterals extending from an inclined main bore |
| US20240117723A1 (en) * | 2022-10-11 | 2024-04-11 | Saudi Arabian Oil Company | Mobilizing heavy oil |
-
2015
- 2015-12-21 CA CA2915661A patent/CA2915661A1/en not_active Abandoned
- 2015-12-22 US US14/978,117 patent/US20160177685A1/en not_active Abandoned
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US10292968B2 (en) | 2014-12-11 | 2019-05-21 | Zenith Epigenetics Ltd. | Substituted heterocycles as bromodomain inhibitors |
Also Published As
| Publication number | Publication date |
|---|---|
| US20160177685A1 (en) | 2016-06-23 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| FZDE | Discontinued |
Effective date: 20181227 |