Patent Application
20130220604
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
The present inventions relate to the formation of artificial fractures in a subsurface formation. More specifically, the inventions relate to the manipulation of in situ stresses within a subsurface formation in order to control the propagation of fractures from wells completed in the formation.
Natural resources sometimes reside in subsurface formations in the form of a fluid. Such natural resources include oil, gas, coal bed methane, and geothermal steam. Typically, such natural resources reside many feet below the surface.
In order to access hydrocarbon fluids or steam, one or more wellbores is formed from the surface down to the depth of the subsurface formation. The wellbore provides fluid communication between the surface and the subsurface formation. Fluids may then be transported to the surface, either by means of reservoir pressure, by means of artificial pressure, through pumping, or by combinations thereof.
The recovery of such natural resources is sometimes made difficult by the nature of the rock matrix in which they reside. In this respect, some rock matrices have very limited permeability. Examples of formations where the rock matrix has low permeability are the shale gas reservoirs found in North America. These include the Marcellus shale formation, the Barnett shale formation, the Haynesville shale formation, and the Horn River shale formation. Another example of a formation where the rock matrix has low permeability is the so-called tight gas sandstone and siltstone intervals found in the Piceance Basin.
It is well known in the oil and gas industry to increase permeability in a subsurface rock matrix through hydraulic fracturing. Hydraulic fracturing is a technique involving the injection of fluid under high pressure into a selected subsurface zone. The fluid is pumped into the wellbore, and then injected through perforations previously shot in production casing and into the surrounding rock matrix. Typically, the rock matrix is a hydrocarbon bearing formation. The fluid is injected at a pressure sufficient enough to create fractures within the rock matrix extending from the perforations. This pressure is sometimes referred to as a “parting” pressure or a “fracturing” pressure. Preferably, the fluid includes a proppant used to hold the fractures open after the fluid pressure is relieved.
A problem encountered with hydraulic fracturing is that the fractures do not always propagate from the wellbore in a direction that is optimal for well productivity or injection. Further, fractures may propagate from different zones in parallel orientations. This means that the fractures do not interconnect, and the artificial fluid channels created for fluid flow to the wellbore remain somewhat isolated.
The orientation of fractures in an underground formation is generally controlled by the in situ stress of the formation. It is known that subsurface formations are subjected to three principal stresses. These represent a vertical stress and two orthogonal horizontal stresses. When a formation is hydraulically fractured, the created fractures should propagate along a path of least resistance. Under principals of geomechanics, the path of least resistance should be in a direction that is perpendicular to the direction of least principal stress.
In deeper formations (generally, formations deeper than about 1,000 to 2,000 feet), one of the horizontal stresses is usually the smallest stress. Consequently, fractures tend to propagate vertically and/or horizontally perpendicular to the direction of least principal stress, the fractures together forming an approximately vertically oriented planar fracture. In other words, if the horizontal directions are the x and y axes and the vertical direction is defined by a z axis, and the direction of least principal stress is in the x direction, fractures would form in the y-z plane. This is also generally true for any naturally occurring fractures which may be present in the deeper formation.
Attempts have been made in the past to modify the direction in which fractures propagate. For example, in U.S. Pat. No. 5,111,881, entitled “Method to Control Fracture Orientation in Underground Formation,” it was proposed to first determine the anticipated fracture orientation of a hydrocarbon-bearing formation. The wellbore was then perforated in the anticipated direction of the fracture, and fluid was injected into the wellbore to form a first fracture. A substance was then injected into the first fracture which would temporarily harden. The formation was then perforated in a direction perpendicular to the original anticipated fracture orientation of the hydrocarbon bearing formation, and re-fractured to form a second fracture. It was believed that the second fracture would propagate in a direction away from that of the first fracture. The result was that independent fractures in two horizontal directions would be formed.
The '881 patent also suggested a modified arrangement to this process. The operator would first determine whether the stress field around a first hydraulic fracture would be altered to allow a reversal of the in situ stresses. The anticipated initial fracture orientation of the hydrocarbon-bearing formation is then determined. The formation is then perforated in a direction parallel to the anticipated fracture orientation, and also perforated in a direction perpendicular to the anticipated fracture orientation. The formation is then fractured in each of the two directions simultaneously.
U.S. Pat. Publ. No. 2009/0095482 and U.S. Pat. Publ. No. 2009/0194273 describe a method for orchestrating multiple subsurface fractures at multiple well locations in a region. This is done by flowing a well treatment fluid from a centralized well treatment fluid center. In operation, a fracture is formed at a first well location, and the effects of that fracture on stress fields within the formation are measured. Sensors disposed about the region are adapted to output effects on the stress fields. This process is then repeated for subsequent fractures. The location and orientation of subsequent fractures are based on the combined stress effects on the stress fields as a result of the prior fractures.
The above publications also disclose a method of servicing multiple well locations. The method includes the step of configuring a central location for the distribution of “well development task fluids to centralized service factories” through fluid lines. The method also includes preparing the treatment fluids at the centralized service factories, and treating wells with the treatment fluids according to well development tasks associated with each well.
As can be seen, the methods of the above publications focus on coordinating the flow of fluids from a centralized well treatment fluid center. The methods ostensibly provide for “optimal region development.”
U.S. Pat. No. 4,830,106 entitled “Simultaneous Hydraulic Fracturing,” describes the use of simultaneous fracturing to change fracture trajectories due to the pressurization of the formation. Fracturing is conducted in at least two wellbores simultaneously, causing the fractures to propagate in a direction contrary to the far-field in situ stresses. The fractures may curve away from each well or towards each well depending on the relative position and spacing of the wells in the stress field and the magnitude of the applied far field stresses. Preferably, the generated fractures will intercept at least one naturally-occurring fracture in the hydrocarbon-bearing interval.
U.S. Pat. No. 4,724,905, also entitled “Simultaneous Hydraulic Fracturing,” discloses the use of hydraulic fracturing in one well to control the direction of propagation of a second hydraulic fracture in a second well located nearby. The first well is fractured, with the fractures generally forming parallel to the fractures in the natural fracture system. The hydraulic pressure is maintained in the first well, and another hydraulic fracturing operation is conducted at the second well within a zone of anticipated in situ stress alteration caused by the first hydraulic fracture. Preferably, the second hydraulic fracture propagates at an angle that is substantially perpendicular to the first hydraulic fracture.
A need exists for an improved method of creating a network of fractures. More specifically, a need exists for a method of creating a fracture network wherein a desired fracture network system is determined for a group of wells or even for a field before all of the wells are completed. Further, a need exists for a method of producing hydrocarbons from a single deviated wellbore by manipulating in situ stresses through sequential producing and fracturing stages in the single wellbore.
A method of creating a network of fractures in a reservoir is first provided. The reservoir has an in situ stress field. The method has particular application to subsurface rock formations having a permeability that is less than 10 millidarcies.
In one embodiment, the method includes designing a desired fracture network system. The fracture network system represents a system of fractures or, alternatively, sets of fractures. The fractures are designed to interconnect within the reservoir. The step of designing a desired fracture network is done using geomechanical simulation, which involves use of a software program and a processor.
The method also includes determining required in situ stresses to create the desired fracture network within the reservoir. Determining required in situ stresses may be done by, for example, (i) reviewing downhole pressure measurements from existing wells, (ii) reviewing micro-seismic and/or tiltmeter monitoring conducted in existing wells, (iii) conducting downhole stress modeling, or (iv) combinations thereof.
The method further includes designing a layout of wells to alter the in situ stresses within the stress field. The layout may refer to the location of wellheads at the surface, the orientation of wellbores along the reservoir, the completion architecture, or combinations thereof.
The method additionally includes injecting a fracturing fluid under pressure into the reservoir. The purpose is to create an initial set of fractures within the reservoir. The fluid may be injected through wells completed for the production of hydrocarbon fluids. Alternatively or in addition, the fluid may be injected through wells completed for the injection of fluids, such as brine.
The method also includes monitoring the in situ stresses within the stress field. Monitoring may be done by, for example, (i) reviewing downhole pressure measurements from wells in the field, (ii) reviewing micro-seismic and/or tiltmeter monitoring conducted in wells in the field, (iii) conducting downhole stress modeling, or (iv) combinations thereof.
The method additionally includes updating the geomechanical simulation based on the monitored in situ stresses. Further, the method includes designing a program of modifying the in situ stress within the stress field. The step of designing a program is also done using geomechanical simulation.
The method further includes modifying the in situ stresses within the stress field. In one aspect, the modifying step is performed at least in part by producing hydrocarbon fluids from the reservoir. In another aspect, the modifying step is performed at least in part by injecting fluids into the reservoir. This injection is for the purpose of increasing pore pressure, and not to further fracture the reservoir. The injection of fluids may take place through a plurality of wells either simultaneously, or in stages such that fluid is injected into two or more wells sequentially.
Modifying the in situ stresses may further comprise (i) specifying a length of time for injecting for selected wells, (ii) specifying a viscosity of fluid for injection into selected wells, (iii) modifying a temperature of the reservoir, or (iv) combinations thereof. Alternatively, modifying the in situ stresses may comprise providing new perforations into the reservoir from selected wellbores, with the perforations being shot at a non-transverse angle relative to the wellbores.
The method then includes injecting a fracturing fluid under pressure into the reservoir in order to expand upon the initial set of fractures and to create the desired fracture network. Preferably, injecting a fluid under pressure into the reservoir comprises injecting a fluid through a plurality of wells that are part of the layout of wells.
In one aspect of the method, at least two wells in the layout of wells are completed for the production of hydrocarbon fluids. In this instance, the network of fractures is designed to optimize production of the hydrocarbon fluids. Optionally, injecting a fracturing fluid under pressure into the reservoir comprises injecting the fluid through the at least two wells completed for the production of hydrocarbon fluids. The method then further comprises producing hydrocarbon fluids from the wells completed for the production of hydrocarbon fluids after the initial set of fractures is created.
In another aspect, at least two wells in the layout of wells are completed for the injection of fluids as part of enhanced hydrocarbon recovery. The fluids may represent an aqueous fluid such as brine. In this instance, injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of fluids.
In yet another aspect, at least two wells in the layout of wells are completed for the production of geothermally-produced steam. In this instance, the network of fractures is designed to optimize heat transfer for geothermal applications. Injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the production of the geothermally-produced steam.
In still another aspect, at least two wells in the layout of wells are completed for the injection of acid gases. In this instance, injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of acid gases. The acid gases may comprise, for example, primarily carbon dioxide. The carbon dioxide may be injected as part of an enhanced hydrocarbon recovery project. Alternatively, the carbon dioxide may be injected as part of a sequestration operation. There, the network of fractures is designed to optimize CO2 storage capacity.
In yet another aspect, at least two wells in the layout of wells are completed for the injection of drill cuttings. In this instance, injecting a fluid under pressure into the reservoir comprises injecting the fluid through selected wells completed for the injection of drill cuttings.
A method of producing hydrocarbons from a subsurface formation is also provided herein. The formation has a permeability less than about 10 millidarcies.
In one embodiment, the method includes providing a wellbore in the subsurface formation. The wellbore has been formed as a deviated wellbore. Further, the wellbore has been perforated within the subsurface formation along at least a first zone and a second zone.
The method also includes fracturing the subsurface formation along the first and second zones. This forms a plurality of fractures extending from the wellbore in an approximately vertically oriented plane that is substantially perpendicular to the direction of least principal or minimum stress. Preferably the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation. In this instance, the fractures extend substantially transverse to the wellbore in an approximately vertically oriented plane, sometimes referred to herein as vertical fractures, that is substantially perpendicular to the direction of least principal or minimum stress.
The method then includes producing hydrocarbon fluids through the vertical fractures along the first and second zones.
The method further includes monitoring the wellbore. The wellbore is monitored to determine when a change in orientation of the maximum principal stress occurs within the subsurface formation along the first and second zones. Monitoring the wellbore may comprise (i) determining when a designated volume of hydrocarbon fluids have been produced from the wellbore; (ii) determining when a designated reduction in reservoir pressure within the subsurface formation has taken place; (iii) determining when a selected period of time of production has taken place; (iv) determining whether micro-seismic and/or tiltmeter readings indicate a change in in situ stresses; (v) or combinations thereof.
The method also includes injecting a fracturing fluid into the subsurface formation. The fluid is injected through perforations in the first and second zones. This creates a first set of new fractures within the subsurface formation that at least partially extends from the vertical fractures along a plane that is substantially transverse to, or at least angled away from, the vertical fractures. The new fractures are still located within an approximately vertically oriented plane, but the plane of the new fractures is at an angle to the vertically oriented planar network of the originally created fractures. The method further includes producing hydrocarbons through the first set of new fractures and through the vertical fractures along the first and second zones.
Preferably, the wellbore has further been perforated within the subsurface formation along a third zone. In this instance,
In one aspect, the method further comprises injecting a fracturing fluid into the subsurface formation through perforations in the first, second, and (optional) third zones. This creates a second set of new fractures within the subsurface formation that at least partially extend from the (i) vertical fractures, (ii) the first set of new fractures, or (iii) both. The fractures in the second new set of fractures extend along a plane that may be substantially transverse to, or at least at an angle to, the vertical fractures. The method then further includes producing hydrocarbons through (i) the second set of new fractures, (ii) the first set of new fractures, and (iii) the vertical fractures along the first, second, and (optional) third zones.
The perforations along the first zone, the second zone, and the third zone are separated. For example, separation may be by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters). In addition, the vertical fractures may extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.
In a related aspect, the method further comprises:
Other aspects of methods of producing hydrocarbons from a subsurface formation are also provided herein. Once again, the formation has a permeability less than about 10 millidarcies.
In some implementations, the method includes providing a wellbore in the subsurface formation. The wellbore has been completed as a deviated wellbore. Further, the wellbore has been perforated within the subsurface formation along at least a first zone and a second zone.
The method also includes fracturing the subsurface formation along the first and second zones. This forms a plurality of fractures formed in a vertical plane, referred to herein as vertical fractures, extending from the wellbore. Preferably the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation. In this instance, the vertical fractures extend substantially transverse to the wellbore.
The method then includes producing hydrocarbon fluids through the vertical fractures along the first and second zones.
The method also includes injecting a fluid into the subsurface formation. The fluid is injected through perforations in the second zone. This serves to raise the reservoir pressure in the subsurface formation along the first zone, and also causes a change in the in situ stresses within the subsurface formation along the first zone. It is noted that the fluid is not injected at a pressure in excess of the formation parting pressure.
The method further includes injecting a fluid into the subsurface formation through perforations in the first zone. In this instance, fluid injection causes a propagation of fractures in the subsurface formation along the first zone at least partially towards the second zone.
The method also includes producing hydrocarbons through the perforations along the first zone. The method may further include producing hydrocarbons through the perforations along the second zone along with the production of hydrocarbons from the first zone.
In one aspect, the method further comprises monitoring the wellbore to determine when a change in maximum principal stress may occur within the subsurface formation along the first zone as a result of injecting the fluid into the second zone. Monitoring the wellbore may be done by (i) determining when a designated volume of hydrocarbon fluids have been produced from the first zone; (ii) determining when a designated reduction in reservoir pressure within the subsurface formation along the first zone has taken place; (iii) determining when a selected period of time of production has taken place; (iv) determining whether micro-seismic and/or tiltmeter readings indicate a change in in situ stresses; (v) determining when a selected volume of fluid has been injected into the subsurface formations through the perforations in the second zone; or (vi) combinations thereof.
Preferably, the wellbore has further been perforated within the subsurface formation along a third zone. In this instance,
The method then further comprises:
The method may also include producing hydrocarbons through the perforations along the first and second zones along with the production of hydrocarbons from the third zone.
The perforations along the first zone, the second zone, and the optional third zone are separated. For example, separation may be by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters). In addition, the fractures may extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.
In some implementations, the method further comprises:
In some implementations, the method further comprises:
So that the present inventions can be better understood, certain drawings, charts, graphs and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.
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As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Hydrocarbons generally fall into two classes: aliphatic, or straight chain hydrocarbons, and cyclic, or closed ring, hydrocarbons including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.
As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions or at ambient conditions (15° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, coalbed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.
As used herein, the terms “produced fluids” and “production fluids” refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, oil, pyrolyzed shale oil, gas, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide and water (including steam).
As used herein, the term “fluid” refers to gases, liquids, and combinations of gases and liquids, as well as to combinations of gases and solids, combinations of liquids and solids, and combinations of gases, liquids, and solids.
As used herein, the term “gas” refers to a fluid that is in its vapor phase at 1 atm and 15° C.
As used herein, the term “oil” refers to a hydrocarbon fluid containing primarily a mixture of condensable hydrocarbons.
As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.
The term “zone of interest” refers to a portion of a formation containing hydrocarbons.
As used herein, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation.
As used herein, the term “hydrocarbon-rich formation” refers to any formation that contains more than trace amounts of hydrocarbons. For example, a hydrocarbon-rich formation may include portions that contain hydrocarbons at a level of greater than 5 percent by volume. The hydrocarbons located in a hydrocarbon-rich formation may include, for example, oil, natural gas, heavy hydrocarbons, and solid hydrocarbons.
As used herein, the term “organic-rich rock” refers to any rock matrix holding solid hydrocarbons and/or heavy hydrocarbons. Rock matrices may include, but are not limited to, sedimentary rocks, shales, siltstones, sands, silicilytes, carbonates, and diatomites. Organic-rich rock may contain kerogen.
As used herein, the term “hydraulic fracture” refers to a fracture at least partially propagated into a formation, wherein the fracture is created through injection of pressurized fluids into the formation. While the term “hydraulic fracture” is used, the inventions herein are not limited to use in hydraulic fractures. The invention is suitable for use in any fracture created in any manner considered to be suitable by one skilled in the art. The fracture may be artificially held open by injection of a proppant material. Hydraulic fractures may be substantially horizontal in orientation, substantially vertical in orientation, or oriented along any other plane.
As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shapes. As used herein, the term “well”, when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”
The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.
The wellbore 100 includes a wellhead, shown schematically at 120. The wellhead 120 contains various items of flow control equipment such as a lower master fracturing valve 122 and an upper master fracturing valve 124. It is understood that the wellhead 120 will include other components during the formation and completion of the wellbore 100, such as a blowout preventer (not shown). In a subsea context, the wellhead may also include a lower marine riser package.
The wellbore 100 has been completed by setting a series of pipes into the subsurface 110. These pipes include a first string of casing 130, sometimes known as surface casing or a conductor. These pipes also include a final string of casing 150, known as a production casing. The pipes also include one or more sets of intermediate casing 140. Typically, the string of surface casing 130 and the intermediate string of casing 140 are set in place using a cement sheath. A cement sheath 135 is seen isolating the subsurface 110 along the surface casing 130, while a cement sheath 145 is seen isolating the subsurface 110 along the intermediate casing 140.
The illustrative wellbore 100 is completed horizontally. A horizontal portion is shown at 160. The horizontal portion 160 has a heel 162. The horizontal portion 160 also has a toe 164 that extends through a hydrocarbon-bearing interval 170. While the wellbore 100 is shown as a horizontal completion, it is understood that the present inventions have equal application in deviated wells that extend through more than one zone of interest.
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For the illustrative wellbore 100, the production casing 150 represents a liner. This means that the casing 150 does not extend back to the surface 101, but is hung from an intermediate string of casing 140 using a liner hanger 152. The production casing 150 extends substantially to the toe 164 of the wellbore 100, and is cemented in place with a cement sheath 155.
The horizontal portion 160 of the wellbore 100 extends for many hundreds of feet. For example, the horizontal portion 160 may extend for over 250 feet, or over 1,000 feet, or even more than 5,000 feet. Extending the horizontal portion 160 of the wellbore 100 such great distances increases the exposure of the low-permeability formation 170 to the wellbore 100.
To permit the in-flow of hydrocarbon fluids from the formation 170 into the production casing 150, the production casing 150 is perforated. Perforations are shown at 157. While only three sets of perforations 157 are shown, it is understood that the horizontal portion 160 may have many more sets of perforations 157.
In preparation for the production of hydrocarbons, the operator may wish to stimulate the formation 170 by circulating an acid solution. This serves to clean out residual drilling mud both along the wall of the borehole 105 and into the near-wellbore region (the region within formation 170 close to the production casing 150). In addition, the operator may wish to fracture the formation 170. This is done by injecting a fracturing fluid under high pressure through the perforations 157 and into the formation 170. The fracturing process creates fissures 159 along the formation 170 to enhance fluid flow into the production casing 150.
To facilitate the injection of fracturing fluid and stimulation fluid into the formation 170, the wellbore 100 may be apportioned into sections or zones. In the illustrative wellbore 100 of
It is desirable to increase the complexity of fractures 159 in the formation 170. This increases the exposure of the rock matrix making up the formation 170 to the perforations 157 and, hence, to the bore 105. Therefore, a process is provided herein whereby fractures may be incrementally formed within the formation 170 at different axes and angles. Illustrative steps for such a process, in one embodiment, are shown in
The subsurface formation 250 represents a rock matrix having limited permeability. For example, the formation may have a permeability less than about 10 millidarcies. The subsurface formation represents a hydrocarbon-producing reservoir such as a tight-gas formation, a shale gas formation, or a coal bed methane formation. The reservoir may contain methane along with so-called acid gases such as carbon dioxide and hydrogen sulfide. The reservoir may also incidentally contain water or brine.
The wellbore 200 includes a string of casing 202. The casing 202 has been cemented into the formation 250. A cement sheath 204 is shown cut away in each of
The benefit of bifurcating the bore 205 is that it permits the operator to alternatively produce fluids from and inject fluids into the subsurface formation 250. This may be done without running alternating strings of production tubing and injection tubing into and out of the casing 202. However, the methods claimed below permit either the use of a bifurcated tubular body or the cyclical running of production and tubing strings. Further, the claims allow for the placement of both a tubing string and an injection string together within the bore 205 of the casing (as shown in
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It is noted that each of the fractures 214′, 224′, 234′ creates a first zone of production. This is indicated schematically in
In accordance with one of the methods of producing hydrocarbons herein, the wellbore 200 is monitored during production. Particularly, the wellbore 200 is monitored to determine when a change in the orientation of maximum principal stress may occur within the subsurface formation 250.
The wellbore 200 may be monitored in various ways. For example, monitoring the wellbore 200 may comprise determining when a designated volume of hydrocarbon fluids have been produced from the wellbore 200. Alternatively, monitoring the wellbore 200 may comprise determining when a designated reduction in reservoir pressure within the subsurface formation 250 has taken place. This may be done through reservoir simulation or may be based on experience with existing wells in the field.
Alternatively still, monitoring the wellbore 200 may comprise determining when a selected period of time of production has taken place. And alternatively still, monitoring the wellbore 200 may comprise determining whether micro-seismic readings or tilt-meter readings indicate a change in in situ stresses. Combinations of these techniques are preferably employed.
The direction in which the new fractures 214″, 224″, and 234″ propagate should be re-emphasized. Because of the change in maximum principal stress within the subsurface formation 250, the new fractures 214″, 224″, 234″ will at least initially extend away from the planes of the original vertical fractures 214′, 224′, and 234′. However, as the new fractures 214″, 224″, and 234″ propagate away from the vertical fractures 214′, 224′, 234′, they move through a transition area of maximum principal stress and begin to bend back so that the plane formed by the new fractures 214″, 224″, and 234″ is in approximate alignment or parallel with the plane formed by the original vertical fractures 214′, 224′ and 234′.
The fluids from the various zones 210, 220, 230 are commingled within the second section 245 of the casing 202. From there, production fluids flow toward the surface according to arrow “P.”
It is noted that in connection with each zone 210, 220, 230, the new fractures 214″, 224″, 234″ create respective second zones of production. This is indicated schematically in
In accordance with one of the methods of producing hydrocarbons herein, the wellbore 200 is once again monitored during production. Particularly, the wellbore 200 is monitored to determine when a change in the orientation of maximum principal stress may once again occur within the subsurface formation 250.
Each of the second new fractures 214″′, 224″′, 234″′ extends at least partially in a direction that is transverse to the respective vertical fractures 214′, 224′, 234′. This is because of the change in maximum principal stress within the subsurface formation 250. The result is that the complexity of the fracture network within the subsurface formation 250 has beneficially increased. However, as the second new fractures 214″′, 224″′, and 234″′ propagate away from the vertical fractures 214′, 224′, 234′, they move through a transition area of maximum principal stress and begin to bend back so that the plane formed by the new fractures 214″′, 224″′, and 234″′ is in approximate alignment or parallel with the plane formed by the original vertical fractures 214′, 224′ and 234′, just as the first new fractures 214″, 224″, 234″ did.
The fluids from the various zones 210, 220, 230 are commingled within the second section 245 of the casing 202. From there, production fluids flow toward the surface according to arrow “P.”
It is noted that in connection with each zone 210, 220, 230, the new fractures 214″′, 224″′, 234″′ create respective third zones of production. This is indicated schematically in
As can be seen, multiple cycles of fracturing, producing, and monitoring may be employed in order to create an ever-expanding network of fractures. However, in low-permeability formations the fracture networks created within the separate zones may or may not interconnect. Accordingly, an additional optional fracturing step may be employed. That step involves the placement of additional perforations and corresponding fractures intermediate to the first 210, second 220, and/or third 230 zones.
It is preferred that the perforations 262, 272 be oriented at an angle that is non-transverse to the casing 202. In this way, fractures 264, 274 are at least initially propagated at an angle, and may intersect with fractures in adjoining zones.
The method 300 has application to subsurface formations with limited permeability. The method 300 is particularly beneficial to formations having a permeability less than about 10 millidarcies. According to the method 300, the subsurface formation represents a hydrocarbon-producing reservoir such as a tight-gas formation, a shale gas formation, or a coal bed methane formation. The reservoir may contain methane along with so-called acid gases such as carbon dioxide and hydrogen sulfide.
The method 300 first includes providing a wellbore in the subsurface formation. This is shown at Box 305. The wellbore has been formed as a deviated wellbore. Preferably, the deviated wellbore is completed as a substantially horizontal wellbore within the subsurface formation.
For purposes of this disclosure, the term “providing” is intended to be broad. “Providing” a wellbore means that the wellbore has been drilled by a government, by a company, or by an individual, association, or partnership. Alternatively, “providing” may mean that a drilling company or a service company has drilled the wellbore at the request or direction of a government, a company, or an individual, association or partnership. Alternatively still, “providing” may mean that a government, an individual, an association, or a business concern has purchased the wellbore. In any instance, the wellbore has been perforated within the subsurface formation along at least a first zone and a second zone. The wellbore may have been perforated by the owner, the lessor, or by a service company or business affiliate on behalf of the owner or lessor.
The method 300 also includes fracturing the subsurface formation along the first and second zones. This is provided at Box 310. Fracturing the formation along these zones creates one or more substantially vertical fractures extending from the wellbore. Where the wellbore is substantially horizontal, the fractures will be transverse to the wellbore, oriented in a vertical plane.
The method 300 further includes producing hydrocarbon fluids through the vertical fractures along the first and second zones. This is seen at Box 315. In one aspect, the vertical fractures extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore. Of course, non-hydrocarbon fluids such as water and carbon dioxide may be incidentally produced along with the hydrocarbon fluids.
The method 300 also includes monitoring the wellbore. This is provided at Box 320. Monitoring the wellbore is conducted to determine when a change in the direction or orientation of maximum principal stress may occur within the subsurface formation along the first and second zones. The wellbore may be monitored in a number of different ways as discussed above.
The method 300 additionally includes injecting a fracturing fluid into the subsurface formation. This is provided at Box 325. The fluid is preferably a hydraulic fluid such as brine. However, liquid CO2, foamed nitrogen, or other non-reactive fluids may also be injected. The fluid is injected through perforations in the first and second zones. This serves to create first new fractures within the subsurface formation that at least partially extend from the vertical fractures along a plane that is substantially transverse to, or at least at an angle to, the vertical fractures.
The method 300 also includes producing hydrocarbons. This is shown at Box 330. Hydrocarbon fluids are produced through the first new fractures and through the vertical fractures along the first and second zones.
The method 300 as described above only recites two zones. However, the method 300 may include more than two zones. In one aspect, the wellbore is perforated to create new perforations along a third zone. This is provided at Box 335. Perforations may be provided along the first zone, the second zone, and a third zone, with the zones being separated by a distance of between, for example, about 20 feet (6.1 meters) and 500 feet (152.4 meters). The perforations along the third zone may be provided at the same time as the perforations along the first and second zones or at a later time. Accordingly, it should be understood that the methods 300 described herein may be applicable on any number of zones, including two or more zones. Additionally or alternatively, the methods 300 described herein may be implemented on multiple zones in either a simultaneous manner or in a sequential manner. For convenience in describing the methods herein, the multiple zones are referenced by ordinals such as first, second, third, etc. It should be understood that reference to a first zone in an illustration is exemplary of any of the other zones and is merely for identification purposes and for description of one zone relative to another. The principles and steps of the methods described herein may be applied with respect to any one or more zones in a wellbore.
Accordingly, in some implementations, the method 300 may then include fracturing the subsurface formation along the third zone to form additional vertical fractures extending from the wellbore. This is seen at Box 340.
Where a third zone is perforated, the method 300 also includes producing hydrocarbon fluids through the vertical fractures in the third zone. This is shown at Box 345. During production, the wellbore continues to be monitored. Hence, monitoring the wellbore further comprises monitoring the wellbore to determine when a change in orientation of maximum principal stress may occur within the subsurface formation along the third zone. This is seen at Box 350. In this embodiment, production from the third zone preferably takes place simultaneously with production from the first and second zones. In other words, the production steps in Boxes 315 and 350 may overlap.
Where a third zone is perforated, the method 300 also includes injecting a fracturing fluid through perforations in the third zone. This is provided at Box 355. The injection step of Box 355 may be done simultaneously with the injection step of Box 325. In addition, the method 300 includes producing hydrocarbons through the first set of new fractures along the third zone. This is shown at Box 360. The production step of Box 360 is preferably done simultaneously with the production step of Box 330.
It is noted here that still additional zones may optionally be perforated, fractured, and produced in accordance with the steps described above. For example, new perforations may be formed in a selected zone, as shown in Box 365 of
The perforating 365 and fracturing 370 steps may be conducted in stages with the first, second, and third zones using multi-interval procedures. For the present method 300, the injection stages may be aided through the use of packers, fracturing ports, mechanical plugs, sand plugs, sliding sleeves, and other devices known in the art. Hydrocarbon fluids are then produced through the perforations along the selected zone.
It is also noted that additional cycles of fracturing, producing, and monitoring may be undertaken. Thus, the method 300 may include the step of injecting a fracturing fluid into the subsurface formation through perforations in the first, second, and third zones, thereby creating a second new set of fractures within the subsurface formation. The second new fractures will at least partially extend from the vertical fractures. Alternatively or in addition, the second new fractures will at least partially extend from the first new fractures as shown and discussed in connection with
The method 300 allows for the creation of a complex network of fractures using only a single wellbore. In the method 300, the wellbore may be divided into a plurality of zones, with the zones being fractured and produced from together. However, it is also proposed herein to create a complex network of fractures from a single wellbore wherein the various zones are not always fractured and produced from together. This is demonstrated through a process shown in
The wellbore 400 includes a string of casing 402. The casing 402 has been cemented into the formation 450. A cement sheath 404 is seen in cut-away view in each of
The benefit of using separate strings 440, 445 within the bore 205 is that it permits the operator to alternatively inject fluids into and produce fluids from the subsurface formation 450. This may be done without running alternating strings of production tubing and injection tubing into and out of the casing 402. However, the methods claimed below also permit the use of a bifurcated tubular body or the cyclical running of production and tubing strings as discussed above.
In
In each of
In
It is noted that each of the fractures 414′, 424′, 434′ creates a first zone of production. This is indicated schematically in
It is noted that the injection of fluids into the subsurface formation, denoted by arrows 428, is at a lower pressure than the injection of fluids for fracturing purposes. The injection of fluids under the higher fracturing pressures is denoted by arrows 426 (seen in
At the same time as fluids are injected into the second zone 420, production continues in the first 410 and third 430 zones. The production of fluids is indicated by production arrow “P.” The simultaneous production and injection of fluids requires the use of separate flow paths. Such an approach is provided through the separate first 440 and second 445 tubing strings. Alternatively, this may be provided through separate flow-channels specially machined in a tubular body as shown at 240, 245 in
In one aspect, the step of
The wellbore 400 may be monitored in various ways. For example, monitoring the wellbore 400 may comprise determining when a designated volume of hydrocarbon fluids have been produced from the wellbore 400. Alternatively, monitoring the wellbore 400 may comprise determining when a designated reduction in reservoir pressure within the subsurface formation 450 has taken place. This may be done through reservoir simulation, or may be based on experience with existing wells in the field.
Alternatively still, monitoring the wellbore 400 may comprise determining when a selected period of time of production has taken place, or when a selected period of injection has taken place. And alternatively still, monitoring the wellbore 400 may comprise determining whether micro-seismic readings or tilt-meter readings indicate a change in in situ stresses. Combinations of these techniques are preferably employed.
In any event, at some point it is determined that in situ stresses in the subsurface formation 450 within the first zone 410 and the third zone 430 have changed. More specifically, the orientation of maximum principal stress has changed.
The fluid is injected into the subsurface formation 450 under high pressure. The result is that new fractures are formed in the subsurface formation 450 along the first 410 and third 430 zones. This again is indicated by fracture injection arrows 416 and 436. At the same time, fluid is optionally also injected at a lower pressure into the subsurface formation 450 along the second zone 420. This is indicated by fluid injection arrows 428.
New fractures in the first zone 410 are seen at 414″. The new fractures 414″ in the first zone 410 largely extend from the original vertical fractures 414′ in that zone 410. New fractures in the third zone 430 are seen at 434″. The new fractures 434″ in the third zone 430 largely extend from the original vertical fractures 434′ in that zone 430. Each of the new fractures 414″, 434″ extends at least partially in a direction that is transverse to the respective vertical fractures 414′, 434′. This is because of the change in maximum principal stress within the subsurface formation 450. The result is that the complexity of the fracture network within the subsurface formation 450 has beneficially increased, even by using just a single wellbore 400.
The direction in which the new fractures 414″ and 434″ propagate should be re-emphasized. Because of the change in maximum principal stress within the subsurface formation 450, the new fractures 414″, 434″ will at least initially extend away from the planes of the original vertical fractures 414′, 434′. However, as the new fractures 414″, 444″ propagate away from the vertical fractures 414′, 434′, they move through a transition area of maximum principal stress and begin to bend back in so that the plane formed by the new fractures 414″ and 444″ is in approximate alignment or parallel with the plane formed by the original vertical fractures 414′ and 434′.
The fluids received from the various zones 410, 420, 430 are commingled within the second tubing string 445 of the casing 402. From there, production fluids flow toward the surface according to arrow “P.”
It is noted that in connection with each zone 410, 420, 430, the new fractures 414″ and 434″ create respective second zones of production. This is indicated schematically in
The second zone 420 is also in production. However, the zone of production is still the first zone 425′. It is possible though using the current method and the singular wellbore 400 to increase the size of the zone of production along the second zone 420. This is shown in the steps provided in
The injection of fluid into the subsurface formation 450 along the first zone 410 is not for the purpose of fracturing the formation 450, but just to build reservoir pressure. In this way, the orientation of the maximum principal stress along the second zone 420 is ultimately changed.
In one aspect, the step of
At the same time as fluids are injected into the second zone 420, production continues in the third 430 zone. The production of fluids is indicated by production arrow “P.” As noted above, the simultaneous production and injection of fluids requires the use of separate flow paths. Such an approach is illustratively provided in
Of note, a second zone of production 425″ is now provided along the second zone 420. This is indicated schematically as a circle in
The injection of fluid into the subsurface formation 450 along the third zone 430 is not for the purpose of fracturing the formation 450, but just to build reservoir pressure. In this way, the orientation of the maximum principal stress along the second zone 420 is ultimately changed. During this time, production may continue in the second zone 420. Production fluids leave the subsurface formation through perforations 422 and according to production arrow “P.”
At the same time as fluids are injected into the second zone 420, production may continue in the first zone 410. The production of fluids is indicated by production arrow “P.” As noted above, the simultaneous production and injection of fluids requires the use of separate flow paths. Such an approach is provided in
The direction in which the new fractures 424″ propagate should be re-emphasized. Because of the change in maximum principal stress within the subsurface formation 450, the new fractures 424″ will at least initially extend away from the planes of the original vertical fractures 424′. However, as the new fractures 424″ propagate away from the vertical fractures 424′, they move through a transition area of maximum principal stress and begin to bend back so that the plane formed by the new fractures 424″ is in approximate alignment or parallel with the plane formed by the original vertical fractures 424′.
Hydrocarbon fluids are being produced from the subsurface formation 450 along each of the first 410, second 420, and third 430 zones. Fluids flow from the subsurface formation 450, through the new transverse fractures 414″, 424″, 434″, through the vertical fractures 414′, 424′, 434′, and through the respective perforations 412, 422, 432. From there, production fluids flow through tubing string 445 within the casing 402, and towards the surface according to production arrow “P.”
It is noted that the steps shown in
It is further noted that the wellbore 400 with its three zones 410, 420, 430 is merely illustrative. The steps presented incident to the wellbore 400 may be taken through just two adjoining zones without the presence of a third zone. Alternatively, there may be more than three zones. As discussed above, the use of three zones and the nomenclature used to refer to the individual zones is for explanatory purposes. The order of operations on the individual zones may be independent of the ordinal assigned to the zone. For example, while a step is illustrated and discussed as being performed on a first zone relative to a second zone, the step may be performed on the second relative to the first, the second relative to the third, the fifth relative to the sixth, or any other pair of adjacent zones.
Regardless of the number of zones, it can be seen that multiple cycles of producing and fracturing may be employed in order to create an ever-expanding network of fractures. However, in low-permeability formations the fracture networks created within the separate zones may or may not interconnect. Accordingly, an additional optional fracturing step may be employed. That step involves the placement of additional perforations and corresponding fractures intermediate to the first 410, second 420, and third 430 zones.
It is preferred that the perforations 462, 472 be oriented at an angle that is non-transverse to the casing 402. In this way, fractures 464, 474 are at least initially propagated at an angle, and may intersect with fractures in adjoining zones.
As can be seen,
In the method 500, the hydrocarbon fluids are produced from a subsurface formation. The subsurface formation represents a reservoir containing hydrocarbon fluids. The fluids may be, for example, methane and other lighter hydrocarbon fluids. The reservoir may also include so-called acid gases such as carbon dioxide and hydrogen sulfide. The reservoir may also incidentally contain water or brine.
In any instance, the subsurface formation is a low-permeability formation. The formation may have a permeability less than, for example, about 10 millidarcies. In this instance, the reservoir may be a tight-gas formation, a shale gas formation, or a coal bed methane formation.
The method 500 first includes providing a wellbore in the subsurface formation. This is shown at Box 505. The wellbore has been completed as a deviated wellbore. Preferably, the deviated wellbore is a substantially horizontal wellbore within the subsurface formation. The wellbore has been perforated along at least a first zone and a second zone.
The method 500 also includes fracturing the subsurface formation along the first and second zones. This is provided at Box 510. Fracturing the formation along these zones creates one or more substantially vertical fractures extending from the wellbore.
The method 500 further includes producing hydrocarbon fluids through the vertical fractures along the first and second zones. This is seen at Box 515. In one aspect, the vertical fractures extend a distance of about 100 feet (30.5 meters) to 500 feet (152.4 meters) from the wellbore.
The method 500 additionally includes injecting a fluid into the subsurface formation. This is provided at Box 520. The fluid is preferably a hydraulic fluid such as brine. However, liquid CO2, foamed nitrogen, or other non-reactive fluids may also be injected.
In the injecting step of Box 520, the fluid is injected through perforations in the second zone. This serves to raise the reservoir pressure in the subsurface formation along the first zone. This also helps to cause a change in the in situ stresses within the subsurface formation along the first zone. However, the fluid preferably is not injected at a parting pressure and does not extend existing fractures.
The method 500 may also include monitoring the wellbore. This is shown at Box 525. The wellbore is monitored to determine when a change in orientation of maximum principal stress may occur within the subsurface formation along the first zone. The change in maximum principal stress occurs as a result of producing fluids from the first zone and injecting the fluid into the second zone.
The wellbore may be monitored in a number of different ways. For example, monitoring the wellbore may comprise determining when a designated volume of hydrocarbon fluids have been produced from the first zone or from the subsurface formation in general. Alternatively, monitoring the wellbore may comprise determining when a designated reduction in reservoir pressure within the subsurface formation along the first zone has taken place. This may be done through reservoir simulation or based on experience with existing wells in the field. Alternatively, monitoring the wellbore may comprise determining when a selected volume of fluid has been injected into the subsurface formations through the perforations in the second zone.
Alternatively still, monitoring the wellbore may comprise determining when a selected period of time of production has taken place from the first zone. And still alternatively, monitoring the wellbore may comprise determining whether micro-seismic readings or tilt-meter readings indicate a change in in situ stresses. Of course, combinations of these techniques are preferably employed.
The method 500 further includes injecting a fluid into the subsurface formation through perforations in the first zone. This is seen at Box 530. The injection of fluid in the first zone is at high pressures, and causes a propagation of fractures in the subsurface formation along the first zone. The direction of maximum principal stress has been changed in the near-wellbore region along the first zone. Accordingly, the fractures tend to propagate at least partially towards the second zone.
The method 500 also includes producing hydrocarbons. This is shown at Box 535. Hydrocarbon fluids are produced through the perforations along the first zone. Preferably, hydrocarbon fluids are also produced through the perforations along the second zone as well. This is seen at Box 540.
The method 500 as described above only recites two zones. However, the method 500 may be applied to a wellbore that is perforated in more than two zones. In one aspect, the wellbore is perforated to create new perforations along a third zone. This is provided at Box 545. Perforations may be provided along the first zone, the second zone, and a third zone, with the zones preferably being separated by a distance of between about 20 feet (6.1 meters) and 500 feet (152.4 meters). As described above, the methods 500 may be performed on wellbores having multiple zones and may be performed simultaneously on more than two zones and may be performed sequentially on more than two zones. The specific manner of implementation may depend on the size of the field, the age of the field, or other factors that may become apparent to an operator. For example, the methods may be applied to more than two zones simultaneously and then later applied to still further zones.
The method 500 would then include fracturing the subsurface formation along the third zone to form additional vertical fractures extending from the wellbore. This is seen at Box 550. The perforating 545 and fracturing 550 steps may be conducted in stages with the first, second, and third zones using multi-interval procedures known in the art of well completions.
Where a third zone is perforated, the method 500 also includes producing hydrocarbon fluids through the vertical fractures in the third zone. This is shown at Box 555. The producing step of Box 555 may take place with the producing step of Box 515.
The method 500 still includes injecting a fluid into the subsurface formation through perforations in the second zone. This was provided at Box 520. The injection step of Box 520 will further raise reservoir pressure in the subsurface formation along the third zone, and will further cause a change in the in situ stresses within the subsurface formation along the third zone. This is indicated at Box 560. During this time, hydrocarbon fluids continue to be produced from the third zone in accordance with the producing step of Box 555.
Where a third zone is perforated, the method 500 also includes injecting a fluid into the subsurface formation through perforations in the third zone. This is provided at Box 565. The injection step of Box 565 creates a first set of new fractures in the subsurface formation along the third zone. These new fractures propagate at least partially towards the second zone.
The method 500 next includes again producing hydrocarbon fluids from the third zone. This is provided at Box 570. Preferably, hydrocarbon fluids are also simultaneously produced from the first and second zones. Thus, the step of producing in Box 570 may take place simultaneously with the producing step of Box 535.
It is noted here that the process of injecting fluid in one zone to increase reservoir pressure and to change in situ stresses in an adjoining zone may be applied in any order. Further, the process may be alternated such that after one zone has been re-fractured and produced, an adjoining zone may be re-fractured and produced. Thus, in the method 500, after producing fluids from the first, second and third zones in Boxes 535 and 570, production is temporarily suspended from the first zone. This is seen at Box 575.
After discontinuing the production of fluids from the first zone, fluid is then injected into the subsurface formation through perforations in the first zone. This is shown at Box 580. This injection is not for the purpose of creating new fractures in the first zone, but to raise reservoir pressure in the subsurface formation along the second zone. This causes a change in the in situ stresses within the subsurface formation along the second zone.
The method 500 then includes injecting a fluid into the subsurface formation through perforations in the second zone. This is provided at Box 585. The injection of fluids into the second zone is at high pressures, thereby causing a propagation of fractures in the subsurface formation along the second zone at least partially towards the first zone.
The method 500 then includes producing hydrocarbons through the perforations along the second zone. This is seen at Box 590.
The steps of Boxes 580 through 590 may be applied again with respect to the third zone. The result is that additional fractures are created in the second zone that extends at least partially towards the third zone. Thus, a more complex network of fractures is created in the subsurface formation, increasing the exposure of the formation to production channels and the wellbore.
It can be seen that the method 500 involves the selective injection of fluids at different pressures and in different stages. Further, the method 500 involves the production of fluids from selected zones at different stages. The steps of the method 500 may be aided through the use of packers, fracturing ports, mechanical plugs, sand plugs, sliding sleeves, and other devices known in the art.
The methods 300 and 500 of
In order to optimize the production of hydrocarbons from a formation, the reservoir engineer or other field developer designs a desired fracture network.
In the illustrative fracture network 600A, the fractures 610, 620 are arranged in pairs 650A. Each of the fractures 610 is oriented along an x-y plane. At the same time, each of the fractures 620 is oriented along a z-y plane. In this way, each of the x-y fractures 610 is intersected at substantially a right angle by a single corresponding z-y fracture 620. A plurality of pairs 650A is provided for the fracture network 600A.
The concept of intersecting fractures shown in the fracture network 600A is but one of many possible arrangements.
Other related variations may readily be employed. For example, instead of providing a single z-y fracture 620 with each of the x-y fractures 610, three z-y fractures 620 may be provided with each of the x-y fractures 610. Inversely, instead of providing a single x-y fracture 610 with each of the z-y fractures 620, two, three, or more x-y fractures 610 may be provided with each of the z-y fractures 610.
In order to create such an arrangement of fractures 610, 620, the reservoir engineer (or other field developer) may complete a plurality of horizontal wells in a subsurface formation. In one aspect, some wells are completed along an x-axis within the formation, while other wells are completed along a z-axis in the formation. The purpose is to provide substantial coverage of a field with a fracture network.
A fracturing fluid is injected into a first set of wells, such as the horizontal wells completed along the x-axis, in order to create fractures in the formation in a first vertical orientation. This may be done in accordance with the steps shown, for example, in
It is desirable to optimize the production of hydrocarbon fluids from the formation 725. Because the formation 725 has limited permeability, one way of optimizing production is by creating a network of interconnecting fractures. In order to create the fracture network, a first set of wells is completed horizontally. The wellbores for the first set of wells are shown at 732. These wellbores 732 extend along an x-axis. Thereafter, the subsurface formation 725 is fractured from perforations in the wellbores 732 for the first set of wells. Fractures are seen at 740. Hydrocarbon fluids are then produced from through the fractures 740 and the corresponding wellbores 732.
After a period of production, the in situ stress field within the subsurface formation 725 is changed. This may be as a natural result of the fluid production process. Alternatively, this may be as a result of selective injection of water or other fluids into the subsurface formation 725 in order to increase in situ pressure. In any instance, a second set of wells having wellbores 734 is also formed. These wellbores are also completed horizontally, and are oriented along a z-axis.
After the in situ stress field within the subsurface formation 725 is changed, the subsurface formation 725 is fractured from perforations in the wellbores 734 for the second set of wells. Illustrative fractures from the wellbores 734 are seen at 750. Hydrocarbon fluids are then produced from through the fractures 750 and the corresponding wellbores 734.
It is noted that the wellbores 732 along the x-axis and the wellbores 734 along the z-axis cross. They do not intersect, but they do cross. This allows the respective fractures 740, 750 to intersect. The intersecting fractures 740, 750 create a fracture network analogous to the fracture networks 650A, 650B shown in
The reservoir may be a hydrocarbon-producing reservoir. For example, the reservoir may contain methane and other hydrocarbon gases. In this instance, the reservoir may be a tight-gas formation, a shale gas formation, or a coal bed methane formation. The reservoir may also include so-called acid gases, such as carbon dioxide and hydrogen sulfide. The reservoir may also incidentally contain water or brine.
Alternatively, the reservoir may be a geothermal zone containing water and, possibly, minerals. In this instance, the reservoir will produce steam.
The method 800 generally includes designing a desired fracture network. This is shown at Box 810. The fracture network may be, for example, in accordance with the illustrative fracture networks 650A, 650B shown and discussed in
The method 800 also includes determining required in situ stresses to create the fracture network within the reservoir. This is provided at Box 820. Determining required in situ stresses may be done in several ways. For example, downhole pressure measurements may be taken from existing wells. Such measurements are indicative of pore pressure acting within a rock matrix. Alternatively or in addition, micro-seismic testing may be conducted. Alternatively or in addition, tiltmeter readings may be monitored.
In a preferred aspect, downhole stress modeling may be conducted. For example, ABAQUS™ software may be used to develop in situ stresses and resulting fractures. To run a model, the rock matrix making up the reservoir is initialized with certain mechanical properties. Such properties may be, for example, elastic moduli and Poisson ratios. Elastic moduli and Poisson ratios may be estimated based on interpreted lithologies for the rocks included in the model.
A stress field may be demonstrated by x, y, and z coordinates. In the Piceance Basin, for instance, the in situ stress field will be affected in one of the horizontal directions due to tectonic forces acting from the Rocky Mountain range to the east. From the stress field modeling, the direction of least principal stress is determined. For formations deeper than about 1,000 feet, the direction of least principal stress will likely be in the “x” or “z” directions, where the x and z directions are horizontal and “y” is the vertical direction, such that hydraulically-induced fractures will be oriented in plane perpendicular to the “x” or “z” direction.
The method 800 further includes designing a layout of wells to alter the in situ stresses. This is provided at Box 830. Designing such a layout of wells means that wells are completed in the subsurface for the production and/or injection of fluids for the purpose of altering the in situ stress field. The layout of wells may be, for example, in accordance with the layout of wellbores 732 and 734 of
The method 800 also includes injecting a fracturing fluid under pressure into the reservoir. The purpose is to create an initial set of fractures. This is shown at Box 840. The fractures will likely extend in a vertical plane through the formation, as shown in
Historically, an operator might choose to extend the length of the fractures in order to increase exposure of the wellbores to the formation. Fractures have been reported in some field developments that extend many thousands of feet. However, this is undesirable where the fractures are anticipated to form in a vertical plane. In this respect, the fractures may propagate beyond the targeted production intervals and, potentially, into aquifers or unconsolidated formations.
In the method 800, a next step is taken to monitor the in situ stresses in the reservoir. This is seen at Box 850. Monitoring the in situ stresses in the reservoir may be done in several ways. These are generally shown in the flow chart of
The method 800 additionally includes updating the geomechanical simulation based on the monitored in situ stresses. This is indicated at Box 855. Further, the method 800 includes designing a program of modifying the in situ stress within the stress field. This is seen at Box 860. The step of designing a program of Box 860 is also done using geomechanical simulation. The geomechanical simulations may be performed using commercially available software capable of capturing the complex interplay between the in situ stress state and the engineering practices. Examples of such software include finite element software (e.g. Abaqus or ELFEN); and discrete element software (e.g. PFC3D or ELFEN).
The geomechanical simulations incorporate fully-coupled constitutive relations that enable mathematical representations of in situ stress state and pore pressure, rock mechanical properties, engineering stimulation practices at the wellbores, and field production. Newly acquired data is input into the geomechanical simulations to foster iteration between history matching and predictive modes.
The method 800 also includes modifying the in situ stresses in the reservoir. This is seen at Box 865. Modifying the in situ stresses permits the operator to determine when the direction of least principal stress within the in situ stress field has changed.
The in situ stresses may be modified through reservoir depletion over time. In this instance, the step 860 will comprise producing hydrocarbon fluids from the reservoir. Alternatively or in addition, the step 865 may comprise injecting a fluid into the reservoir. The fluid is injected at a pressure lower than the parting pressure of the rock matrix. The fluid may be injected into each of a plurality of wells either (i) simultaneously, or (ii) in stages such that fluid is injected into one or more wells or one or more zones sequentially.
In a related embodiment, modifying the in situ stresses further comprises (i) specifying a length of time for injecting for selected wells, (ii) specifying a viscosity of fluid for injection into selected wells, (iii) modifying a temperature of the reservoir, or (iv) combinations thereof. Modifying a temperature of the reservoir may comprise (i) injecting a heated gas into the reservoir, (ii) applying resistive heat to a rock matrix comprising the reservoir, (iii) actuating one or more downhole combustion burners, (iii) injecting a cooler fluid into the reservoir or (v) combinations thereof.
Modifying the in situ stresses may also comprise establishing assistive fracture paths. The assistive fracture paths are in addition to the initial fractures created in step 840. Establishing the assistive fracture paths may be done by creating a plurality of radially offset perforations into the reservoir through a plurality of wells. The orientation of the perforations may also be adjusted so that the perforations do not extend transverse to the wellbores. Alternatively or in addition, establishing the assistive fracture paths may be done by injecting an acidic fluid through a plurality of wells to create worm holes in the reservoir.
Once the in situ stresses have been modified, the reservoir may be further fractured. This enables a true network of fractures to be created, as opposed to simply re-opening or, perhaps, extending the same fractures in the same direction. Thus, the method 800 further includes injecting a fluid under pressure into the reservoir in order to expand upon the initial set of fractures and to create the network of fractures. This is shown at Box 870. Injecting a fluid into the reservoir to create the network of fractures may be done by determining pump rates and associated shear rates for selected wells.
In one aspect of the method 800, at least two of the wells in the layout of wells are completed for the production of hydrocarbon fluids. In this instance, the network of fractures is designed to optimize production of the hydrocarbon fluids. Injecting a fluid into the reservoir under pressure in accordance with the steps of Boxes 840 and 870 may comprise injecting the fluid through wells that have been completed principally for the production of hydrocarbon fluids.
In another aspect, at least two of the wells in the layout of wells are being completed for the injection of fluids as part of enhanced oil recovery. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 may further comprise injecting the fluid through selected wells that are completed for the injection of fluids. The fluids being injected may represent an aqueous fluid such as brine.
In yet another aspect, at least two of the wells in the layout of wells are completed for the production of geothermally-produced steam. The network of fractures is designed to optimize heat transfer for geothermal applications. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 may comprise injecting the fluid through selected wells completed for the production of the geothermally-produced steam.
In still another aspect, at least two of the wells in the layout of wells are completed for the injection of acid gases. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 comprises injecting the fluid through selected wells completed for the injection of acid gases. The acid gases may primarily comprise carbon dioxide. The carbon dioxide may be injected as part of an enhanced oil recovery project. Alternatively, the carbon dioxide may be injected as part of a sequestration operation. In this instance, the network of fractures is designed to optimize CO2 storage capacity.
In yet another aspect, at least two of the wells in the layout of wells are completed for the injection of drill cuttings. In this instance, injecting a fluid under pressure into the reservoir in accordance with the steps of Boxes 840 and 870 comprises injecting the drill cutting through selected wells for injection into the reservoir.
In one embodiment of the methods herein, the reservoir comprises two or more zones. In this instance, the network of fractures is created within at least two different zones. Designing a desired fracture network system then involves designing a fracture network system in each of the at least two zones. In addition, injecting a fluid under pressure into the reservoir involves injecting a fluid into each of the at least two zones so as to create the network of fractures within the at least two zones. For example, the network of fractures may be created in the manner described above in connection with
In another embodiment, a plurality of wells within the layout of wells has already been perforated into the reservoir. Further, the reservoir has undergone hydrocarbon production for a period of time. In this instance, injecting a fluid under pressure into the reservoir in order to create the network of fractures involves re-fracturing each of the plurality of wells.
As can be seen, methods are offered herein to enhance hydrocarbon production from subterranean formations by manipulating the downhole in situ stresses. Manipulating in situ stresses allows the operator to create fractures in different directions and to enhance reservoir connectivity. In accordance with the methods, a desired fracture network system is first designed for draining the reservoir. The in situ stresses needed to create the fracture network system are then determined. A comprehensive system consisting of well/pad layout and well architecture is designed to alter the stress field around the individual wells. A customized network of fractures is then created.
As a result of fracturing, there is increased fracture complexity and increased reservoir access. The change in downhole in situ stresses and accompanying fracture orientation are preferably monitored or modeled to provide continuous feedback. This is indicated at Box 880 of
The methods disclosed herein are particularly beneficial for the development of unconventional reservoirs such as tight gas, shale gas, and coal bed methane, and the recovery of gas. The methods are also beneficial for the sequestration of CO2. In geothermal applications, the present methods will help to increase contact area from the wellbore to the reservoir. For water/cuttings injection wells, the methods can be used to control fracture geometry and orientation.
While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof.
This application claims the priority benefit of U.S. Provisional Patent Application 61/405,069 filed 20 Oct. 2010 entitled METHODS FOR ESTABLISHING A SUBSURFACE FRACTURE NETWORK, the entirety of which is incorporated by reference herein.
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/US11/49579 | 8/29/2011 | WO | 00 | 3/22/2013 |
| Number | Date | Country | |
|---|---|---|---|
| 61405069 | Oct 2010 | US |
