WO2012015528A1 - Enhanced hydrocarbon fluid recovery via formation collapse - Google Patents

Abstract

Methods for improving hydrocarbon production from a subsurface formation, such as a low-permeability formation, are provided herein. The methods may involve drilling a wellbore into the subsurface formation, and analyzing a mineralogy of a rock matrix making up the formation. The methods also include continuing to drill the wellbore into the formation, and running a working string into the wellbore and down to the formation. A first fluid is selected that will chemically produce a disaggregation or other change in the rock matrix. The methods then include circulating the first fluid across the formation. This serves to break off rock material from the formation and enlarge an annular region around the working string. Preferably, the wellbore operations induce at least a partial collapsing of the wellbore and a change in in situ stresses. This creates a fracture network within the subsurface formation, further aiding in the production of hydrocarbon fluids.

Description

ENHANCED HYDROCARBON FLUID RECOVERY

VIA FORMATION COLLAPSE

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the priority benefit of U.S. Provisional Patent Application 61/369,484 filed 30 July 2010 entitled Enhanced Hydrocarbon Fluid Recovery Via Formation Collapse, the entirety of which is incorporated by reference herein.

BACKGROUND

[0002] 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.

Field

[0003] The present inventions relate to the field of hydrocarbon recovery operations. More specifically, the inventions relate to methods for increasing the permeability of shale and other low-permeability formations in order to improve the recovery of hydrocarbon fluids.

General Discussion of Technology

[0004] In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and connected bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation.

[0005] A cementing operation is typically conducted in order to fill or "squeeze" the annular area with cement. This serves to form a cement sheath. The combination of cement and casing strengthens the wellbore and facilitates the isolation of the formations behind the casing.

[0006] It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. Thus, the process of drilling and then cementing progressively smaller strings of casing is repeated several or even multiple times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented into place. In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface, but is hung from the lower end of the preceding string of casing.

[0007] In some instances, a well may be completed as an open-hole completion. This means that the final tubular body run into the wellbore is not cemented into place; instead, a perforated or "slotted" liner may be installed. Where the formation comprises an unconsolidated sand or other loosely-held rock matrix, a sand screen with a gravel pack may be placed along hydrocarbon-bearing intervals.

[0008] In some instances, a wellbore is completed in a formation having very low permeability. The low permeability may be less than 10 millidarcies, or even less than 5 millidarcies. In recent years, large accumulations of hydrocarbons have been discovered in such formations, even with a permeability that is less than 2 millidarcies. For example, the Barnett shale in northern Texas by some estimates holds recoverable gas reserves in the range of 26 to 39 trillion cubic feet.

[0009] Shale formations such as the Barnett shale are typically made up of fine-grained, sedimentary rocks and significant amounts of clay minerals. These rocks typically have a native permeability of less than even 1 millidarcy. To extract hydrocarbon fluids from these or other low-permeability formations at commercial rates, it is usually necessary to increase the gross permeability of the hydrocarbon-bearing formation through hydraulic fracturing.

[0010] Hydraulic fracturing is a formation stimulation technique in which fluid is pumped into the formation at a pressure higher than the minimum earth stress. The fracturing fluid is typically mixed with a proppant material such as sand, ceramic beads, or other granular material. The proppant serves to hold the fracture(s) open after the hydraulic pressures are released. The fracturing process creates fractures within the formation that allow formation fluids to more easily flow to the well.

[0011] In addition to hydraulic fracturing, operators may complete wells in low- permeability formations in a highly deviated orientation. This substantially increases the wellbore surface area through a selected zone of interest. In one example, the operator may drill a well through a zone of interest in a substantially horizontal orientation, and then perform multiple fracture jobs along the horizontal portion using so-called slick-water. Slick water is water with a viscosity-reducing agent added. This completion method can enable initial well rates for shale formations in the range of 3 to 10 million cubic feet per day (mcfd). [0012] While this method is considered useful in optimizing initial production rates, published estimates indicate that this method sometimes only recovers between 5% and 20% of the available gas. This is due to the inability of fracture cracks to create fluid communication channels across more than a small portion of the hydrocarbon reservoir. Rates and recovery factors for shale formations are much lower than those typically achieved in conventional gas resources.

[0013] Another problem that has been encountered with hydraulic fracturing of low- permeability formations is that some shale strata are very ductile. Such shales have a tendency to close back around fractures after they are formed in response to in situ earth stress. The result is that wells completed in shale strata may experience a rapid decline in production. Decline rates for some shale gas wells have exceeded 50% per year.

[0014] Yet another problem with hydraulic fracturing is that it typically requires large volumes of water. A typical shale fracturing job may use more than 500,000 gallons of water. While some of this water is returned when the well is initially put on production, a significant fraction (such as up to 40%) is normally lost downhole. This is particularly problematic and expensive in areas where water may not be abundant.

[0015] Finally, the completion and stimulation technology used to generate multiple fractures is expensive, often comprising more than 50%> of the well construction costs.

[0016] A need exists for a method to enhance the flow capacity of low-permeability reservoirs without a primary reliance on hydraulic fracturing. A need further exists for a method of increasing the surface area of the wellbore face to enhance exposure to the surrounding formation.

SUMMARY OF THE INVENTION

[0017] Methods for improving hydrocarbon production from a subsurface formation are provided herein. The methods have application to wells that are completed as open-holes in formations having low permeability. In one example, the wells have a permeability of less than 10 millidarcies. The wells may be completed either vertically, or as deviated holes. However, the methods have greatest utility in improving recovery efficiency in wells that are completed substantially horizontally.

[0018] In one aspect, the method first includes drilling a wellbore using a drill string. The wellbore is drilled into a subsurface formation. The method may also include analyzing a mineralogy of a rock matrix making up the formation. In one aspect, the rock matrix comprises shale.

[0019] The method may also include continuing to drill the wellbore through the subsurface formation. Preferably, the drill string extends to proximate a bottom portion of the subsurface formation. A working string is then run into the wellbore. The working string extends into the subsurface formation, and forms an annulus (circular or other shape) between the working string and the surrounding formation. Optionally, a pre-perforated liner is also installed along the bottom portion of the wellbore before running the working string into the wellbore.

[0020] The method further includes selecting a fluid as a first fluid. The first fluid is selected so as to induce via chemical interaction (i) a swelling of the rock matrix, (ii) a disaggregation of the rock matrix, (iii) a dissolution of particles within the rock matrix, or (iv) combinations thereof. In this way, the first fluid acts against the rock matrix to enlarge the annulus along at least a bottom portion of the subsurface formation. [0021] The first fluid may comprise, for example, fresh water. Alternatively, the first fluid may be an organic solvent. Alternatively still, the first fluid may include a detergent, an acidic fluid, an oxygen-releasing compound, or a bleaching compound. The first fluid is selected based on the analysis of the mineralogy of the rock matrix.

[0022] The method also includes flowing the first fluid across the subsurface formation within the wellbore. Preferably, flowing comprises reverse-circulating the first fluid into the annulus across the subsurface formation, and back up a bore of the working string to the surface. The chemical action of the first fluid breaks off rock material from the bottom portion of the subsurface formation and enlarges the annulus. Typically, the first fluid is pressurized in the bottom portion of the wellbore to a pressure greater than initial pore pressure in the shale, but less than a fracture initiation pressure.

[0023] In one aspect, the method includes continuing to flow the first fluid until enough rock material is broken off from the bottom portion of the subsurface formation to change in situ stresses within the subsurface formation. This, in turn, (i) induces at least partial collapse of the bottom portion of the wellbore, and (ii) creates a fracture network within the subsurface formation above the collapsed bottom portion of the wellbore. [0024] The method further includes producing hydrocarbon fluids from the subsurface formation. In a preferred embodiment, the hydrocarbon fluids comprise primarily gaseous hydrocarbons that are produced through a pre-perforated liner.

[0025] In one aspect, the method also includes circulating a cleaning fluid into the annulus across the subsurface formation. The action of the cleaning fluid removes at least a portion of the rock material that has broken off. The cleaning fluid may have substantially the same composition as the first fluid, in which case the cleaning fluid is a chemically reactive fluid. Alternatively, the cleaning fluid may have a composition that is different from the first fluid. In the latter instance, the cleaning fluid preferably contains a viscosifier to increase fluid density and to facilitate the transport of rock material up the bore of the working string during circulating.

[0026] Additional steps may be taken to further induce the bottom portion of the wellbore to collapse. In one approach, the operator may reduce fluid pressure within the open-hole portion of the wellbore. The fluid pressure is reduced, for example, by reverse circulating a collapsing fluid into the deviated portion of the wellbore, wherein the collapsing fluid has a density that is less than a density of the first fluid. The collapsing fluid may comprise, for example, a gas or a light hydrocarbon fluid. In another approach, the operator may further induce the bottom portion of the wellbore to collapse by changing the temperature of the bottom portion of the formation. For example, the temperature of the bottom portion of the formation may be increased by at least 100° F.

[0027] Yet additional steps may be taken to enlarge the annulus in the open-hole portion of the wellbore. For example, nozzles may be run into the end of the working string. The first fluid may then be jetted against the rock matrix. Alternatively, the first fluid may be oscillated within the wellbore.

[0028] A method for improving hydrocarbon production from a subsurface formation is also provided herein. The method again has application to wells that are completed as open- holes in formations having low permeability.

[0029] In one aspect, the method first includes drilling a wellbore into the subsurface formation. Drilling is conducted using a drill string and connected drill bit. The method also includes selecting a first fluid which chemically interacts with the rock matrix adjacent to the wellbore to weaken the rock matrix. The first fluid is selected based on a mineralogy of the rock matrix. Thus, the method may optionally include analyzing a mineralogy of the rock matrix making up the formation. In one aspect, the rock matrix comprises primarily shale.

[0030] The method further comprises flowing the first fluid into the wellbore and across the subsurface formation. In this manner, the first fluid contacts the rock matrix along the subsurface formation adjacent to the wellbore. This serves to weaken the rock matrix.

[0031] The method then includes withdrawing the drill string from the subsurface formation. Withdrawal may mean only partially raising the drill string to a depth above the subsurface formation. More preferably, withdrawal means tripping the drill string from the hole, and then attaching a new rock grinding device before re-entry.

[0032] In operation, the first fluid may be flowed down an annulus formed between the drill string so as to break off rock material from the rock matrix along the subsurface formation. This also serves to radially enlarge at least a portion of the wellbore along the subsurface formation. In one aspect, the first fluid chemically interacts with the rock matrix to cause a swelling of the rock matrix. Alternatively or in addition, the first fluid chemically interacts with the rock matrix to cause a dissolution of inorganic particles within the rock matrix. Alternatively or in addition, the first fluid chemically interacts with the rock matrix to cause a dissolution of organic binders within the rock matrix.

[0033] To facilitate flowing the first fluid across the subsurface formation, the method may include running a working string into the wellbore. The working string extends into the subsurface formation and forms an annulus between the working string and the surrounding formation. In this instance, flowing the first fluid comprises circulating the first fluid through the annulus.

[0034] The action of flowing the first fluid across the subsurface formation serves to break off at least some rock material. The rock material falls into the wellbore. Thus, the method preferably also includes rotating the drill string and a connected rock grinding device back along the subsurface formation to grind out at least a portion of the broken rock material. The rock grinding device may be, for example, another drill bit or an auger. During this clean-out process, a cleaning fluid is circulated through the drill string. The cleaning fluid may be the first fluid, but preferably it is a drilling mud or heavy fluid that can transport rock particles away from the subsurface formation and up the wellbore.

[0035] In one aspect, a collapsing fluid is placed in the wellbore after the first fluid is circulated across the subsurface formation. The collapsing fluid is a foam, a gas, or other low-density fluid. The collapsing fluid may or may not be circulated across the subsurface formation. In either instance, the collapsing fluid induces further collapse of the rock matrix into the wellbore. Thereafter, the drill string and a connected rock grinding device are rotated back along the subsurface formation to grind out at least a portion of newly broken rock material. In addition, the cleaning fluid is circulated through the drill string to at least partially clean out the wellbore.

[0036] The steps of weakening and/or collapsing and/or drilling and cleaning may be repeated. Hydrocarbons are then produced from the subsurface formation.

BRIEF DESCRIPTION OF THE DRAWINGS

[0037] 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.

[0038] Figure 1A is a cross-sectional view of an illustrative wellbore. The wellbore has been completed substantially horizontally as an open-hole completion. A working string is placed within a slotted liner along a hydrocarbon-bearing formation.

[0039] Figure IB is a next cross-sectional view of the wellbore of Figure 1A. Here, a first fluid is being reverse-circulated through the wellbore. The volume of the annulus at the open-hole portion of the wellbore is being increased, and material from the rock matrix is being circulated out of the wellbore.

[0040] Figure 1C is a next cross-sectional view of the wellbore of Figure 1A. The first fluid continues to be reverse-circulated through the wellbore, causing the volume of the annulus at the open-hole portion of the wellbore to be further increased.

[0041] Figure ID is a next cross-sectional view of the wellbore of Figure 1A. The open- hole portion of the wellbore is being induced to collapse.

[0042] Figure IE is a next cross-sectional view of the wellbore of Figure 1A. The working string is being incrementally withdrawn from the wellbore, and rock material continues to be circulated out of the open-hole portion of the wellbore. A network of fractures is also seen in the subsurface formation. [0043] Figure IF is a next cross-sectional view of the wellbore of Figure 1A. Here, the working string has been removed, and compressible hydrocarbon fluids are being produced from the subsurface formation.

[0044] Figure 2A is a cross-sectional view of an illustrative wellbore, in an alternate arrangement. The wellbore has been completed substantially vertically as an open-hole completion. A working string is placed within a slotted liner along a hydrocarbon-bearing formation.

[0045] Figure 2B is a next cross-sectional view of the wellbore of Figure 2A. Here, a first fluid is being reverse-circulated through the wellbore. The volume of the annulus at the open-hole portion of the wellbore is being increased, and material from the rock matrix is being circulated out of the wellbore.

[0046] Figure 2C is a next cross-sectional view of the wellbore of Figure 2A. The first fluid continues to be reverse-circulated through the wellbore, causing the volume of the annulus at the open-hole portion of the wellbore to be further increased.

[0047] Figure 2D is a next cross-sectional view of the wellbore of Figure 2A. The open- hole portion of the wellbore is being induced to collapse.

[0048] Figure 2E is a next cross-sectional view of the wellbore of Figure 2A. Here, a coiled tubing has been run into the wellbore with a nozzle, and fluid is being jetted against the formation face to further enlarge the annulus around the open-hole portion of the wellbore.

[0049] Figure 2F is a next cross-sectional view of the wellbore of Figure 2A. A network of fractures is seen in the subsurface formation as a result of inducing the wellbore to collapse.

[0050] Figure 2G is a next cross-sectional view of the wellbore of Figure 2A. Here, the working string has been removed, and compressible hydrocarbon fluids are being produced from the subsurface formation.

[0051] Figure 3 is a flowchart demonstrating steps of a method for improving hydrocarbon production from a subsurface formation. DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS

Definitions

[0052] 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.

[0053] 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, coal bed methane, shale oil, pyrolysis oil, pyrolysis gas, a pyrolysis product of coal, and other hydrocarbons that are in a gaseous or liquid state.

[0054] 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, and combinations of liquids and solids.

[0055] As used herein, the term "condensable hydrocarbons" means those hydrocarbons that condense at about 15° C and one atmosphere absolute pressure. Condensable hydrocarbons may include, for example, a mixture of hydrocarbons having carbon numbers greater than 4.

[0056] As used herein, the term "subsurface" refers to geologic strata occurring below the earth's surface.

[0057] 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.

[0058] The terms "zone" or "zone of interest" refer to a portion of a formation containing hydrocarbons. [0059] The terms "annulus" and "annular region" mean a region between a tubular body within a wellbore and a surrounding tubular body or a surrounding formation. The annulus or annular region need not be precisely circular, or precisely shaped as a ring, but generally refer to a gap of any shape.

[0060] 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 shape. As used herein, the term "well", when referring to an opening in the formation, may be used interchangeably with the term "wellbore."

[0061] The term "tubular member" refers to any pipe, such as a joint of casing, a portion of a liner, a sand screen, or a pup joint.

Description of Selected Specific Embodiments

[0062] 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.

[0063] Certain aspects of the inventions are also described in connection with various figures. In the figures, the top of the drawing page is intended to be toward the surface, and the bottom of the drawing page toward the well bottom. While wells commonly are completed in substantially vertical orientation, it is understood that wells may also be inclined and even horizontally completed. When the descriptive terms "up and down" or "upper" and "lower" or similar terms are used in reference to a drawing, they are intended to indicate relative location on the drawing page, and not necessarily orientation in the ground, as the present inventions have utility no matter how the wellbore is orientated.

[0064] Figure 1A is a cross-sectional view of an illustrative wellbore 100. The wellbore 100 principally defines a bore 105 that extends from a surface 101, and into the earth's subsurface 110. The wellbore 100 also includes a wellhead 120 at the surface 101. 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 additional valves and other components, such as a blow-out preventer, used for drilling and completing a well. Once the well is completed, a well tree will be installed for directing the flow of production fluids. [0065] 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. The surface casing 130 has an upper end 132 in sealed connection with the lower master fracture valve 122. The surface casing 130 also has a lower end 134. The surface casing 130 is secured in the subsurface 110 with a surrounding cement sheath 136. The combination of the surface casing 130 and the cement sheath 136 strengthens the wellbore 100 and facilitates the isolation of formations behind the casing 130.

[0066] The pipes also include one or more sets of intermediate casing 140. The illustrative intermediate casing 140 also has an upper end 142 in sealed connection with the upper master fracture valve 124. The intermediate casing 140 also has a lower end 144. The intermediate casing 140 is secured in the subsurface 110 with a surrounding cement sheath 146. It is understood that a wellbore may, and typically will, include more than one string of intermediate casing. Some of the intermediate casing strings may be only partially cemented into place, depending on regulatory requirements and the presence of migratory fluids in any adjacent strata.

[0067] In some completions, a final string of casing, referred to as a production casing is installed. This string is likewise cemented into place, and then perforated in order to provide fluid communication between hydrocarbon fluids within the surrounding subsurface formation and the bore of the wellbore. However, in Figure 1A, the wellbore 100 is being completed as an open-hole completion. This means that a string of production casing is not run into the wellbore and cemented into place; rather, a bottom portion of the wellbore 100 is exposed to a hydrocarbon-bearing formation 150. This represents an open-hole portion 115A.

[0068] There are certain advantages to open-hole completions versus cased-hole completions. First, because open-hole completions have no perforation tunnels, formation fluids can converge on the wellbore radially 360 degrees. This has the benefit of eliminating the additional pressure drop associated with converging radial flow and then linear flow through particle-filled perforation tunnels. The reduced pressure drop associated with an open-hole completion virtually guarantees that it will be more productive than an unstimulated, cased hole in the same formation.

[0069] Second, open-hole completions, including gravel pack techniques, are oftentimes less expensive than cased hole completions. For example, the use of perforated liners and gravel packs eliminates the need for cementing, perforating, and post-perforation clean-up operations.

[0070] In Figure 1A, the wellbore 100 has been drilled into a hydrocarbon-bearing formation 150. More specifically, the wellbore 100 has been completed substantially horizontally within the hydrocarbon-bearing formation 150. The horizontal (or deviated) portion of the wellbore 100 is largely within the open-hole portion 115A of the wellbore 100. In this instance, the open-hole portion 115A extends from proximate a heel 112 of the wellbore 100 to a toe 114.

[0071] In order to support the open-hole portion 115A and to receive production fluids, a slotted liner 160 is optionally placed within the open-hole portion 115A of the wellbore 100. The slotted liner 160 is connected to the bottom 144 of the intermediate string of casing 140 using a liner hanger 162. The liner 160 may be connected proximate the heel 112 of the open-hole portion 115, and preferably extends to the toe 114 of the wellbore 100.

[0072] A working string 170 is also placed along the hydrocarbon-bearing formation 150. The working string 170 resides within the slotted liner 160. The working string 170 may be, for example, a string of coiled tubing. Upper 172 and lower 174 packers serve as fluid diversion means around the working string 170. In one aspect, a first fluid is pumped down an annular region 145 between the working string 170 and the surrounding casing 140. The first fluid is then directed by the upper packer 172 to circulate around the slotted liner 160 and against the formation face along the open-hole portion 115A. The first fluid is then returned up a bore 175 of the working string 170.

[0073] The arrangement of a working string 170 within a slotted liner 160 shown in Figure 1A provides for what is known as "reverse-circulating." However, it is understood that the operator may optionally use forward-circulating. In that instance, a working fluid is pumped down the bore 175 of the working string 170, to the heel 114 of the open-hole portion 115A of the wellbore 100, and then up the annulus 145. In addition, the operator may choose to circulate fluid using the working string 170 before installing the slotted liner 160. In that instance, packers 172 and 174 would not be needed.

[0074] Figure IB is a next cross-sectional view of the wellbore 100 of Figure 1A. A first fluid is being reverse-circulated through the wellbore 100. The flow of the first fluid is seen at arrows 10B. [0075] The first fluid is selected with the idea of interacting with the rock matrix making up the hydrocarbon-bearing formation 150. More specifically, the first fluid is selected to induce a swelling of the rock matrix. Alternatively or in addition, the first fluid is selected to induce a chemical disaggregation of the rock matrix. Alternatively or in addition, the first fluid is selected to induce a dissolution of particles within the rock matrix.

[0076] Various fluids may be selected to accomplish one or more of these affects. For example, the first fluid may be an organic solvent. Examples of an organic solvent include methanol, ethanol, propanol, iso-propanol, terpenes, and diesel. Alternatively, the first fluid may comprise a detergent. An example of a suitable detergent is a quaternary ammonium compound. Solvents and detergents may be beneficial in breaking up a formation which contains solid or near-solid hydrocarbons which act as binders between inorganic rock particles. Such hydrocarbons may include kerogen, bitumen, coal, or pyrobitumen. Another type of fluid that might be selected is a surfactant. Surfactants may facilitate the attack of water on certain shale components by lowering the surface tension of the water. [0077] As another example, the first fluid may be an acidic fluid. For example, the acidic fluid may comprise at least 10% by volume hydrochloric acid, acetic acid, or formic acid. Alternatively still, the first fluid may comprise an oxygen-releasing compound. Suitable examples of oxygen-releasing compounds include hydrogen peroxide, sodium perborate, sodium percarbonate, sodium persulfate, tetrasodium pyrophosphate, and urea peroxide. Acidic fluids and oxygen-releasing compounds may be beneficial in causing shale and clay- based formations to swell and break up. They may further be beneficial in causing carbonate formations to dissolve.

[0078] A further example for a first fluid is fresh water or other water having a salt content of less than about 1% by mass. Due to their clay content and composition, some low- permeability shale formations are sensitive to water, and will swell. Upon swelling, such formations become susceptible to breaking apart or disaggregation when exposed to fluid circulation.

[0079] As yet another example, the first fluid may include a bleaching compound. Examples of a bleaching compound are sodium hypochlorite and calcium hypochlorite. Bleaching compounds may be beneficial where the rock matrix making up the formation contains solid or near-solid hydrocarbons which act as binders between inorganic rock particles. Such hydrocarbons may include kerogen, bitumen, coal, or pyrobitumen. In any event, selection of the first fluid is based on the mineralogy of the rock matrix in the hydrocarbon-bearing formation 150. "Mineralogy" in this context is understood to include solid-like organics in addition to inorganic solids.

[0080] As the first fluid is circulated, it will react with the rock matrix in the subsurface formation. Portions of the rock matrix may chemically interact with the first fluid, changing the fluid's pH. Therefore, in connection with circulating the first fluid, the first fluid may be pH buffered. This means that the fluid is monitored to ensure that it has a consistent pH for dissolving or otherwise reacting with the rock matrix making up the formation 150.

[0081] Returning to Figure IB, it can be seen that an annulus 165 between the slotted liner 160 and the surrounding open-hole portion 115B of the wellbore 100 has become enlarged relative to the original position of Figure 1A. This is due to interaction of the first fluid with the rock matrix. Particles 5B representing material from the rock matrix are being removed from the open-hole portion 115B of the wellbore 100. The rock particles 5B are being circulated through the bore 175 of the working string 170 and up to the surface 101.

[0082] Figure 1C is a next cross-sectional view of the wellbore 100 of Figure 1A. The first fluid continues to be circulated through the wellbore 100. In this instance, circulation is again reverse-circulating. The flow of the first fluid is seen at arrows IOC.

[0083] Circulation of the first fluid causes the volume of the enlarged annulus 165 at the open-hole portion of the wellbore 100 to be further increased. The enlarged open-hole portion is now indicated at 115C. Particles 5C representing material from the rock matrix are being removed from the open-hole portion 115C of the subsurface formation 100. The rock particles 5C are again being circulated through the bore 175 of the working string 170 and up to the surface 101.

[0084] Figure ID is a next cross-sectional view of the wellbore 100 of Figure 1A. Here, the open-hole portion 115D of the wellbore 100 is being induced to collapse. Large formation particles 8D are seen laying on the bottom of the annulus 165 in the open-hole portion 115D.

[0085] The open-hole portion 115D of the wellbore 100 may be induced to collapse in a number of different ways. For example, the operator may reduce fluid pressure within the open-hole portion 115D of the wellbore 100. The fluid pressure may be reduced, for example, by circulating a second fluid into the wellbore, wherein the second fluid has a density that is less than a density of the first fluid. In this instance, the second fluid is a collapsing fluid. [0086] In Figure ID, arrows 10D indicate the circulation of a collapsing fluid. The collapsing fluid may comprise, for example, a gas or a light hydrocarbon fluid. Because the collapsing fluid has a density that is less than the density of the first fluid, the hydrostatic head will be reduced, allowing the open-hole portion 115D to at least partially collapse. Particles 8D indicate formation particles that have fallen to the bottom of the annulus 165 as a result of the partial collapse.

[0087] It is understood that in actual practice, the enlarged annulus 165 in open-hole portion 115D probably will not have the somewhat smooth mono-diameter appearance presented in Figure ID. Further, it is understood that the annulus 165 presented in Figure ID is not to scale. In actual practice, the annulus 165 may only be enlarged in diameter by about one to ten meters. Still further, it is understood that numerous additional particles 8D may gather in the open-hole portion 115 of the wellbore 100, and may even encompass the slotted liner 160.

[0088] To further induce a collapse of the open-hole portion 115D of the wellbore 100, the operator may further reduce the pressure within the open-hole portion 115D of the wellbore 100 by reducing pressure of injection pumps (not shown) at the surface 101. In these instances, the collapsing fluid may optionally have the same composition as the first fluid. Wellbore pressure is preferably reduced to below initial reservoir pressure. In addition, the operator may cause one or more oscillations in the fluid pressure. Oscillations may be created by cyclically increasing and drawing down the wellbore pressure using a pump at the surface. Alternatively, oscillating the first fluid may be done by reciprocating a downhole plunger, or generating ultrasonic frequencies downhole. Such oscillations may occur infrequently or with a relatively slow frequency, for example less than 1 Hz, 0.01 Hz, or even 0.0001 Hz. Alternatively, high frequency oscillations may be propagated through the fluid in the wellbore by generating ultrasonic frequencies downhole. Such frequencies may be in excess of, for example, about 10 kHz, and can enhance particle break-off from the wellbore surfaces.

[0089] As an alternative means of inducing a collapse of the open-hole portion 115D of the wellbore 100, the temperature of the hydrocarbon-bearing formation 150 may be changed. For example, the temperature of the hydrocarbon-bearing formation 150 adjacent to the wellbore may be increased by at least 100° F. Depending on the mineralogy of the rock matrix, changing the temperature may cause the rock matrix to become more susceptible to dissolution and/or disaggregation when exposed to the first fluid, the second fluid, or both. [0090] The temperature of at least a portion of the hydrocarbon-bearing formation 150 may be increased by circulating a heated fluid through the working string 170. The heated fluid may be, for example, steam. Alternatively, the temperature of at least a portion of the formation 150 may be increased by actuating a downhole electrical resistance heater. This may be done, for example, by running a conductive member into the wellbore adjacent the hydrocarbon-bearing formation 150, and then running a current through the conductive member to generate resistive heat. Where the working string 170 is a string of coiled tubing, the coiled tubing should ideally be removed from the wellbore 170 before the resistive heat is generated to avoid melting or deformity.

[0091] Figure IE is a next cross-sectional view of the wellbore 100 of Figure 1A. In this view, the particles 8D that fell from the formation 150 are being optionally removed. To do this, the first or second fluid continues to be circulated through the wellbore 100. Arrows 10E indicate the direction of the flow of fluid. At the same time, the working string 170 is incrementally withdrawn from the wellbore 100. In Figure IE, the working string 170 is withdrawn to position Ei.

[0092] Continuing to circulate the fluid as indicated by arrows 10E will also cause further erosion of the formation 150 and increase the size of the annulus 165. Particles 5E continue to break away from the hydrocarbon-bearing formation 150. The particles 5E are seen being moved from the annulus 165, up the bore 175 of the working string 170, and to the surface 101.

[0093] As an aid in transporting rock particles 5E to the surface, the second fluid may have a viscosity that is greater than a viscosity of the first fluid. In this instance, the second fluid is a cleaning fluid. In one aspect, a viscosifier is added to the cleaning fluid to increase the density and the viscosity of the cleaning fluid so as to assist in the transport of rock particles 5E. In another aspect, a collapsing fluid is used, followed by a cleaning fluid.

[0094] The working string 170 will be withdrawn from the open-hole portion 115E of the wellbore 100 to subsequent positions. These positions will include positions E₂ and E₃. As the working string 170 is withdrawn from the open-hole portion 115E and as fluid continues to be circulated, at least some of the particles 5E are cleaned out of the wellbore 100. Moreover, as the annulus 165 is enlarged due to the removal of material from the formation 150, the in situ stresses within the formation 150 change. This, in turn, creates a network of fractures 155. [0095] Figure IF is a next cross-sectional view of the wellbore 100 of Figure 1A. Here, the working string 170 has been completely removed from the wellbore 100. The wellbore 100 has been put on production. Hydrocarbon fluids are being produced from the formation 150, into the perforated liner 160, and to the surface 101. In the illustrative view of Figure IF, the hydrocarbon fluids are light hydrocarbon fluids such as methane. Methane gas production is indicated by bubbles 180.

[0096] Figures 1A through IF demonstrate one way of increasing the surface area of a wellbore 100 so as improve hydrocarbon recovery. This approach may desirably change in situ stresses within a subsurface formation 150, causing fracturing to take place with the subsurface formation 150 and provide increased flow paths for valuable hydrocarbon fluids. The wellbore 100 is completed as a deviated wellbore.

[0097] Figures 2A through 2G demonstrate an alternative way of improving hydrocarbon recovery from a subsurface formation. In these figures, a wellbore 200 is shown. The wellbore 200 is completed as a substantially vertical wellbore.

[0098] First, Figure 2A is a cross-sectional view of the illustrative wellbore 200. The wellbore 200 principally defines a bore 205 that extends from a surface 201, and into the earth's subsurface 210. As with wellbore 100, the wellbore 200 also includes a wellhead 120 at the surface 101. These again include 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 additional valves and other components, such as a blowout preventer, used for drilling and completing a well. Once the well is completed, a well tree will be installed for directing the flow of production fluids.

[0099] The wellbore 200 has been completed by setting a series of pipes into the subsurface 210. These pipes include a first string of casing 230, sometimes known as surface casing or a conductor. The surface casing 230 has an upper end 232 in sealed connection with the lower master fracture valve 122. The surface casing 230 also has a lower end 234. The surface casing 230 is secured in the subsurface 210 with a surrounding cement sheath 236. The combination of the surface casing 230 and the cement sheath 236 strengthens the wellbore 200 and facilitates the isolation of formations behind the casing 230.

[0100] The pipes also include one or more sets of intermediate casing 240. The illustrative intermediate casing 240 also has an upper end 242 in sealed connection with the upper master fracture valve 124. The intermediate casing 240 also has a lower end 244. The intermediate casing 240 is secured in the subsurface 210 with a surrounding cement sheath 246. It is understood that a wellbore may, and typically will, include more than one string of intermediate casing. Some of the intermediate casing strings may be only partially cemented into place, depending on regulatory requirements and the presence of migratory fluids in any adjacent strata.

[0101] As with wellbore 100, the wellbore 200 is being completed as an open-hole completion. This again means that a string of production casing is not run into the wellbore and cemented into place; rather, a bottom portion of the wellbore 200 is exposed to a hydrocarbon-bearing formation 250. An open-hole portion of the wellbore 200 of Figure 2A is seen at 215A.

[0102] In Figure 2 A, the wellbore 200 has been drilled into a hydrocarbon-bearing formation 250. More specifically, the wellbore 200 has been completed substantially vertically within the hydrocarbon-bearing formation 250. The open-hole portion 215A of the wellbore 200 is along the hydrocarbon-bearing formation 250. [0103] In order to receive production fluids, a slotted liner 260 is optionally placed within the open-hole portion 215A of the wellbore 200. The slotted liner 260 is connected to the bottom 244 of the intermediate string of casing 240 using a liner hanger 262. The liner 260 preferably extends near the bottom of the wellbore 200.

[0104] A working string 270 is also placed along the hydrocarbon-bearing formation 250. The working string 270 resides within the slotted liner 260. The working string 270 may be, for example, a string of coiled tubing. Upper 272 and lower 274 packers serve as fluid diversion means around the working string 270. A first fluid is pumped down an annular region 145 between the working string 270 and the surrounding casing 240. The first fluid is then directed by the upper packer 272 to circulate around the slotted liner 260 and against the formation face 215A. The first fluid is then returned up a bore 275 of the working string 270.

[0105] The arrangement of a working string 270 within the slotted liner 260 shown in Figure 2A provides for reverse-circulation. However, it is again understood that the operator may optionally use forward-circulation. In that instance, a working fluid is pumped down the bore 275 of the working string 270, to the bottom of the wellbore 200, and then up the annulus 245. In addition, the operator may choose to circulate fluid using the working string 270 before installing the slotted liner 260. [0106] Figure 2B is a next cross-sectional view of the wellbore 200 of Figure 2 A. A first fluid is being reverse-circulated through the wellbore 200. The flow of the first fluid is seen at arrows 10B.

[0107] The first fluid is once again selected with the idea of interacting with the rock matrix making up the hydrocarbon-bearing formation 250. More specifically, the first fluid is selected to induce a swelling of the rock matrix. Alternatively or in addition, the first fluid is selected to induce a disaggregation of the rock matrix. Alternatively or in addition, the first fluid is selected to induce a dissolution of particles within the rock matrix.

[0108] As discussed above in connection with Figure IB, various fluids may be selected to accomplish one or more of these affects. Those fluids again may be fresh water, an acid solution, a bleaching compound, a solvent, a detergent, or other fluid. Selection of the first fluid is based upon an analysis of the mineralogy of the rock matrix in the hydrocarbon- bearing formation 250.

[0109] As the first fluid is circulated, it will react with the rock matrix in the subsurface formation 250. Portions of the rock matrix may chemically interact with the first fluid, changing the fluid's pH. Therefore, in connection with circulating the first fluid, the first fluid may be pH buffered. This means that the fluid is monitored to ensure that it has a consistent pH for dissolving or otherwise reacting with the rock matrix making up the subsurface formation 250. Additionally or alternatively, when the interaction between the first fluid and the rock matrix is not dependent solely on the pH of the first fluid, the composition of the first fluid may be monitored in other manners to ensure substantially consistent composition. For example, when the first fluid is fresh water, the salinity of the water may be monitored.

[0110] Returning to Figure 2B, it can be seen that an annulus 265 between the slotted liner 260 and the surrounding open-hole portion 215B of the wellbore 100 has become enlarged relative to the original position of Figure 2A. This is due to interaction of the first fluid with the rock matrix. The flow of the first fluid is seen at arrows 10B. Particles 5B representing material from the rock matrix are being removed from the open-hole portion 215B of the subsurface formation 210. The rock particles 5B are being circulated through the bore 275 of the working string 270 and to the surface 201. [0111] Figure 2C is a next cross-sectional view of the wellbore 200 of Figure 2A. The first fluid continues to be circulated through the wellbore 200. In this instance, circulation is again reverse-circulation. The flow of the first fluid is seen at arrows IOC.

[0112] Circulation of the first fluid causes the volume of the enlarged annulus 265 at the open-hole portion of the wellbore 200 to be further increased. The enlarged open-hole portion is now indicated at 215C. Particles 5C representing material from the rock matrix are being removed from the open-hole portion 215C of the subsurface formation 100. The rock particles 5C are being circulated through the bore 275 of the working string 270 and to the surface 201.

[0113] Figure 2D is a next cross-sectional view of the wellbore 200 of Figure 2A. Here, the open-hole portion of the wellbore 200 is being induced to collapse. The collapsing open- hole portion is now shown at 215D. Formation particles 8D are seen collecting on the bottom of the annulus 165 in the open-hole portion 215D.

[0114] The open-hole portion 215D of the wellbore 100 may be induced to collapse in a number of different ways. For example, the operator may reduce fluid pressure within the open-hole portion 215D of the wellbore 200. The fluid pressure may be reduced, for example, by circulating a collapsing fluid into the wellbore, wherein the collapsing fluid has a density that is less than a density of the first fluid.

[0115] In Figure 2D, arrows 10D indicate the circulation of a second fluid. As noted above, the second fluid may be a collapsing fluid that comprises, for example, a gas or a hydrocarbon fluid. The collapsing fluid will have a density that is less than the density of the first fluid so as to reduce the hydrostatic head and allow the open-hole portion 215D to at least partially collapse. Particles 8D indicate formation particles that have fallen to the bottom of the annulus 265 as a result of the partial collapse.

[0116] It is again understood that in actual practice, the enlarged annulus 265 probably will not have the somewhat smooth appearance presented in Figure 2D. Further, it is understood that the annulus presented at 265 is not to scale. In actual practice, the annulus 265 may only be enlarged in diameter by about one to five meters. Still further, it is understood that numerous additional particles 8D may gather in the open-hole portion 215D of the wellbore 100, and may even encompass at least a bottom portion of the slotted liner 260. [0117] To further induce a collapse of the open-hole portion 215D of the wellbore 100, the operator may further reduce the pressure within the open-hole portion 215D of the wellbore 100. by reducing pressure of injection pumps (not shown) at the surface 201. In these instances, the second fluid may optionally have the same composition as the first fluid. Wellbore pressure is preferably reduced to below initial reservoir pressure. In addition, the operator may cause one or more oscillations in the fluid pressure. Oscillations may be created by cyclically increasing and drawing down the wellbore pressure using a pump at the surface. Alternatively, oscillating the first fluid may be done by reciprocating a downhole plunger. Such oscillations may occur infrequently or with a relatively slow frequency, for example, less than 1 Hz, 0.01 Hz, or even 0.0001 Hz. Alternatively, high frequency oscillations may be propagated through the fluid in the wellbore by generating ultrasonic frequencies downhole. Such frequencies may be in excess of, for example, about 10 kHz, and can enhance particle break-off from the wellbore surfaces.

[0118] As an alternative means of inducing a collapse of the open-hole portion 215 of the wellbore 200, the temperature of the formation 250 may be changed. For example, the temperature of the subsurface formation 250 may be increased by at least 100° F. Depending on the mineralogy of the rock matrix, changing the temperature may cause the rock matrix to become more susceptible to dissolution and/or disaggregation when exposed to either the first or the second fluid.

[0119] Figure 2E is a next cross-sectional view of the wellbore of Figure 2A. Here, a string of coiled tubing 290 has been run into the wellbore 200. More specifically, the string of coiled tubing 290 has been run into the bore 275 of the working string 270. The coiled tubing string 290 has a nozzle 292 at its lower end. The nozzle 292 is positioned below the slotted liner 260. Hydraulic fluid is being pumped from the surface 201 and through the nozzle 292. Jets of hydraulic fluid, seen at 294, are being directed against the hydrocarbon- bearing formation 250 in order to further enlarge at least a bottom portion of the annulus 265.

[0120] It is noted that the operator may choose to remove the original working string 270 from the wellbore 200 before running in the string of coiled tubing 290. Further, the operator may choose to use the original working string 270 for running in the nozzle 292. In this instance, the nozzle 292 would actually be attached to a bottom end of the original working string 270. The working string 270 would then be re-run into the wellbore 200 for the hydraulic jetting operation. In any respect, the step of jetting hydraulic fluid against the hydrocarbon-bearing formation shown in Figure 2E is optional. [0121] An open-hole portion of the wellbore 200 is shown in Figure 2E at 215E. It can be seen that the volume of the open-hole portion 215E is being further increased due to the hydraulic forces being applied to the hydrocarbon-bearing formation 250. The hydraulic forces cause additional particles 8E to fall from the rock matrix making up the hydrocarbon- bearing formation 250.

[0122] Figure 2F is a next cross-sectional view of the wellbore 200 of Figure 2A. In this view, the particles 8D and 8E that fell from the formation 250 have been optionally removed. To do this, the second fluid continues to be circulated through the wellbore 200. Preferably, the second fluid is a cleaning fluid that has a higher viscosity than the first fluid in order to carry larger formation particles 8E. Arrows 10F indicate the direction of the flow of fluid. At the same time, the working string 270 is incrementally withdrawn from the wellbore 200.

[0123] Continuing to circulate the cleaning fluid as indicated by arrows 10F will also cause further erosion of the formation 250 and increase the size of the annulus 265. Particles 5F continue to break away from the subsurface formation 250. The particles 5F are seen being moved from the annulus 265, up the bore 275 of the working string 270, and to the surface 201.

[0124] As an aid in transporting rock particles 5F to the surface, the second fluid may have a viscosity that is greater than a viscosity of the first fluid. In this instance, the second fluid is a cleaning fluid. In one aspect, a viscosifier is added to the cleaning fluid to increase the density and the viscosity of the fluid so as to assist in the transport of rock particles 5F.

[0125] As the annulus 265 is enlarged due to the removal of material from the hydrocarbon-bearing formation 250, the in situ stresses within the formation 250 change. This, in turn, creates a network of fractures 255. The fractures 255 provide fluid pathways for hydrocarbon fluids en route to the wellbore 200 during later production.

[0126] Figure 2G is a next cross-sectional view of the wellbore 200 of Figure 2A. Here, the working string 270 has been removed from the wellbore 200. The wellbore 200 has been put on production. Hydrocarbon fluids are being produced from the subsurface formation 250, into the perforated liner 260, and to the surface 201.

[0127] In the illustrative view of Figure 2G, the hydrocarbon fluids are again light hydrocarbon fluids such as methane. Methane gas production is indicated by bubbles 280. The flow of gas bubbles 280 to the surface 201 is indicated by arrows 10G. [0128] It is noted that while production is shown taking place in the wellbore 200, the operator may choose to treat the wellbore 200 as a permanent formation heater well, or perhaps convert the wellbore 200 to an injector for acid gas injection ("AGI"). In such instances, production of hydrocarbon fluids from the hydrocarbon-bearing formation 250 will take place in one or more separate production wells. The operator will complete one or more separate wells as production wells, and then produce the hydrocarbon fluids from those separate wells. The same process for enlarging the annulus in an open-hole completion may be undertaken for the separate production wells.

[0129] Figure 3 presents a flow chart for a method 300 for improving hydrocarbon production from a subsurface formation. The method 300 has application to wells that are completed as open-hole completions. The method 300 has greatest benefit in hydrocarbon- bearing formations having low permeability. In one example, the subsurface formation has a permeability of less than 10 millidarcies.

[0130] The method 300 first includes drilling a wellbore into a subsurface formation. This step is shown in Box 310. The wellbore is drilled using a drill string with a connected drill bit. Preferably, and the wellbore is drilled through and to a bottom of the subsurface formation. The wellbore may be vertical, or it may be deviated. The method 300 has particular advantage in wells that are completed horizontally.

[0131] The method 300 may optionally include analyzing a mineralogy of the rock matrix making up the subsurface formation. This is provided at Box 320. In one aspect, the rock matrix comprises shale. As an example, the rock matrix may comprise greater than about 12 wt. % clay.

[0132] The drill string may serve as a working string for the method 300. Optionally though, the drill string is removed from the wellbore, and a separate working string is then run into the wellbore. This is shown at Box 330. In either instance, the working string extends into the subsurface formation, and forms an annulus between the working string and the surrounding formation. Preferably, a separate working string is employed and a pre- perforated liner is also installed along the bottom portion of the wellbore before running the working string into the wellbore.

[0133] The method 300 further includes selecting a fluid as a first fluid. This is seen at Box 340. The first fluid is based on a mineralogy of the rock matrix. The first fluid is selected so as to chemically induce (i) a swelling of the rock matrix, (ii) a disaggregation of the rock matrix, (iii) a dissolution of particles within the rock matrix, or (iv) combinations thereof. In this way, the first fluid acts against the rock matrix to enlarge the annulus or to at least loosen the rock matrix.

[0134] As noted above, the first fluid may comprise, for example, fresh water. Alternatively, the first fluid may be an organic solvent. Alternatively still, the first fluid may include a detergent, an acidic fluid, an oxygen-releasing compound, or a bleaching compound. The operator will determine which of these fluids, or which combination of these fluids, has greatest utility in breaking up or removing particles from the rock matrix as the first fluid is circulated across the subsurface formation.

[0135] The method 300 also includes circulating or otherwise flowing the first fluid across the subsurface formation. This is seen at Box 350. Circulating may mean traditional forward-circulation, but more preferably represents reverse-circulation. In reverse- circulation, the first fluid is injected into the annulus and then back up the bore of the working string. The chemical interaction of the first fluid breaks off rock material from the bottom portion of the subsurface formation and enlarges the annulus. Typically, the first fluid is pressurized in the wellbore to a pressure greater than initial pore pressure in the shale, but less than a fracture initiation pressure.

[0136] In one aspect, the method 300 includes continuing to circulate or otherwise flow the first fluid until enough rock material is broken off from the bottom portion of the subsurface formation to change in situ stresses within the subsurface formation. This, in turn, (i) induces at least partial collapse of the bottom portion of the wellbore, and (ii) creates a fracture network within the subsurface formation above the collapsed bottom portion of the wellbore. In one aspect, a volume of collapsed shale is at least 100 cubic meters.

[0137] It is noted that the process of flowing the first fluid in the method 300 may involve flowing the first fluid through the drill string. In this instance, the drill string is maintained in the wellbore as the working string, with the first fluid being flowed into the wellbore. In one aspect, the first fluid is circulated across the subsurface formation for chemical interaction with the rock matrix. The first fluid may be flowed down an annulus formed between the drill string and the surrounding subsurface formation and up the drill string to a surface. Alternatively, the first fluid may be flowed down the bore of the drill string, and up an annulus formed between the drill string and the surrounding subsurface formation. In either instance, this would be before the drill string is withdrawn from the subsurface formation. In another aspect, the drill string is temporarily withdrawn from the subsurface formation during circulation.

[0138] Preferably, the drill string is reintroduced along the subsurface formation for further drilling of the formation to remove collapsed rock material, and for further circulation of the first fluid. A drill bit, an auger, or other mechanical device may be used for grinding the rock material. A weighted cleaning fluid is preferably circulated during this process. The cleaning fluid may be circulated down the annulus between the drill string and the surrounding subsurface formation, and back up the bore of the drill string.

[0139] In one aspect, the method 300 also includes circulating a second fluid into the annulus across the subsurface formation to remove at least a portion of the rock material that has broken off. This is provided at Box 360. The second fluid may be a reactive fluid that has substantially the same composition as the first fluid, or it may be different from the first fluid. In the latter instance, the second fluid preferably contains a viscosifier to facilitate the transport of rock material up the bore of the working string during reverse-circulating. The second fluid may thus be a cleaning fluid.

[0140] Additional steps may be taken to further induce the bottom portion of the wellbore to collapse. In one approach, the operator may reduce fluid pressure within the open-hole portion of the wellbore. This is seen at Box 370. In one aspect, the fluid pressure is reduced by reverse circulating a second fluid into the deviated portion of the wellbore, where the second fluid is a collapsing fluid that has a density that is less than a density of the first fluid. The collapsing fluid may comprise, for example, a gas or a light hydrocarbon fluid. In another approach, the operator may further induce the bottom portion of the wellbore to collapse by changing the temperature of the bottom portion of the formation. This is indicated at Box 375. For example, the temperature of the portion of the formation immediately adjacent to the wellbore may be increased by at least 100° F.

[0141] Yet additional steps may be taken to enlarge the annulus in the open-hole portion of the wellbore. For example, nozzles may be run into the end of the working string. The first fluid may then be jetted through the nozzles and against the rock matrix. Alternatively, the first fluid may be oscillated within the wellbore.

[0142] The method 300 further includes producing hydrocarbon fluids from the subsurface formation. The producing step is seen at Box 380. In a preferred embodiment, the hydrocarbon fluids comprise primarily light hydrocarbons that are produced through a pre-perforated liner. These would include methane and ethane. Of course, some acid gases may also be produced in the process.

[0143] The steps in the method related to enlarging the annulus or inducing a collapse of the wellbore may be repeated one or more times. In addition, the method 300 may further comprise running the drill string back into a bottom portion of the subsurface formation, and rotating the drill string and connected drill bit to grind out collapsed rock material. A cleaning fluid may be circulated through the drill string during this process.

[0144] The method 300 in its various embodiments provides a way to create a fracture network in a low-permeability formation. The method 300 takes advantage of hydraulic forces and chemical action working against the formation in order to change in situ stresses and intentionally induce wellbore collapse. 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.

Claims

Claims What is claimed is:

1. A method for improving hydrocarbon production from a subsurface formation, comprising:

drilling a wellbore from a surface into a subsurface formation;

running a working string into the wellbore, the working string extending into the subsurface formation, and forming an annulus between the working string and the surrounding formation;

based on an analysis of a mineralogy of a rock matrix making up the subsurface formation, selecting a fluid as a first fluid to induce, via chemical interaction, (i) a swelling of the rock matrix, (ii) a disaggregation of the rock matrix, (iii) a dissolution of particles within the rock matrix, or (iv) combinations thereof;

flowing the first fluid into the annulus across the subsurface formation in order to break off rock material from the subsurface formation and enlarge the annulus; and

producing hydrocarbon fluids from the subsurface formation.

2. The method of claim 1, further comprising:

circulating a cleaning fluid into the annulus across the subsurface formation to remove at least a portion of the rock material that has broken off.

3. The method of claim 2, wherein circulating the cleaning fluid comprises reverse- circulating the cleaning fluid into the annulus across the subsurface formation and back up the bore of the working string.

4. The method of claim 3, wherein the cleaning fluid contains a viscosifier to facilitate the transport of rock material up the bore of the working string during reverse-circulation.

5. The method of claim 1, further comprising:

running the drill string back into the subsurface formation;

drilling out broken rock material from the wellbore; and

circulating a cleaning fluid through a bore of the drill string to at least partially remove the broken rock material.

6. The method of claim 1, further comprising:

installing a pre-perforated liner along a bottom portion of the wellbore before running the working string into the wellbore; and

wherein the hydrocarbon fluids are produced through the pre-perforated liner.

7. The method of claim 1, wherein:

the method further comprises injecting a fluid through the wellbore and into the subsurface formation; and

producing hydrocarbon fluids from the subsurface formation comprises:

completing a production well separate from the wellbore; and

producing hydrocarbon fluids from the production well.

8. The method of claim 1, further comprising:

continuing to flow the first fluid until enough rock material is broken off from the bottom portion of the subsurface formation to change in situ stresses within the subsurface formation and induce at least partial collapse of the wellbore.

9. The method of claim 8, further comprising:

circulating a cleaning fluid into the annulus across the subsurface formation to remove at least a portion of the rock material that has collapsed; and

producing hydrocarbon fluids from the subsurface formation through a network of created fractures above the collapsed wellbore.

10. The method of claim 8, further comprising:

further inducing the wellbore to collapse by reducing fluid pressure within the deviated portion of the wellbore.

11. The method of claim 10, wherein the fluid pressure is reduced to below initial reservoir pressure.

12. The method of claim 10, wherein reducing fluid pressure comprises circulating a collapsing fluid into the deviated portion of the wellbore, the collapsing fluid having a density that is less than a density of the first fluid.

13. The method of claim 12, wherein the collapsing fluid comprises a gas or a light hydrocarbon fluid.

14. The method of claim 1, wherein the first fluid is an organic solvent.

15. The method of claim 1, where the first fluid comprises a detergent which comprises a quaternary ammonium compound.

16. The method of claim 1, wherein the first fluid comprises an acidic fluid which comprises at least 10% by volume hydrochloric acid, acetic acid, or formic acid.

17. The method of claim 1, wherein the first fluid comprises an oxygen-releasing compound which comprises hydrogen peroxide, sodium perborate, sodium percarbonate, sodium persulfate, tetrasodium pyrophosphate, or urea peroxide.

18. The method of claim 1 , wherein the first fluid comprises a bleaching compound which comprises sodium hypochlorite or calcium hypochlorite.

19. The method of claim 8, further comprising:

further inducing the wellbore to collapse by changing the temperature of the formation immediately adjacent to the bottom of the wellbore, and

wherein changing the temperature of the formation comprises increasing the temperature of the formation immediately adjacent to the bottom of the wellbore by at least 100° F.

20. The method of claim 1, further comprising:

installing nozzles proximate the end of the working string; and

jetting the first fluid against the rock matrix in order to further break off rock material from the bottom portion of the subsurface formation and enlarge the annulus.

21. The method of claim 1 , further comprising:

oscillating the first fluid in order to further break off rock material from the bottom portion of the subsurface formation and enlarge the annulus.

22. The method of claim 21, wherein oscillating the first fluid comprises reciprocating a downhole plunger, cyclically changing downhole fluid pressure using a pump at a surface, or generating ultrasonic frequencies downhole in excess of 10 kHz.

23. The method of claim 1, wherein:

the subsurface formation is a rock matrix comprising shale;

the wellbore is completed substantially horizontally along the bottom portion of the subsurface formation; and

a volume of collapsed shale is at least about 100 cubic meters.

24. A method for improving hydrocarbon production from a subsurface formation, comprising:

drilling a wellbore into a subsurface formation, the subsurface formation comprising shale, and the subsurface formation having an initial permeability that is less than about 10 millidarcies;

continuing to drill the wellbore proximate a bottom portion of the subsurface formation such that the wellbore extends substantially horizontally through the bottom portion of the subsurface formation;

running a working string into the wellbore, the working string extending into the bottom portion of the subsurface formation, and forming an annulus between the working string and the surrounding formation;

selecting a first fluid to produce via chemical interaction (i) a swelling of the shale, (ii) a disaggregation of the shale, (iii) a dissolution of particles within the shale, or (iv) combinations thereof;

circulating the first fluid into the annulus across the subsurface formation and back up a bore of the working string in order to break off rock material from the bottom portion of the subsurface formation and enlarge the annulus;

reducing pressure in the bottom portion of the wellbore in order to induce at least a portion of the wellbore to substantially collapse;

producing hydrocarbon gasses from the subsurface formation.

25. The method of claim 24, wherein reducing pressure in the wellbore comprises circulating a collapsing fluid into the deviated portion of the wellbore, the collapsing fluid having a density that is less than a density of the first fluid.

26. The method of claim 25, wherein the collapsing fluid comprises (i) a gas, (ii) a hydrocarbon fluid, (iii) water having a salt content less than about 1% by mass, or (iv) an acidic fluid.

27. The method of claim 24, further comprising:

selecting a cleaning fluid for carrying rock material from the subsurface formation that has broken off; and

circulating the cleaning fluid into the annulus across the subsurface formation to remove at least a portion of the rock material that has broken off.

28. The method of claim 27, wherein the cleaning fluid contains a viscosifier to facilitate the transport of rock material up the bore of the working string during reverse-circulating.

29. The method of claim 27, wherein the cleaning fluid is a reactive fluid that has substantially the same composition as the first fluid.

30. The method of claim 27, further comprising:

withdrawing the working string incrementally while continuing to circulate the cleaning fluid.

31. The method of claim 28, further comprising:

changing a temperature of the cleaning fluid before circulating in order to change a temperature of the formation immediately adjacent to a bottom portion of the wellbore.

32. The method of claim 27, further comprising:

again circulating the first fluid into the annulus across the subsurface formation and back up a bore of the working string in order to break off additional rock material from the bottom portion of the subsurface formation and further enlarge the annulus

33. The method of claim 24, wherein circulating the first fluid comprises reverse- circulating the first fluid.

34. A method for improving hydrocarbon production from a subsurface formation comprising a rock matrix, the method comprising:

drilling a wellbore into the subsurface formation using a drill string and connected drill bit;

selecting a first fluid which chemically interacts with the rock matrix adjacent to the wellbore to weaken the rock matrix;

flowing the first fluid into the wellbore and across the subsurface formation such that the first fluid contacts the rock matrix along the subsurface formation adjacent to the wellbore; and

withdrawing the drill string from the subsurface formation.

35. The method of claim 34, wherein the first fluid is flowed down an annulus formed between the drill string and the surrounding subsurface formation and up the drill string to a surface before withdrawing the drill string from the subsurface formation.

36. The method of claim 34, further comprising:

rotating the drill string and a connected rock grinding device back along the subsurface formation to grind out at least a portion of broken rock material.

37. The method of claim 36, wherein the first fluid chemically interacts with the rock matrix to cause a swelling of the rock matrix, dissolution of inorganic particles within the rock matrix, or dissolution of organic binders within the rock matrix.

38. The method of claim 36, further comprising:

circulating a cleaning fluid through the drill string while rotating the drill string and connected rock grinding device back along the subsurface formation, wherein the cleaning fluid has substantially the same composition as the first fluid, and wherein the cleaning fluid is circulated down the annulus between the drill string and the surrounding subsurface formation, and back up a bore of the drill string.

39. The method of claim 34, further comprising: circulating a collapsing fluid into the such that the collapsing fluid further induces formation collapse;

rotating the drill string and a connected rock grinding device back along the subsurface formation to grind out at least a portion of newly broken rock material;

circulating a cleaning fluid through the drill string while rotating the drill string and connected rock grinding device back along the subsurface formation to at least partially clean out the wellbore; and

withdrawing the working string incrementally while continuing to circulate the cleaning fluid.

40. The method of claim 39, further comprising:

placing a collapsing fluid into the wellbore such that the collapsing fluid further induces formation collapse; and

producing hydrocarbon fluids from the subsurface formation.