METHODS AND SYSTEMS FOR STIMULATING BIOGENIC PRODUCTION OF NATURAL GAS IN THE SUBSURFACE

CROSS-REFERENCE TO RELATED APPLICATION

This application claims priority to International Patent Application No. PCT/US2006/039352, filed October 5, 2006, which is incorporated by reference herein. For purposes of the United States, this application is a continuation of International Application No. PCT/US2006/039352, filed October 5, 2006, which designates the United States.

BACKGROUND Unconventional sources of oil and gas have received increased attention in recent years, driven by a progressively more limited supply of conventional sources and the resulting price pressures that have enhanced the economic feasibility of the more difficult methods required for recovery of these types of resources. Conventional sources typically include coal, liquid, or gas fossil fuels, which can be exploited using primary recovery methods. Typically, these reservoirs can be tapped using standard drilling techniques to drive or pump the oil or gas to the surface for recovery. These include the majority of past and current crude oil and natural gas production sites across the world. Conventional sources can even be extended to include those that require secondary recovery methods, such as water flooding, to enhance recovery in adjacent or peripheral production wells. In general, primary and secondary recovery methods refer to the production within similar types of geological formations, with secondary methods employed once primary methods have recovered the majority of the easily accessible resource. Enhanced recovery methods for crude oil, including thermal and CO ₂ injection, have been applied widely to address remaining resources after primary and secondary methods have been employed. For the most part, unconventional resources of oil and gas are considered to be those that are not subject to primary or secondary recovery methods, and they typically include wholly different hydrocarbon reservoirs. The most identifiable of these resources are coal-bed methane and bitumen (oil sands), both of which have been the target of large-scale recovery operations in North America and elsewhere within the past decade. Locations of coal beds, such as those widespread across the United States, have been thoroughly mapped, and recovery of the methane associated with some of these deposits has proven to be a relatively

straightforward process that involves dewatering the surrounding subsurface to produce a favorable pressure gradient for release of sorbed gas. Bitumen deposits, such as the vast oil sands present in western Canada, can often be found close to the surface, facilitating recovery and separation of this energy-rich material. This is an energy-intensive process but is made economical when the price of the recoverable resource is high.

A similar economic impediment to recovery is associated with an even more promising reservoir for energy that lies in the huge oil shale deposits found in the Midwestern and Western United States, as well as other parts of the country and the world. Because maturation of the organic matter that eventually forms subsurface hydrocarbon deposits is a slow process, portions of this carbon are present in a non-flowing state that is less amenable to recovery. While more natural, easily-recoverable fractions have either formed in or migrated to permeable reservoirs, the less mature hydrocarbons can be trapped in less permeable units. This is a particular concern in areas that are not subject to recharge and remain anoxic, where large amounts of buried organic matter can form shale rock (with kerogen as the general term for the organic fraction of shale). Thickness of shale deposits range up to over 2000 feet in deposits such as the Piceance Basin in Colorado, and they tend to be continuous and not density-stratified. Crude oil can be recovered from these deposits if the kerogen material in the shale can be converted to a liquid form, and estimates of 25 to 50 gallons of oil per ton of shale have been documented. However, the process of extracting oil from shale is commodity-intensive, requiring both an abundance of water and a ready supply of energy to drive production. Current retorting processes carry additional environmental impacts, particularly those that involve mining to uncover the shale deposits and extraction techniques that yield undesirable by-products. Surface mining for deposits that can lie under more than 500 feet of overburden means that the scale of impact is considerable. A variety of in situ retorting techniques also exist, and thermal conductive heating is another in situ technique that is the most extensively studied and perhaps the most innovative technology. Because of the limitations of existing technologies (uneconomic process for surface retorting of oil shale; limited recovery of energy from hard-to-mine coals), there has been increasing emphasis on in situ processes of resource plays. With an in situ process, a physical/chemical reaction is initiated in the subsurface that produces high-quality energy (e.g., methane or hydrogen gas or a light oil). Two examples are thermal conductive heating of oil shales and underground gasification of hard-to-mine coal deposits.

The thermal conductive heating process relies on electrical heating in a network of injection points that are driven through the entire thickness of the formation. The conductive process slowly raises the matrix temperature over the course of several years to a temperature range of 550 ⁰ F to 750 ⁰ F, at which oil and gas is naturally extracted from the shale via a combination of physical and chemical modifications of the subsurface environment. As a result, a product containing two-thirds liquid and one-third gas is generated and collected through a series of production wells located within the treatment area. Similar to the gas, the light hydrocarbon-rich liquid product is suitable for use with limited need for upgrading, increasing the economic feasibility of the process. The in situ thermal conductive heating process is able to pyrolyze the oil shale deposit throughout the entire length of the column, but it does not convert 100% of the organic material (kerogen) in the formation to a recoverable resource. Interior portions of the oil shale, will likely contain still high amounts of kerogen or other complex organic by-products, even though the typical decommissioning procedure for the production system involves flushing and treatment of the heated zone to remove any potential groundwater contaminants.

A variety of modifications on the thermal conductive heating process are under development to deal with site-specific geological characteristics that necessitate a more robust approach for efficient recovery. Thermal in situ conversion does not generate any surface waste material surface retort methods do, but both the initial capital costs and the operational costs associated with this technique means that production must be high enough to meet this intensive outlay. Other technologies are being developed for in situ processing of oil shale. Most of these include the addition of heat in some form, such as steam, explosives, or other methods.

There has been limited recovery of hard-to-mine coal deposits via the underground coal gasification process (UCG). Underground coal gasification is a straightforward process that involves the injection and ignition of an oxidant gas (air or pure oxygen) directly into a coal formation and then allowing the ignition front to propagate. The combustion process must be controlled precisely, particularly with respect to water intrusion, which is partially controlled by the formation of a steam jacket surrounding the combustion zone. As the coal is gasified, cavities develop in the formation and serve as the site for deposition of solid waste material. During the process, the combusted coal releases pressurized gas, including methane and carbon dioxide, that is collected in a recovery well screened in the same interval. In

general, this gas is a high quality product (100 to 400 BTU/scf) that conserves up to 70% of the original energy content of the coal. Underground coal gasification is a particularly attractive alternative when mining of the coal deposit is difficult or impossible. Underground coal gasification projects have been performed at several sites in the former Soviet Union and has also been tested in the western United States in the 1980s. Since 1990 large field trials have been completed in Spain, China, and Australia.

The development of methods to stimulate biogenic methane production is a key goal for increasing energy recovery from in coal and shale deposits exploited by in situ processing techniques. Biological production of gas from a complex substrate such as coal or kerogen in shale requires the presence of a number of different microbial species. These hydrocarbon reservoirs contain highly complex carbon structures, typically as a mix of long-chain alkanes and other complex aromatic and heterocyclic compounds. Without a source of oxygen, these compounds must be transformed anaerobically, either via anaerobic respiration pathways or fermentatatively. Such decomposition pathways lead to the formation of shorter-chain organic acids and alcohols, which serve as substrates for syntrophic acetogens that generate acetate as well as carbon dioxide and hydrogen gas. However, fermentative metabolism is possible from a thermodynamic standpoint only if the concentration of the products is maintained at low levels. This is made possible when organisms capable of utilizing single- carbon compounds and hydrogen exist. Methanogens occupy this ecological niche in a variety of environments, including in deep subsurface formations. Methane is the primary endproduct of their metabolism, and biogenic processes are at least partially responsible for subsurface natural gas.

The physical and chemical characteristics of an oil shale or coal resource that has been subjected to in situ processing is likely to be amenable to supporting large-scale production of biological methane after the processing has been terminated. In both shale and oil projects, considerable hydrocarbon will remain in the formation in the form of a rich mix of unextracted gases, liquids, and/or unreacted solid hydrocarbon. In the case of oil shale, horizontal fractures form within the formation as a result of the high temperature heating, providing conduits that facilitate growth of biomass for conversion of remaining hydrocarbons to methane. Underground coal gasification projects produce a large cavity surrounded by fractured unreacted coal deposits, providing a large surface area for the growth of methane-producing microorganisms. Finally, as the shale and coal deposits that have been

subjected to the heating from the in-situ processing cool, they will slowly descend through a wide band of temperature regime that is suitable (and in some cases optimal) for methanogic activity (i.e., 25 to 80 degrees centigrade). The combination of a rich mixture of hydrocarbons, large surface area, and elevated tempetures that are created following these processes make them ideal bioreactors for further conversion of the residual energy content of the formation into natural gas.

With domestic production of natural gas unable to meet U.S. consumption demand, the potential to close the gap between production and consumption exists if techniques can be developed to take advantage of this resource. DRAWINGS

Some specific example embodiments of the disclosure may be understood by referring, in part, to the following description and the accompanying drawings.

Figure 1 is a cross-sectional schematic showing the well network in a solid hydrocarbon deposit following an in situ thermal conductive heating process. Figure 2 is a cross-sectional schematic showing biogenic natural gas production in the vicinity of the solid hydrocarbon deposit.

Figure 3 is a cross-sectional schematic showing the recovery of biogenic natural gas.

While embodiments of this disclosure have been depicted, described, and are defined by reference to example embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure. SUMMARY

The present disclosure relates to methods that stimulate natural biological activity in subterranean formations.

The present disclosure provides, according to one embodiment, methods comprising performing in situ heating of a non-liquid hydrocarbon layer of a subterranean formation and allowing biogenic production of methane from the non-liquid hydrocarbon. In some embodiments, an injection fluid may be injected into the formation to provide conditions

suitable for anaerobic biological degradation of the hydrocarbon by indigenous microorganisms.

The features and advantages of the present disclosure will be readily apparent to those skilled in the art upon a reading of the description of exemplary embodiments, which follows. DESCRIPTION

The present disclosure relates to methods that stimulate natural biological activity in subterranean formations, and more particularly to methods and systems for stimulating anaerobic biologic production of methane from non-liquid hydrocarbon-bearing subsurface formations. In the descriptions that follow, the formation is generally considered to be shale or coal, but the disclosure is not intended to be limited to these types of deposits. Rather, shale or coal may be used in certain embodiments because, among other things, (1) their abundance within the United States, and (2) the difficulty in recovering energy from these resources are specifically addressed by the present disclosure. The methods of the present disclosure generally involve relatively small cost investments and are environmentally friendly.

The methods of the present disclosure generally comprise using a subsurface formation comprising a non-liquid hydrocarbon that has been treated using in situ thermal heating or coal gasification and a microbial population, utilizing wells in the formation, and providing conditions suitable for anaerobic biological degradation of the hydrocarbon by themicrobial population. Such methods may facilitate increased transport of water and nutrients, as well as improved contact between these components and both the substrate (e.g., shale or coal) and microbial population. By stimulating growth of the microbial population, natural gas production may be enhanced. Microbial Population An indigenous microbial population should be present in the formation. This microbial population may generally capable of at least partially converting a non-liquid hydrocarbon, such as coal or kerogen in oil shale, to methane.

The microbial community that develops within a subsurface environment depends highly on the type of substrates that are initially present. The term "substrate" refers to a microbe's energy source, and may be extended to include the source of carbon for cell synthesis as well. The degree of microbial growth may depend on a number of other determining factors, including the presence of electron acceptors, nutrients, water, and

transport within the formation, but the type of organisms present are most highly dependent on the substrate type. In a deposit, the carbonaceous kerogen or coal may serve as the substrate for one set of organisms that have evolved to degrade these complex organic compounds. However, these organisms may not have enzyme systems capable of completely degrading these compounds into inorganic or mineral forms, e.g. CO ₂ or CH ₄ . Alternatively, they may partially degrade a compound to an intermediate because they are capable of gaining more energy from the initial substrate. The complexity of the microbial community is typically enhanced by this incomplete mineralization of substrates, i.e. the formation of byproducts during primary metabolism. These may be a mix of carbonaceous and inorganic compounds that form during partial degradation of more complex substrates, but they may serve as suitable substrates to support growth of a wide variety of other species. These organisms may convert these intermediates to more energetically-stable end products such as H ₂ O, CO ₂ , and CH ₄ .

In a coal or oil shale formation where biogenic methane production is occurring, the environment must be largely anoxic. This is because the organisms that mediate the final step in the conversion process may function only in environments where oxygen is not abundant. They may form a relatively specialized metabolic niche, utilizing substrates that are not energy-rich and thriving only when competing processes (e.g., sulfate-reduction) are limited. Methanogens may be restricted to a fairly narrow range of substrates, and each species may typically only use one or two different compounds. These may include acetate, hydrogen, formate, methanol, ethanol, carbon monoxide, methylated amines, and other 1- or 2-carbon compounds. As noted above, they may rely on the production of these substrates during the utilization of more complex compounds by other populations. Therefore, the diversity of the native flora within a biologically-active coal or oil shale deposit may be expected to be similar to established models for anaerobic systems. This has been confirmed in published literature studies using laboratory microcosms and molecular testing of shale-derived source material.

In general, this anaerobic food web that is responsible for converting complex organic carbon to methane does so in a process that involves at least three steps, with different organisms responsible for each step. The most complex hydrocarbons (e.g., long-chain straight and branched alkanes, polycyclic aromatics, and other kerogen structures) may be depolymerized via abiotic or biotic process, such that they can be metabolized to compounds

with slightly lower free energy by non-specific hydrolytic and fermentative organisms. These organisms require no external electron acceptor and attack easily accessible portions of the hydrocarbon molecule, thereby releasing monomers and other short-chain acids and alcohols that contain partially oxidized carbon. Concurrently, H ₂ may be formed during the fermentation process as the primary reduced product. This step in the degradation may be thermodynamically favorable and may proceed so long as water is present. The second stage may require the presence of a population that may be capable of utilizing the shorter chain alcohols and acids produced during the previous step. These are fermentative organisms that may further oxidize the carbon-containing compounds to acetate and carbon dioxide, with H ₂ as the primary reduced product. However, the difference between this step and the previous step is that there may be little energy to be gained from metabolizing these products. In fact, the fermentation of short chain carbon compounds may typically be unfavorable from a thermodynamic perspective, meaning that there is no net energy benefit for the mediating organisms. By the law of mass action, the only way for the fermentation process to proceed is if the concentration of products is kept low enough such that this energetic limitation is minimized. In most environmental conditions, this may occur when organisms are present that are able to use the fermentation products as a growth substrate. Therefore, the fermenters that mediate the second step in the overall process may generally be referred to as syntrophs because of their interdependent relationship with another population. In this case, the organisms that serve this important role in the syntrophic relationship are the methanogens, and they may be responsible for the final stage of the shale degradation process. As noted previously, there may be a number of different types of methanogens, but the species of importance to this process may be those that utilize acetate (acetoclastic methanogens) or H ₂ plus CO ₂ (hydrogenotrophic or autotrophic methanogens). The former species may convert acetate to a mixture of methane and carbon dioxide, and the latter species may use this carbon dioxide to produce a mixture of methane and water. Additional methane may be produced via hydrogenotrophic methanogenesis using the hydrogen and carbon dioxide generated in the earlier fermentation steps.

The conversion of the entire carbon reservoir present in coal or the kerogen portion of shale to natural gas may require the presence of each of these population types, though the fraction of methane derived via the syntrophic portion of the cycle is not clearly established. It is assumed that a productive well may rely solely on the initial fermentation of complex

carbon into H ₂ , CO ₂ , and acetate, followed by the generation of methane from these products. It has been established that the majority of biogenic methane in subsurface hydrocarbon deposits is due to hydrogenotrophic (autotrophic) rather than the acetoclastic pathway.

In addition to indigenous microbial populations already present in the subsurface deposit, a non-indigenous (i.e., exogenous) culture may be added, whether it is a single species or an enriched consortia. However, the addition of an active culture to injection wells may be coupled to this stimulation process in an effort to speed up degradation and subsequent gas formation. This approach (termed bioaugmentation) may be accomplished using standard techniques for inoculating subsurface environments, including, in some cases, pressurized delivery to ensure adequate delivery to deep subsurface formations.

The use of non-indigenous microbial populations is of particular relevance for the portions of the hydrocarbon formation that has been treated via in situ thermal conductive heating or coal gasification. The peak temperatures used in thermal conductive heating (>550°F) and coal gasification (>1100°F) may not allow for survival of any indigenous organisms within some or all portions of the treated area. Because elevated temperatures are present for several years during the active recovery phase of in situ thermal conductive heating or underground coal gasification, there may be little or no ability for microbial growth in the formation until the process is stopped. Thereafter, water flushing within the pyrolyzed area is initiated and the temperatures decrease below 170 to 180 ⁰ F. This is a relatively slow process following in situ thermal conductive heating because the freeze wall must thaw. Groundwater containing active microbial populations re-enters the treated area through advective transport, permitting re-colonization. However, if this re-colonization is further hindered by slow groundwater transport or other identified factors, then inoculation with an exogenous culture may be considered. Utilization of Formation Following Application of In Situ Thermal Conductive

Heating Technology or Coal Gasification

Within coal or shale, there is typically an existing fracture network. However, communication between fractures is minimal, and apertures for entry of fluids are sufficiently small to result in very low initial permeability within many formation. The accessibility of the formation may be increased by enhancing transport of components, which may allow for increased production and recovery of natural gas. The formation of lateral fractures during the thermal treatment process increases the in situ surface area, creating a formation that is

capable of much higher rates of biogenic natural gas formation. For example, gas and water that was previously confined in pores in the coal or shale matrix are more accessible to microbes, and delivery and transport of other liquid and gaseous constituents (such as acetate, dissolved nutrients, CO ₂ , or H ₂ ) can be considered to further enhance methane production. Similarly, microbes have access to a much larger percentage of the organic material present in the non-liquid hydrocarbon-bearing formation once it has been heat-treated. There is also the potential for increased spatial heterogeneity within the bedrock, which promotes the formation of biofilms as well as other microbial niches. Thus, more species can be ecologically competitive within the same formation volume. Conditions created by in situ thermal conductive heating and coal gasification are favorable for further biological activity. Conduits created by the release of liquid from the oil shale facilitate transport of microbes and increased contact with substrate, as well as lower internal formation pressures. Cavities formed in coal deposits during the gasification process provide an ideal reservoir for solubilization and utilization of organic carbon substrates, resulting in enhanced microbial growth.

Of importance is the partial conversion of portions of the coal and kerogen in the oil shale to other organic carbon components during the pyrolysis process. This includes smaller- chain aliphatics with a higher degree of hydrogenation, which may be more amenable to further degradation by a wider range of microorganisms. In general, by-products of pyrolysis will be more soluble in groundwater and more bioavailable, thus facilitating further conversion to natural gas.

No specific analyses are required prior to stimulation; although use of previous geophysical characterization and delineation of the formation is assumed such that the process can be optimized. The techniques required for these characterizations are known to persons of ordinary skill in the art. Additional characterization methods may include, but are not necessarily limited to: (1) Soil borings and other geotechnical testing designed to determine the depth of the coal or shale interval and associated overburden, as well as formation pressures, pore size and particle distributions; (2) Soil borings designed to determine the lithology of the formation, including compositional ratios and concentrations of key hydrocarbon constituents; (3) Formation water sampling to determine concentrations of dissolved constituents within the coal or shale deposit, including such parameters as oxidation-reduction potential, dissolved carbon, methane, acetate, and hydrogen; (4) Slug

tests, tracer tests, or other standard methods to determine hydrologic patterns within the formation, including the identification and influence of other potential water-bearing units in the vicinity; (5) Microcosm assays to determine the ability of aliquots from the targeted deposit to produce natural gas, the rates associated with this activity, and to identify any nutrient deficiencies that may be limiting gas production; and (6) Genotype or phenotype- based genetic probing of solid and aqueous phase samples to identify and/or enumerate specific organisms or populations that might be key in converting complex substrates into natural gas. All of these characterization steps may be conducted prior to the implementation of the technology associated with the present disclosure. Injection strategies may be delivered to the subsurface using a variety of methods.

The key component of all injection strategies is the utilization of an existing well and fracture/cavity network that has been established within an interval of interest. Stimulation of biogenic natural gas production may be conducted in identical locations and be delivered to the subsurface in the same borehole within the same depth interval. Therefore, the addition of these injection strategies may be able to utilize existing screened intervals, packing, and casing. This is true regardless of whether the injection strategy is gaseous or liquid. In some embodiments, the injection strategy may necessitate an alteration in the existing wellbore for more efficient delivery. Additional injection strategy delivery wells may be used to target these areas as needed to stimulate or maintain natural gas production. However, the present disclosure is not intended to be limited to a particular delivery approach.

The modification of pre-existing wells, either to serve as injection wells for liquid or gaseous components, or as recovery wells, relies on standard techniques known to a person of ordinary skill in this art. The wells in the present disclosure are not intended to be limited to a particular number or configuration but should be based on knowledge of the horizontal and vertical expanse of the resource at a particular site.

Heater wells in an in situ thermal conductive heating process are typically spaced 20 to 100 feet apart, which is an appropriate distance to serve as injection or recovery wells for biogenic methane production and recovery. These wells can serve as injection wells once the electric resistance heaters are removed from the borehole; well conversion is facilitated by the use of a wide, open borehole during typical drilling practices.

Production/recovery wells in an in situ thermal conductive heating process are typically placed within 20 to 100 feet of a heater well and spaced 40 to 100 feet from the

closest production/recovery well. Use of a hexagonal configuration results in 6 heater wells for each production/recovery well, which is an appropriate distance to serve as injection or recovery wells for biogenic methane production and recovery. Little or no modification to these wells is needed. Monitoring wells are typically distributed outside of the treated area during in situ thermal conductive heating. These wells can be converted to recovery wells or extraction wells, or used for continued monitoring of the process.

Water injection wells can be used during the later stages of an in situ thermal conductive heating process to enhance recovery. These may rely on conversion of monitoring wells, and they serve as ideal wells for use in biogenic methane production and recovery. Preexisting dewatering wells located within the treatment area are already equipped with a submersible pump and can also be used for recycling of water through the formation to enhance biogenic activity.

One application of thermal treatment technologies utilizes freeze walls to stop inward groundwater migration. Freeze wells in an in situ thermal conductive heating process are typically placed 8 feet apart along the outer perimeter of the treated area. The borehole diameter of a freeze well is wide enough for retrofitting, but the steel casing that is necessary for its construction makes it more difficult to convert. In addition, the freeze wells are located sufficiently far outside of the original treatment area (>100 feet) that use of these wells for injection or recovery is not practical. As a result, in the present disclosure, it is not anticipated that freeze wells will be used for biogenic methane production and recovery.

Underground coal gasification does not rely on creating an area contained by a freeze wall, but uses the pressure of the combustion gases to dewater the in-situ gasification area. Therefore, the only wells necessary are injection wells and production/recovery wells, along with monitoring wells as needed. Injection wells are open boreholes that serve as the location for ignition. These wells can also serve as injection wells during biogenic methane production and recovery. Production wells in underground coal gasification are typical gas recovery wells that are placed at the boundary of the in situ gasifier. These can serve as injection or recovery wells for biogenic methane production and recovery with little or no modification. The creation of a large cavity during the gasification process may necessitate the drilling of additional injection or recovery wells to provide adequate distribution within the formation.

Injection of liquid or components dissolved in liquid may promote continued gas production following completion of the active portion of an in situ thermal conductive heating or coal gasification project. In one embodiment, where only anaerobic conditions are maintained, the liquid must be oxygen-free. Therefore, it should not be kept in equilibrium with air prior to injection, and it should be sparged with an anoxic gas to remove any residual oxygen beforehand. This may be easily accomplished using standard sparging techniques. Further, storage and handling in on-site containers allows for the maintenance of oxygen-free conditions. The injection fluid may also comprise one or more selected from the group consisting of macronutrients, vitamins, trace elements, and buffers. Applications of gaseous compounds to the formation may use a variety of different types of gas, including but not limited to air, oxygen, nitrogen, carbon dioxide, and hydrogen. In a strict case, where only anaerobic conditions are maintained, the gas must not be air or oxygen. Nitrogen gas is relatively safe and inert, though it could serve as a nitrogen source for promoting growth if certain N ₂ -fixing organisms are present or used as an inoculum. Carbon dioxide can be used to provide a carbon source for growth of autotrophic organisms, including autotrophic (e.g., hydro genotrophic) methanogens that convert H ₂ and CO ₂ to methane. The addition of large amounts of gaseous carbon dioxide will lower the pH of the formation water, which will aid in the dissolution of certain organic and minerals. As a result, the bioavailability of key constituents, including the complex organics present in kerogen, can be enhanced in the presence of CO ₂ . In certain cases, undesirable dissolution of metals may occur, but that is typically not a concern for upstream processes.

Similarly, hydrogen gas can be used to provide an electron donor for growth of homoacetogens and autotrophic methanogens. It has been documented that autotrophic methanogenesis is the major pathway by which natural gas is formed in shale deposits, meaning that the formation of H ₂ as a by-product of kerogen degradation drives the productivity. Therefore, the addition of H ₂ stimulates growth of these methanogenic species, and accelerates the rate of natural gas production. This is because dissolved inorganic carbon is typically not a limiting factor in promising shale deposits, and conversion of this source of CO ₂ to methane and growth of new cells occurs once H ₂ is supplied in abundance. By providing an initial increase in this population, thermodynamic limitations in certain steps of the degradation process are minimized. Specifically, fermentation and other syntrophic reactions are not particularly favorable unless H ₂ is utilized during these reactions. A new

population of hydrogenotrophic methanogens fills this need, particularly once the fracturing fluid (H ₂ ) has disappeared from the formation either through dissipation or biological utilization. It should be noted that typical mixtures of hydrogen gas are more explosive than the other two gases mentioned, but practitioners in the field are fully capable of delivery hydrogen to the subsurface in a safe and efficient manner. Injection Strategies

There are a number of approaches that can be combined in an injection strategy to enhance overall biological activity, including the use of additional fracturing within an oil shale formation. For example, one or more of the following may be injected into the formation: nutrients, surfactants, additional heat, and exogenous microbial cultures.

In some embodiments, a fracture network may be created through the use of pneumatic or hydraulic fracturing. This is designed to further enhance biological activity by increasing surface area within the formation and improving contact between microbes and the more inaccessible portions of hydrocarbon deposit. This is not considered as a feasible polishing step following coal gasification because the cavity formed within the formation is sufficient for enhanced transport and contact. However, it may be employed following thermal conductive heating if the fracture network generated during pyro lysis is not sufficient for enhanced biogenic gas production. In this approach, existing heater or production wells may be used as fracture wells because they are drilled and isolated in the area of interest, though additional packers or seals may be used in conjunction with fracturing for further efficiency. Therefore, an embodiment of the present disclosure uses these standard techniques for fracturing bedrock, with the understanding that the depth of the shale formation and the desired extent of the fracture network will dictate that the design be appropriate based on site- specific considerations. In hydraulic fracturing, the injection fluid may be liquid, with both water-based and oil-based liquids commonly used, though gases or solids can be fluidizing within this liquid. In either case, a polymer may be added to increase the viscosity of the fluid both in terms of improved handling and increased efficiency during the fracturing process. These soluble polymers may include both non-degradable and degradable forms. The addition of a polymer may prevent pressure loss as the fluid is pumped to depth in a borehole. This may allow for higher injection rates because friction losses are minimized. The pressurized liquid may promote continued gas production.

Pneumatic fracturing may utilize a pressurized gas as the injection fluid. This gas may be highly compressed to create a minimum pressure gradient and to minimize the amount necessary to create the desired effects. Liquid may be added in conjunction with the pressurized gas, typically using high gas-to-liquid ratios to maximize fracture efficiency. The fracturing gas may be selected to stimulate anaerobic activity by indigenous organisms such that the carbon reservoir in the shale is converted to natural gas in a multi-step process to support growth of several populations. This activity may be enhanced by the increased contact between the shale substrate and microorganisms, and because more water may enter the formation following fracturing, the network enhances transport and dissolution of key constituents. In a specific embodiment, pneumatic fracturing is utilized to increase surface area and conduits within an oil shale deposit. The gas selected for fracturing is based on its ability to stimulate microbial growth, and the fracture interval includes the entire shale deposit depth that is at a temperature of less than about 80 ⁰ C.

Applications of pneumatic fracturing may use a variety of different types of gas, including but not limited to air, oxygen, nitrogen, carbon dioxide, and hydrogen.

In some embodiments, proppant may be used to keep an existing or newly-created fracture network open, thus increasing its longevity. This may be useful for situations in which a single recovery event is not sufficient to justify the expense of fracturing and in cases where slow production is expected following the injection event. Proppant may be solid particulates, typically graded sand or synthetic polymers. Other configurations use glass frit or powdered carbon. Proppant may consist of a single material or combinations of materials, and coating is often employed using resins. Resins may be selected based on their ability to harden in place following contact with fracture walls, thus increasing the efficiency of the fracture network. The proppant may be selected on the basis of its ability to stimulate biological activity. For example, there are a variety of organic coatings for solid beads that can be used in a fracturing application. These coatings will partially dissolve into the aqueous phase following introduction to a water-bearing formation, supplying nutrients or substrates to indigenous populations. Alternatively, an inorganic proppant such as activated carbon can be used in fracturing applications because of its high specific surface area. This provides a support matrix for further growth of microbes, as dissolved carbon from the enhanced dissolution and degradation of shale is transported to the proppant. Alternatively, a proppant

impregnated with an exogenous microbial culture can be used in fracturing applications. This would allow for augmentation of the shale deposit in cases where the initial population is low or unsuitable for stimulation.

If employed, the fracturing technology can be selected based on its ability to stimulate either the initial catalysis of the complex organic structures associated with kerogen, the formation of methane through hydrogeno trophic or acetoclastic methanogenesis, or both.

The well network installed for in situ thermal conductive heating or underground coal gasification also provides increased surface area as well as a delivery mechanism in the formation. Accordingly, in some embodiments, the methods of the present disclosure will further comprise providing nutrients to an indigenous microbial population in a formation. Note however that in some embodiments of the present disclosure, the native microbes gain all necessary carbon for cell synthesis from existing sources. However, it is possible that additional carbon sources may be added as part of an injection strategy. These may include soluble organics (acetate or other short-chain acids or alcohols), partially-soluble organics (semi-solid polymers containing high amounts of carbon that is slowly released into solution), or CO2. Suitable examples of soluble organic carbon sources are molasses, acetate, formate, lactate, propionate, butyrate, whey, chitin, methanol, and ethanol. The goal of a carbon-based injection strategy would be to stimulate rapid growth of an initial population, such that subsequent endogenous decay of these organisms may drive further utilization of target hydrocarbons in the formation.

In some embodiments, injection strategies may utilize surfactants to promote favorable chemical changes in the formation. Surfactants are typically organic compounds that contain both hydrophilic and hydrophobic functional groups such that they can enhance the aqueous solubility of oil-phase constituents or reduce fluid viscosity and interfacial tension. Surfactants have long been common in the oil and gas industry to improve transport and enhance productivity within hydrocarbon-rich deposits. They have also been used to increase the bioavailability of partially soluble compounds in ex situ waste treatment, biocatalysis, as well as numerous similar in situ applications. Some embodiments of the present disclosure may incorporate the addition of a surfactant either to facilitate transport or to make specific compounds more bioavailable such that higher rates of conversion to natural gas are achieved.

In some embodiments, additional heat may be provided to enhance productivity. Heat may be used to elevate the temperature of the formation to increase biological growth rates. For example, the formation may be heated to a temperature in the range of from about 30 to about 35 ⁰ C. Because of the existence of heater wells for the thermal conductive process, elevated temperatures within the formation may be achieved using electric resistive heating. However, other methods include steam or hot water flushing. As an example, steam may be added through existing injection or recovery wells, though it is not particularly effective in low permeability zones and requires a very dense fracture network to raise the temperature of the entire formation. There may be a small enhancement of dissolution at the higher temperatures, but the primary benefit will be associated with increased microbial growth. In general, specific growth rates for methanogens and other anaerobes may increase if the temperature is raised from ambient ranges of about 20 to about 25°C to a range of about 30 to about 35°C. A similar increase in methane production rate may accompany the higher growth rates, since the ratio of carbon routed to new cells relative to methane is relatively fixed. Note that the upper temperature limit for deep hydrocarbon layers is apparently near about 80 ⁰ C, and the formation temperature may be increased closer to this level if desired. However, the majority of organisms cultured successfully may be more viable at lower temperatures because of denaturation of proteins and other negative impacts on cellular structure. Generally, care must be taken to keep temperature below 100 ⁰ C because vaporization of water is undesirable. Some formations, such as deep shale deposits, have temperatures that are naturally suitable to enhanced productivity. Accordingly, supplemental heat would not be required in such formations. The necessity for formation heating should be considered a site- specific decision, and it may be utilized if initial productivity is insufficient.

In some embodiments, injection strategies may utilize exogenous microbial cultures to enhance biological activity in the coal or oil shale deposit. The general term for this process is bio augmentation, and it is used in both the remediation industry as well as in oil and gas production. In the latter, it falls into the general category of microbial enhanced oil recovery (MEOS) methods. The addition of enrichment cultures or pure cultures to subsurface has been used in generating coal-bed methane and has been proposed for other hydrocarbon formations. Locating sources of desirable cultures, as well as identification and growth of specific species, follow standard laboratory culturing techniques as well as more innovative genetic testing methods. Bio augmentation may be used to stimulate rapid initial

growth within the formation. However, long-term productivity within the area surrounding an injection well may generally be the result of stimulating indigenous microflora that have been able to exploit a very specialized microbial niche.

The stimulation of microbial growth is generally deemed beneficial, regardless of whether or not it initially results in growth of the desired species, for example, syntrophic fermenters, acetogens, and methanogens. This is because the new organisms may also generate by-products that are beneficial to coal-degrading or shale-degrading organisms, particularly when endogenous decay releases nutrients back into solution. Organisms that are readily capable of exploiting the largest supply of available substrate (non-liquid hydrocarbon deposit and its degradation by-products) may eventually thrive in the stimulated formation. This is particularly promising in light of the fact that these microorganisms have been present for extremely long periods of time, having been able to survive in a likely nutrient-limited subsurface environment following geologic deposition. The fact that the organic-rich hydrocarbon deposits remain largely undegraded suggest that microbial activity is limited by one or more factors, and the use of an injection strategy is designed to address these limitations.

As noted above, the injection strategy may be based on a desire to stimulate either the initial steps in the degradation of complex organic compounds in coal or kerogen in shale, the steps directly leading to methane production, or both. In some embodiments, liquid nutrients may be added to the gas stream during pneumatic fracturing such that the ratio of liquid to gas is very low. This may result in the atomization of liquid particles in the gas stream, and may increase the delivery efficiency of the liquid. Introducing liquid into a gas stream requires very little additional equipment, with metering pumps and proper valving being the most pertinent. In another embodiment, pneumatic fracturing may be conducted solely with gas, and then nutrient-rich liquid may be pumped into the borehole once groundwater seepage into the formation has occurred. This approach may prevent flushing of nutrients by incoming groundwater. In another embodiment, hydraulic fracturing may be conducted with pressurized liquid that is supersaturated with gas such as hydrogen. This may help overcome the solubility limitations that are inherent in gas sparging applications. In another embodiment, gas may be introduced to the subsurface following a pneumatic or hydraulic fracturing event. In this case, the goal of

gas supplementation is not to initiate fracturing, but to provide an additional source of a particular constituent such as H2 or CO2 within the formation. Gas Recovery

Coal and oil shale formations contain a series of pores and fractures that allow for storage and transport of gas within the formation. This natural movement of gas may be enhanced once more numerous and expansive conduits for gas transfer are created by the installation of a recovery well network. The present disclosure may require the creation of additional wellbores for injection of fluids or fracturing; and therefore, the hole may serve the additional role of a recovery well following the completion of the injection or fracturing event. Recovery efficiency may be increased when the entire interval is cased. The conversion of an existing injection, heater, or monitoring well into a recovery well may be a relatively straightforward process, and such retrofitting occurs commonly in conventional oil and gas fields. The installation of a wellhead fully equipped with pumps, valves, and piping may be relatively inexpensive and may not require extensive modification or above-ground infrastructure, providing there is an ability to connect to an existing gas pipeline network.

If the recovery well is configured such that produced gas is entrained in an oil layer or formation water, than sufficient measures must be undertaken to separate the gas. Because the fluid is under pressure, gas concentrations in water may be above typical saturation levels, and gas separation may occur naturally at surface pressures. Alternatively, the recovery well may be screened only in an interval that directly communicates with a gas layer, such that separation of produced gas from formation water is more efficient. The present disclosure is not intended to be restricted to one particular method for recovering gas, and it is understood that there are a number of site-specific considerations that would dictate the particular method selected for gas recovery. If additional recovery wells are needed, they can be placed in whatever configuration is desired either to maximize recovery or to exploit particular areas of the field. Recovery wells may also be placed horizontally if site topography permits. Horizontal wells placed near deposit intervals may be particularly effective in recovering natural gas from the entire depth of the formation. To facilitate a better understanding of the present invention, the following examples of specific embodiments are given. In no way should the following examples be read to limit or define the entire scope of the invention.

EXAMPLE

The following field example details how one specific embodiment of the present disclosure could be implemented.

Oil recovery using the in situ thermal conductive heating process may be implemented within a shale interval present below a thick overburden layer. This would convert a portion of the shale deposit to a high-quality product in a process that utilizes heating, monitoring, and recovery wells while creating a fracture network within the subsurface formation. Following the completion of the project, the treated area is flushed and the freeze wall is allowed to thaw, causing temperatures to decrease and groundwater to reenter the pyrolzyed zone. The existing well network is left in place, and site characterization data collected during the conductive heating phase is available for use in designing and implementing the biogenic methane production phase of the project. This data may include delineation of site hydrogeology using standard geophysical characterization methods. High levels of dissolved inorganic carbon (DIC) may be measured in formation water analyses, which may indicate that biogenic methane production has occurred and is ongoing. This includes analyses of carbon isotope ratios that suggest a link between ¹³ C _DIC and ¹³ C _CH4 that is biogenic in origin, or compositional analyses that indicate that Type I shale with a desirable lack of thermal maturity is the dominant type remaining in the formation. These are strong indicators that the formation contains indigenous flora that are capable of generating significant levels of natural gas following stimulation.

A test well or a series of injection wells would be selected in an area with high hydraulic conductivity due to extensive fracturing. Hydrogen would be used as an injection gas to provide an initial electron donor source for autotrophic growth. High pressure injection with this gas may also increase the effective permeability of the formation, and a water flood would be initiated if water seepage into the formation was not established. Process and performance monitoring would be conducted to assess the establishment of a biologically active zone within the desired shale interval, using off-gas monitoring as the primary evaluation tool. Analysis of dissolved inorganic and organic carbon, as well as radioisotopic analysis, would be implemented as needed to establish distinct chemical signatures of biogenic gas production once the formation reached equilibrium. The production of methane would be monitored over several months to determine if additional injection strategies would be required to supplement the native microbial production rate.

Following the successful establishment of biogenic gas production in a test well, additional production wells would be converted to serve as gas recovery wells. The initial injection point can be converted to a recovery well, or alternatively, additional injections of gas would be performed in this well over time to maintain proper reducing environment and to provide nutrients when needed. Additional water flooding, hydrogen, or carbon dioxide injections are anticipated on a periodic basis to enhance both biogenic production and recovery of natural gas. It is not necessary for these water or gas supplementations to induce additional fracturing, but this approach can be selected if desired. Natural gas is separated out of the gaseous-formation water mixture in an above-ground separation unit, and the product is routed to a pipeline network for transport to central production facilities.

Referring to Figure 1, the test injection location 110 is selected based on its suitability following an evaluation of available site characteristics. The most important component of the injection system 120 is an existing injection well that is screened in an oil shale interval below the significant overburden 125 that is present above most deposits. It is anticipated that this is a stationary skid unit with supporting equipment (such as compressors, pumps, fuel, and mixing reservoir for fluids) present in the near vicinity of the desired injection point. Additional capacity for on-site storage and handling of injection fluids and other amendments is needed. For gas injection, this requires the high-pressure injection of gas (hydrogen, nitrogen, carbon dioxide, or another anoxic gas) into the borehole. For hydraulic fracturing, anoxic water is used as the injected fluid and must be injected at high pressures to overcome hydrostatic pressure within the formation. In either case, the injection fluid is added to an existing borehole or to a new location drilled specifically for the purpose of gas production. Drilling should proceed at least as deep as the first occurrence of the solid hydrocarbon (kerogen) interval 130. This kerogen interval is typically a tight formation with very few natural fractures and little or no entrained water, but in situ thermal conductive heating may generate larger conduits for transport of water such that the effective porosity is relatively high. Oxygen exposure and dissolution of solid organic carbon is limited within this deposit. The borehole is typically screened only in the kerogen interval such that injection fluids will be delivered to an existing fracture network 140 within a portion of the formation that has been treated with thermal conductive heating. This interval can be thick as desired but may not encompass the entire formation. The propagation of injection fluid occurs in the lateral

direction relative to the borehole, and can extend for several meters provided a sufficient fracture network exists and that adequate pressure and volume of fluid is used.

Referring to Figure 2, additional injection strategies can be introduced into the fracture network as needed. Typically, these injection strategies are constituents that have been previously identified (either through bench-scale testing or previous field applications) as beneficial for stimulating biogenic gas production in a particular formation. These can include nutrients, heat, inocula of exogenous microbes, alternative electron donors, or surfactants.

Figure 2 depicts biogenic natural gas production in a fracture 140 in the vicinity of the solid hydrocarbon deposit 130. This occurs via the catalytic degradation of organic carbon present in the kerogen by microbial flora 220, either indigenous microbes or exogenous cultures or both. An enhancement of natural biological activity in the oil shale deposit is promoted by the increased contact between substrate and organisms, the enhanced dissolution promoted by water entering the fracture network, and the more readily degradable, (lower molecular weight) intermediates generated during in situ thermal conductive heating. The Carbonaceous oil shale components must be in the aqueous phase to be utilized by microbes and ultimately converted to natural gas.

Referring to Figure 3, the recovery of biogenic natural gas is shown. In this case, the recovery is conducted in the same borehole that was used to deliver amendments to the target zone. Therefore, the Figure 3 is an example of a dual injection-recovery well that requires minimal adaptation to suit either need. However, it is not necessary to have both injection and recovery occur at the same borehole, and certain applications might require that an additional recovery well is utilized adjacent to the injection well. Recovery can proceed passively in certain cases but active recovery methods such as pumping are anticipated. Migration of the gas mixture 320 (CH ₄ +CO ₂ ) out of the formation occurs naturally to dissipate pressure and promote the thermodynamic viability of further microbial degradation, though it will be mixed with formation water and vapor. Migration or transport of the gas-water mixture continues upwards through the borehole to the surface and an appropriate wellhead 310. Produced gas then is directed to an above ground separation unit prior to transfer to a gas flow line for on-site storage or further transfer off-site.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. While numerous changes may be made

by those skilled in the art, such changes are encompassed within the spirit of this invention as illustrated, in part, by the appended claims.