METHODS AND SYSTEMS FOR STIMULATING BIOGENIC PRODUCTION OF NATURAL GAS IN A SUBTERRANEAN FORMATION

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 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 in the United States, Middle East, the North Sea, and other established plays. 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. This process relies on electrical heating in a network of injection holes to drive the matrix temperature above 650 ⁰ C, at which oil is naturally extracted from the shale via a combination of physical and chemical modifications of the subsurface environment. Thermal in situ conversion does not necessarily generate the same amount of waste as ex situ methods, 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.

Natural gas also forms in the pores and natural fractures of shale rock, as well as sorbed to the mineral phase and corresponding organic materials (kerogen) of the rock. This natural gas forms as the result of both biogenic and thermogenic (catagenic) processes. Thermogenic gas production occurs via the breakdown of kerogen in deeper intervals where

temperatures and pressures are high. These are mature formations and little influence can be exerted to increase gas production beyond its natural rate. However, biogenic gas generally forms at shallower depths (typically less than 3000 feet below ground surface) and results from activity at the margins of basins where temperatures and conditions are more suitable for the establishment of microbial populations.

Because the method by which thermogenic gas is formed makes it difficult to alter in an economically meaningful way, ^" developing methods to stimulate biogenic methane production is a key goal for recovering a portion of the energy content stored in shale deposits. Production of gas from a complex substrate such as the kerogen in shale requires the presence of a number of different microbial species. Carbonanceous shale contains 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.

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.

FIGURES

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 creation of a subsurface fracture network in a solid hydrocarbon deposit.

Figure 2 is a cross-sectional schematic showing represents 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, and more particularly to methods and systems for stimulating anaerobic biologic production of methane from non-liquid hydrocarbon-bearing subsurface formations.

The methods of the present disclosure generally comprise fracturing a subsurface formation comprising a non-liquid hydrocarbon; and providing conditions suitable for anaerobic biological degradation of the hydrocarbon by indigenous microorganisms.

The systems of the present disclosure generally comprise a subsurface formation comprising a hydrocarbon and at least one fracture; an injection fluid disposed within the fractures; and indigenous microorganisms disposed within the formation.

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, but the disclosure is not intended to be limited to this one type of deposit. Rather, shale may be used in certain embodiments because, among other things, (1) its abundance within the United States, and (2) the difficulty in recovering energy from this resource is 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 providing a subsurface formation comprising a non-liquid hydrocarbon and an indigenous microbial population, increasing the surface area of the formation, and providing conditions suitable for anaerobic biological degradation of the hydrocarbon by the indigenous microbial 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) and microbial population. By stimulating growth of the microbial population, natural gas production maybe 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 kerogen, 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 shale deposit, the carbonaceous kerogen 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 by-products 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 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 durin tg the utilization of more complex compounds by other populations. Therefore, the diversity of the native flora within a biologically-active 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 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 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.

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.

Fracturing Technology

The surface area of the formation may be increased by creating or enhancing one or more fractures within, which may allow for increased production and recovery of natural gas. Fracturing creates 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 shale

matrix are no longer inaccessible 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 fractured. The newly created fracture network also results in increased spatial heterogeneity within the bedrock, which promotes the formation of biofϊlms as well as other microbial niches. Thus, more species can be ecologically competitive within the same formation volume.

No specific analyses are required prior to fracturing; although typically at least a minimal geophysical characterization of the formation may be previously conducted such that the targeted area is delineated and that the fracturing process can be optimized. The techniques required for this characterization are known to persons of ordinary skill in the art. Characterization methods may include, but are not necessarily limited to: (1) Soil borings and other geotechnical testing designed to determine the depth of the 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 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 kerogen substrates into natural gas. All of these characterization steps may be conducted prior to the implementation of the technology associated with the present disclosure.

Within 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 a shale formation. This means that

while the initial pressure that results from this configuration must be overcome during the fracturing process, loss of fluids or dissipation of injection pressure should be minimal. This increases the overall efficiency of the process, and means that no modifications are necessary when applying fracturing technology to shale formation. 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. For example, typical applications of fracturing technology rely on multiple fracturing events, such that additional fracturing is conducted over time to promote more complete utilization and production within a given field.

In some embodiments, the fracture network may be created through the use of pneumatic or hydraulic fracturing. Packers or seals may be used in conjunction with fracturing, for example, to isolate the interval of interest and allow for maximum efficiency in terms minimizing the amount of injection fluid required. In other embodiments, tubing may be used in conjunction with a packer to effectively deliver injection fluids or nutrients to the subsurface.

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.

For both types of fracturing, a well may be drilled using conventional methods. These may include, but are not limited to, conventional rotary augering, rotosonic, direct push, and hollow stem auger drilling techniques. Wells may be cased through the entire depth interval to maintain their integrity over time and to increase the efficiency of the fracturing. Injection wells may be configured as needed to maintain a well-connected fracture network within the oil shale deposit. The typical lateral radius of influence for an individual fracture well ranges from about 20 to about 60 feet. Additional injection points can be placed such that the radii of influence overlap, creating a higher density fracture network. Alternatively, injection wells can be placed adjacent to each other, with each well targeting a different depths interval within the same formation. Alternatively, a single injection well can be used, with all recovery of produced natural gas occurring within the same well. The choice of configuration depends on the economic and design requirements, and the present disclosure is not restricted to any single well configuration.

Injection of fluid must occur at rates high enough to propagate fractures, which requires that the pressure at the interface between the well and formation exceeds the natural pressure of the formation. Typically, this means that injection volumes are large and occur over short time periods, such that the injection rate is the determining factor rather than the absolute pressure. Specific injection volumes may depend on a variety of factors, including the permeability and fluid pressures associated with the formation. Additionally, the thickness and depth of the targeted interval may be critical to designing the proper injection strategy. For example, a shale deposit present under a large overburden layer would require a significant increase in the injection pressure relative to a shallow deposit. Typical injection pressures may rely on about 1 psi per foot of depth (of overburden) for hydraulic fracturing, and up to about 3 psi per foot of depth for pneumatic fracturing.

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. 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.

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°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 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 -fϊxing 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., hydrogenotrophic) metlαanogens 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 produced 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.

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 hydrogenotrophic or acetoclastic methanogenesis, or both.

Injection Strategies

In addition to the fracturing fluid itself, there are a number of approaches that can be combined in an injection strategy to enhance overall biological activity. For example, one or more of the following may be injected into the formation: nutrients, surfactants, heat, and exogenous microbial cultures.

The newly-created fracture network generally should provide increased surface area in the shale formation and thus increased contact between components. Therefore, the addition of nutrients or other compounds may be more effective in a fractured formation than it would be in an area where contact would rely on the natural conduits. 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 CO ₂ (added following injection of the fracturing fluid). 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, 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. Heating the formation may be accomplished using one or more of steam, hot water

flushing, conductive heating, and electric resistive heating. 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. Electrodes for resistive heating may also utilize existing wells, though additional electrodes are likely necessary to match the lateral extent of the fracture network. 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 ⁰ 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°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°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, an electric current may be provided to enhance productivity. Low voltage electrochemical stimulation of anaerobic microbial populations can increase the hydrogen yield during biological fermentation of carbon substrates. This process results in hydrogen formation at the cathode by utilizing protons and electrons released during the degradation of a reduced carbon compound. The hydrogen then may be converted to methane within the formation by the activity of methanogens. Electrodes for resistive heating may be placed in existing wells to deliver low voltage to the formation. Separation of cathode and anode would be provided in the well borehole. The utilization of electrochemical stimulation in a formation is a site-specific decision that may be appropriate if initial productivity is insufficient.

In some embodiments, injection strategies may utilize exogenous microbial cultures to enhance biological activity in the oil shale deposit. The general term for this process is bioaugmentation, 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. Bioaugmentation 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 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 (kerogen 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 kerogen in shale, the steps directly leading to methane production, or both.

Injection strategies may be delivered to the subsurface using a variety of methods. It is anticipated that fracturing and injection strategies 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 pneumatic or hydraulic fracturing is selected, whether the injection strategy is added during the fracturing process or after the fracture event has concluded, and 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. For example, an additional injection well for the delivery of liquid nutrients may be necessary if it is determined that a portion of the newly- created fracture network has become closed off due to insufficient amounts of proppants. 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.

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 H ₂ or CO ₂ within the formation.

Gas Recovery

Even in a shale formation that has not been hydraulically or pneumatically fractured, a series of pores may exist that may allow for transport of gas throughout the formation. This natural movement of gas may be enhanced once more numerous and expansive conduits for gas transfer are created by fracturing. The present disclosure may require the creation of a wellbore to promote fracturing; and therefore, the hole may serve the additional role of a recovery well following the completion of the fracturing event. Recovery efficiency may be

increased when the entire interval is cased. The conversion of a fracture 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 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 recoveiy 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.

EXAMPLES

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

A shale interval present below a thick overburden layer may be relatively well- delineated hydrogeologically using standard geophysical characterization methods. High levels of dissolved inorganic carbon (DIC) may be measured in initial formation water analyses, which may indicate that biogenic methane production has occurred and is on-going. This includes analyses of carbon isotope ratios that suggest a link between ¹³ C _DIC and ¹³ C _CH 4

that is biogenic in origin, or shale compositional analyses that indicate that Type I shale with a desirable lack of thermal maturity is the dominant type present 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 drilled in the area and a fracture network would be initiated in the interval of interest using a pneumatic fracturing technique. Hydrogen would be used as the fracture gas to provide an initial electron donor to stimulate microbial activity and autotrophic growth. High pressure pneumatic fracturing with this gas would increase the effective permeability of the formation, but a water flood would be initiated if water seepage into the newly-fractured 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 with the fracturing fluid. 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 drilled at intervals suggested by the initial radius of influence for the first production well. The initial injection point would be converted to a recovery well, or alternatively, additional recovery wells would be drilled in the near down gradient vicinity of the initial well or series of wells. Additional water flooding 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 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 a high capacity drill rig is typically required for drilling below the significant overburden 125 that is present above most kerogen deposits. It is anticipated that

this is a stationary unit with supporting equipment (such as engines, pumps, fuel, and mixing reservoir for drilling 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 pneumatic fracturing, 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 fracturing fluid and must be injected at high pressures to initiate fracture formation. In either case, the fracturing fluid can be 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. Therefore, oxygen exposure and dissolution of solid organic carbon is limited within this deposit. Initiation of active fracturing via the addition of a fracturing fluid at the surface typically will occur once the kerogen formation is reached; fracturing of any of the overburden is inefficient and will not target the organic content bound in the shale region. Therefore, the borehole is typically screened only in the kerogen interval such that injection fluids will create a fracture network 140 within a targeted portion of the formation. This interval can be thick as desired but may not encompass the entire formation. The propagation of fractures occurs in the lateral direction relative to the borehole, and can extend for several meters provided a sufficient pressure and volume of fracturing fluid is used. As a fracturing event proceeds, a secondary fracture network in the vertical direction can be initiated to further relieve pressure while increasing permeability and contact within the formation.

Referring to Figure 2, during the fracturing process, proppants 210 are used to maintain the integrity of the artificial fracture network. These are typically solid particles with specific properties (size, composition) that provide resistance to existing subsurface geophysical forces that might lead to closure of the newly-created fractures. The proppants remain in place such that additional liquids or gases can be efficiently delivered to the formation. 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, as well as the enhanced dissolution promoted by water entering the fracture network. The solid kerogen 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 create the fracture network and deliver amendments to the target zone. Therefore, the Figure 3 is an example of a dual production-recovery well that requires minimal adaptation to suit either need. However, it is not necessary to have both production and recovery occur at the same borehole, and certain applications might require that an additional recovery well is drilled some distance downgradient of the production 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 fracture network 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.