WO2014018789A1 - Enhancing energy recovery from subterranean hydrocarbon bearing formations using hydraulic fracturing - Google Patents

Abstract

Systems and methods are described that may utilize hydraulic fracturing to deliver fluid mixtures to native microorganism consortiums. The injection of fluid mixtures may cause fractures to form throughout the formation to allow the fluid mixture to be delivered to carbonaceous material contained in the formation. The injection may also be stopped and the injected fluid may be allowed to disperse through the formation such that microorganisms native to the formation may access the injected fluid mixture. The microorganisms may be stimulated by the injected fluids to convert carbonaceous material into the biogenic gas thereby increasing the production of the biogenic gas.

Description

ENHANCING ENERGY RECOVERY FROM SUBTERRANEAN HYDROCARBON BEARING FORMATIONS USING HYDRAULIC FRACTURING

CROSS-REFERENCES TO RELATED APPLICATIONS

This Application claims priority to U.S. provisional application 61/675,469, filed July 25, 2012, entitled "ENHANCING ENERGY RECOVERY FROM

SUBTERRANEAN HYDROCARBON BEARING FORMATIONS USING HYDRAULIC FRACTURING", attorney docket number 89859-846519 (003600US), the entire disclosure of which is hereby incorporated by reference for all purposes.

TECHNICAL FIELD

The present technology relates to systems and methods for stimulating the production of biogenic gas. More specifically, the present technology relates to utilizing hydraulic fracturing to deliver fluid mixtures to carbonaceous materials to stimulate the production of biogenic gas.

BACKGROUND

As the price of oil rises, along with economic and environmental pressures to find local and alternative energy sources, the use of natural gas as a safe and reliable energy source continues to grow. Natural gas is used as an energy source for heating, electric power generation, and transportation fuel. Natural gas is also used for the production of hydrogen, and in many manufacturing processes.

The majority of natural gas is found in underground deposits, many of which are the same geologic formations that contain liquid and solid carbonaceous material such as oil fields and coal beds. Substantial amounts of natural gas production are believed to occur by biogenic processes by methanogenic communities of

microorganisms that were introduced by infiltration meteoric water after uplift of the geologic formations. These microorganisms evolved over geologic time into methanogenic communities that metabolize the carbonaceous material into substances such as natural gas as a metabolic end-product. The work of these microorganisms over thousands and millions of years has produced deposits of secondary biogenic natural gas that measure in the trillions of cubic feet.

As natural gas use increases globally, these reserves will be depleted creating new types of energy crises. Fortunately, the same biogenic processes that originally produced many of these deposits may be utilized to continue producing natural gas on a globally significant scale. Furthermore, if biogenic processes may be improved or enhanced to convert even a small fraction of the carbonaceous material in current formations to natural gas, the quantities produced could be enormous. For example, the Powder River Basin in northeastern Wyoming is estimated to contain over 1 trillion short tons of coal. If even 1% of this coal could be converted to natural gas, it could supply the current annual natural gas usage in the United States (about 23 trillion cubic feet) for four years.

In the United States alone, many previously mined coal and oil fields have become economically prohibitive for continued mining but still retain substantial quantities of residual carbonaceous materials. Accessing the reserves, however, may be cost prohibitive, or may not result in commercially significant amounts of biogenic gases.

Thus, there is a need for improved methods and systems for accessing carbonaceous materials and/or subterranean geological environments. There is also a need for improved ways of producing biogenic gases in these environments. These and other needs are addressed by the present technology.

BRIEF DESCRIPTION

Systems and methods are described that may utilize hydraulic fracturing to deliver fluid mixtures to native microorganism consortiums. The injection of fluid mixtures may cause fractures to form throughout the formation to allow the fluid mixture to be delivered to carbonaceous material contained in the formation. The injection may also be stopped and the injected fluid may be allowed to disperse through the formation such that microorganisms native to the formation may access the injected fluid mixture. The microorganisms may be stimulated by the injected fluids to convert carbonaceous material into the biogenic gas thereby increasing the production of the biogenic gas. The technology may further include methods of stimulating the production of biogenic gas. The methods may include forming an access in a subterranean geologic formation containing a carbonaceous material. The formation environment may be analyzed to determine the presence of a microorganism consortium. The method may include injecting a fluid mixture into the formation, where the injection causes fractures to form through the formation to allow the fluid mixture to be delivered to the carbonaceous material. The fluid mixture injection may be stopped, and access to the formation may be sealed. The method may also include monitoring the formation environment after the access has been sealed. The method may additionally include increasing the production of the biogenic gas from

microorganisms stimulated by the injected fluid mixture to convert a portion of the carbonaceous material into the biogenic gas.

Additional embodiments and features are set forth in part in the ensuing detailed description and accompanying drawings, and in part will become apparent to those skilled in the art upon examination of the specification, or may be learned by the practice of the technology. The features and advantages of the technology may be realized and attained by means of the instrumentalities, combinations, and methods described in the specification.

BRIEF DESCRIPTION OF THE DRAWINGS

A further understanding of the nature and advantages of the disclosed technology may be realized by reference to the remaining portions of the specification and the drawings.

FIG. 1 is a flowchart describing a method of enhancing energy recovery according to embodiments of the present technology.

FIGS. 2A-2B show a flowchart describing another method of enhancing energy recovery according to embodiments of the present technology.

FIG. 3 illustrates still another method of enhancing energy recovery according to embodiments of the present technology.

FIG. 4 shows an exemplary system for enhancing energy recovery according to embodiments of the present technology. FIG. 5 illustrates another exemplary system for enhancing energy recovery according to embodiments of the present technology.

In the appended figures, similar components and/or features may have the same numerical reference label. Further, various components of the same type may be distinguished by following the reference label by a letter that distinguishes among the similar components and/or features. If only the first numerical reference label is used in the specification, the description is applicable to any one of the similar components and/or features having the same first numerical reference label irrespective of the letter suffix.

DETAILED DESCRIPTION

Methods and systems are described for stimulating production of biogenic gases in geologic formations using fluid mixtures that may be delivered via hydraulic fracturing. The process may allow activation agents, stimulants, and/or nutrients included in the fluid mixtures to be dispersed over a larger portion of carbonaceous material located in the formation, and/or may allow access to previously inaccessable regions of the formation environment. This may allow the agents and nutrients to be accessible to a larger number of microorganisms in the carbonaceous material, while providing new access paths for the fluid mixtures as well as the produced biogenic gas.

The stimulation effects of the fluid mixtures may include increasing the rate of production of the biogenic gas and/or an intermediary in a metabolic process that is essential to the creation of the gas. The effects may also include activating a key member of the consortium of microorganisms, e.g., Thermotoga sp., T. phaem, Geobacter sp., Methanosaeta, etc., in the formation to start and/or enhance the rates and/or yield of biogenic gas creation. They may further include stopping or decreasing a "rollover" effect such as when the concentration of one or more metabolic products starts to plateau (or even drop) after a period of monotonically increasing.

Turning now to FIG. 1, a flowchart illustrating a method 100 is shown of enhancing energy recovery according to embodiments of the present technology. The method may include stimulating the production of a biogenic gas produced in a subterranean geologic formation that contains carbonaceous material. The method 100 may include the step 110 of injecting a fluid mixture into a subterranean geologic formation that contains the carbonaceous material. The injection of the fluid mixture may be performed so as to cause fractures to form through the formation that allows the fluid mixture to be delivered to the carbonaceous material within the formation environment. The injection of the fluid mixture may be stopped at step 115 after a certain amount of time, after a certain amount of fluid has been injected, after the formation strata has been affected in a particular way, etc. During the injection and/or subsequent to the stopping of the injection of the fluid mixture, the injected fluid mixture may be allowed to disperse through and/or be imbibed by the formation environment at step 120. The dispersion or imbibement of the fluid mixture may allow microorganisms native to the formation environment to access the injected fluid mixture, or compounds contained within the fluid mixture. The production of biogenic gas may be increased at step 125. Microorganisms within the formation environment may be stimulated by the injected fluid mixture or compounds within the injected fluid mixture, and the stimulation may cause them to convert a portion of the carbonaceous material into the biogenic gas.

The geologic formation may be a previously explored, carbonaceous material-containing subterranean formation, such as a coal mine, oil field, natural gas deposit, carbonaceous shale deposit, etc. The carbonaceous material may include coal, oil, carbonaceous shale, oil shale, tar sands, tar, lignite, or peat, and the associated kerogen and bitumen, among other naturally occurring carbonaceous materials.

The geologic formation environment may be anaerobic, and thus, the production, transportation, and injection of the fluid mixtures may occur under anaerobic conditions. For example, the fluid mixtures themselves may be developed anaerobically utilizing water from the formation environment that may have anaerobic characteristics. Alternatively, compounds encapsulated or mixed in the fluid to be injected may be contained in an anaerobic aqueous fluid developed externally to the formation environment. Anaerobic fluid is characterized as having little or no dissolved oxygen, in general no more than 4 mg/L, preferably less than 2 mg/L, and most preferably less than 0.1 mg/L, as measured at 20°C and 760 mmHg barometric pressure.

In FIG. 2A, another method of enhancing energy recovery 200 is shown. Beginning with A, the method may include step 206 of accessing the geologic formation. Initial access to the formation environment may occur through a well, bore-hole, or other natural or man-made access. In one example, a location in which previous hydraulic fracturing has been performed may be used. In many instances, access to the formation may involve utilizing previously mined or drilled access points to the formation. For unexplored formations, accessing the formation may involve digging or drilling through a surface layer to access the underlying site. The geologic formations may include native carbonaceous materials that were formed in the formation through natural processes instead of being supplied to the formation through a human-directed process (e.g., dumping or pumping the carbonaceous material into the formation). The access may be formed substantially vertically, horizontally, or some combination of the two. The access may be include sheathing, piping, or other components that may be configured to direct the fluid injection. For example, piping or other protection or structure may be inserted in the access that include gaps or perforations through which the injected fluid mixture may act.

The access may be formed to reach the carbonaceous material or other specific regions of the formation environment that may include formation fluid or reservoirs. Through this access, prior to the injection of fluid mixtures, a

determination may be made that microorganisms are present in the formation. At step 208, the method may include characterizing microorganisms in the formation or carbonaceous material. The characterization may occur in situ, or by removing formation or formation fluid samples that are analyzed. The removed samples may be maintained in anaerobic conditions to preserve the native environment of the microorganisms. These microorganisms may include methanogenic microorganisms that convert adjacent carbonaceous material into hydrogen (H₂), methane (CH₄), and/or other metabolic products that have hydrogen-to-carbon ratios higher than the starting carbonaceous material. The microorganisms may also include species of methanogenesis inhibitors that slow or inhibit methanogenic metabolic processes by consuming methanogenic precursors and/or producing compounds that inhibit methanogenesis.

The characterization step 208 may include a biological analysis of the microorganisms. This may include a quantitative analysis of the population size determined by direct cell counting techniques, including the use of microscopy, DNA quantification, phospholipid fatty acid analysis, quantitative PCR, protein analysis, etc. The phylogentic characterization of the microorganism consortium may be performed by metagenomic analysis using 16rDNA Amplicon pyrosequencing.

Genetic analysis may also be conducted by an analysis of the DNA of the

microorganisms where the DNA is optionally cloned into a vector and suitable host cell to amplify the amount of DNA to facilitate detection. In some embodiments, the detecting is of all or part of ribosomal DNA (rDNA), of one or more microorganisms. Alternatively, all or part of another DNA sequence unique to a microorganism may be detected. Detection may be by use of any appropriate means known to the skilled person. Non- limiting examples include restriction fragment length polymorphism

(RFLP) or terminal restriction fragment length polymorphism (TRFLP); polymerase chain reaction (PCR); DNA-DNA hybridization, such as with a probe, Southern Analysis, or the use of an array, microchip, bead based array, or the like; denaturing gradient gel electrophoresis (DGGE); or DNA sequencing, including sequencing of cDNA prepared from RNA as non- limiting examples. Additional details of the biological analysis of the microorganisms is described in co-assigned U.S. Pat. App. Ser. No. 11/099,879, filed April 5, 2005, the entire contents of which is herein incorporated by reference for all purposes. By determining characteristics of the microorganisms, activation agents and nutrients may be provided that target particular microorganisms or metabolic pathways in order to stimulate or favor metabolism of the carbonaceous material to make particular metabolic products or biogenic gases.

Once the access has been provided, and a characterization may have been performed, a fluid mixture may be injected into and through the access at step 210, after B. The fluid mixture may be injected at a pressure adequate to exceed the rock strength, thereby fracturing the formation strata. The fluid may be injected via pumping or high-pressure pumping that is operated at pressures exceeding the strength of the formation strata. The injected fluid mixture may include a variety of different components that will be described in greater detail below. Monitoring may be performed during the injection in order to regulate underground pressures, fluid mixture composition, environmental characteristics, etc. After an amount of fluid mixture has been injected, or certain injection results have occurred that may include an underground pressure, the injection may be stopped at step 215. The access may be plugged or sealed at step 218 after the injection is stopped to maintain pressure underground to continue to force the injected fluid through fissures that may have formed, as well as to allow a buildup of biogenic gas.

After the access is sealed, the fluid may be allowed to disperse through and be imbibed by the formation at step 220. Based on the original access and

characterization, a determination can be made about the extent of dispersion required or desired. Accordingly, the internal well pressure may be regulated to tailor the degree and rate to which the fluid is dispersed through the formation. Additionally, the formation environment may be monitored at step 222. Various monitoring can be performed, and in alternative embodiments may include monitoring one or more environmental characteristics in situ, monitoring the microorganism consortium makeup, monitoring the rate of biogenic gas production, etc. For example, the pressure within the formation environment may be monitored to determine the projected extent of fluid dispersion, and additionally may be performed to determine the amount of biogenic gas being produced. This may occur over a period of time.

For example, the pressure within the formation may initially reduce from the level when the access is sealed. As the microorganism consortium is stimulated and biogenic gas is produced, the pressure within the well may increase as more gas is produced. Finally, at step 225, the production of biogenic gas may be increased from the microorganisms in the formation environment that have accessed the injected fluids. The increase may relate to various factors related to the production of biogenic gas. For example, the rate at which biogenic gas is created may be increased as compared to the rate prior to the fluid mixture injection. Alternatively, a change in the makeup of the produced biogenic gas may be caused. For example, certain compounds included in the fluid mixture may cause a shift within the microorganism consortium that allows the proliferation of certain microorganisms whose metabolic pathways favor the production of methane, acetate, or other particular products that may affect the end composition of the biogenic gas.

FIG. 2B shows an alternative process between segments A and B of the method 200. As illustrated, subsequent to the characterization of the microbial community, an amendment mixture may be formulated at step 209. The optimization may be based on information gathered from the analysis performed at step 208. For example, the information may show that a particular microorganism useful to methanogenesis is not gathering nutrients or certain nutrients may not be readily available to that organism. In response, an amendment package may be formulated to provide nutrients to help the particular microorganism flourish amongst the consortium members. Many other examples of environmental changes, nutrient inclusions, or inhibitors may be used to affect the microbial community in one or more ways. Many of the possible amendment components are described in more detail below. Once an optimized amendment package has been formulated, the amendment may be encapsulated, mixed, or otherwise incorporated with the fluid mixture for injection into the formation environment. Alternatively, the optimization may be performed subsequent to an initial fluid injection. Sampling and

characterization may be performed after an initial fracturing operation, and an optimized amendment mixture may be produced based on information provided from this characterization for subsequent injection.

The fluid mixture utilized may include any number of components useful in both the stimulation of microorganisms as well as the delivery though the formation environment. The fluid mixtures may include an aqueous or non-aqueous medium that contains one or more solid, liquid, or gaseous components. These components may be divided into a number of categories including delivery means and stimulation means, and the fluid mixture utilized may be tailored to include any combination of components that can be manipulated prior to or during the injection process. In some processes, multiple injections may be performed that may each include similar or different components. For example, a first injection may be performed with organic or inorganic acids followed by the general fluid mixture injection. The fluid mixture may be anaerobic or substantially anaerobic and thus the delivery means and components used may include materials with limited additional oxygen content. The delivery means may include the aqueous or non-aqueous medium with which all other components are combined. For example, water may be used as the medium, and may include water extracted from the formation environment initially, or alternatively or additionally include water imported from other sources that can include groundwater, well water, or any other water deliverable to the production site.

Alternatively, the injected fluid may be based on oil, methanol, or some combination of these components with or without water. Components may be included in the mixture for aiding or causing the fracturing to occur within the formation.

Proppants may be used to help maintain formed fractures. The proppants may be selected based on various characteristics including permittivity, interstitial spacing characteristics, and mechanical strength. Depending on the formation environment, large or small mesh proppants may be selected. For example, if the environment demonstrates low closure stresses, larger mesh proppants may be used to produce greater permittivity or permeability. As the closure stresses increase, larger mesh proppants may fail mechanically, and thus smaller mesh proppants may be used.

Particular proppants that may be utilized can include sand, resin coated materials, ceramics, glass, ores including bauxite, as well as proprietary compositions of various densities, mesh sizes, etc. The proppant composition may be selected based on the particulate or fines production, and the selection may be made based on the strength required for particular operations. For example, resin coated sand may be used, or in other examples proprietary ceramic proppants may be used to reduce the fines production. The proppants may additionally include activated particles, which can include support structures that house microorganisms. For example, bacteria, fungus, or other inoculum can be incorporated into spheres, pellets, or other organic or inorganic structures for delivery with the fluid mixture. The support structure may operate as the proppant, while also providing the path by which micobes can access carbonaceous material. This inoculated support structure may also be combined with one or more additional proppants to provide a delivery means for the microorganisms while also providing other desired proppant characteristics. The delivery means may also include viscosity agents to produce fluids having particular viscosities depending on the characteristics of the formation environment, the proppant used, the desired fracture width, etc. Gelling agents can be included from 0 to as much as 20% or more by volume of the composition. Linear or cross-linked gels may be included, and the amount of gel used may be determined based on the desired amount of proppant to be transported, with the higher viscosity being able to transport a greater amount or proppant. Linear gels may be water-based, and the gelling agent may include polymers or other components. Guar may be utilized for gelling as well as guar derivatives that may include hydroxypropylguar, carboxymethylguar,

carboxymethylhydroxypropylguar, hydroxyethylcellulose, or other biodegradable or non-biodegradable agents. Diesel fuel may additionally be included as a carrier for gelling agents including guar-based gelling agents. Cross-linked gels may be used in addition to or in lieu of linear gels, but may require the use of a breaking agent to reduce the polymer. The cross-linked gels may include metal ions including aluminum, chromium, aluminum, boron, etc. to cross-link guar or other products. Additional components in the cross-linked gels may include acids, glycols, amines and a variety of other components.

Gaseous components may also be utilized including air, nitrogen, carbon dioxide, etc. to foam the fluid mixture. Foams may allow a reduced volume of fluid to transport an amount of proppant. The foaming agent may be included with gelling agents, and may include additional components including amines and alcohols. Acids may also be used to varying degrees to break down or help weaken the structural integrity of the formation composite. Acids may include hydrochloric acid, acetic acid, formic acid, etc. The acids may be diluted in the mixture, pumped prior to the fluid mixture injection, and/or utilized with gelling agents as the breaker fluids.

Breaker fluids may also include oxidizers, microorganisms such as bacteria or filamentous fungi or yeast, and/or enzymes. With the addition of acids, corrosion inhibitors such as acetone may be additionally included.

Other additives may also be added that can include fluid-loss additives and friction reduction additives. These additives may include sands, resin, flours, starches, talc, clay, latex polymers, acrylamides, etc. The amount of all of the delivery means components may be based on the formation structure, geochemistry, depth of treatment, amount of formation impact, as well as many other variables. As the injection is performed, the fluid mixture composition may be adjusted according to changing conditions. For example, the amount of proppant may be increased or decreased as the injection is performed. Any number of other adjustments to components may be performed, as well as adjustments to the rate and pressure at which the injection is performed. Still other components may include tracers that may allow the progress of the fluid injection to be monitored. For example, transmitters, radioactive particles, magnetic particles, etc. may be used that can be monitored during and/or after the injection to ensure adequate propagation through the formation environment. These materials may additionally allow the injection process to be adjusted during the injection to ensure the desired structural effects occur. In some embodiments, the materials utilized in the methods are chosen so as to limit the effect they may have on microorganisms native to or introduced to the formation environment. Furthermore, exemplary fluid mixtures may not inhibit, neutralize, or destroy native microorganisms to any substantial degree. Additionally, in some embodiments, the fluid mixture may not inhibit neutralize, or destroy microorganisms included in the fluid mixture for introduction into the formation environment.

The stimulation means may include components that operate in conjunction with the delivery means, or are specifically included to be utilized by a microbial consortium that may be native to or introduced to the formation environment.

Compounds used in the methods described may act as nutrients, activation agents, initiators, or catalysts for increasing the production of biogenic gases including hydrogen and methane. As nutrients, the microorganisms may consume the compounds allowing the microorganism populations to grow more rapidly than without the compounds. As activation agents, the compounds may lower an activation barrier, open a metabolic pathway, modify a carbonaceous material, change the reaction environment, and may or may not be rapidly consumed as a nutrient.

When the compound is acting primarily like a nutrient, consumption of the nutrient by the microorganisms may increase the production of biogenic gas by a stoichiometrically proportional amount to that of the compound used. Alternatively, when a compound is acting primarily as an activation agent, the increased amount of biogenic gas may be much larger than the amount of the compound added. Thus, in such a scenario, introducing small quantities of the compound may produce more than stoichiometric quantities of the biogenic gases. When the compound acts as an activation agent, the compound may or may not act as a catalyst, and may be fully, partially, or not consumed while increasing the production of biogenic gas. The activation compound may also be a compound that is a transient byproduct of the microorganism community that may appear at low levels, e.g., about 0.5 to about 2 μΜ. The compounds may stimulate the microorganisms to metabolize carbonaceous material in the formation into biogenic gas, such as methane, or into intermediate metabolites that may further be metabolized into biogenic gases.

The stimulation means may be incorporated to the fluid mixture in a variety of ways designed to maintain the compounds during the injection process so that they may be delivered to the microorganisms at the carbonaceous material. The stimulation means may be mixtures themselves, and may be non-homogeneous or homogeneous, and may include multiple phases, including solid and liquid phases, or two or more liquid phases. Exemplary mixtures having two or more liquid phases may include emulsions that have one or more dispersed phases surrounded by a continuous phase. The lack of miscibility that causes the separate liquid phases may be due to different polarities of the liquids. For example, a dispersed liquid phase may be non-polar while the continuous phase is polar. Conversely the dispersed phase may have a polar liquid while the continuous phase is made from a non-polar liquid. Exemplary emulsions may include oil-in-water (O/W) emulsions that have a non-polar dispersed phase incorporated into a continuous phase that include polar water molecules. They may also include water-in-oil (W/O) emulsions where droplets of polar water or an aqueous solution are dispersed in a non-polar hydrocarbon-containing continuous phase. The emulsions may be classified as microemulsions and/or nanoemulsions if the size of the dispersed-phase droplets are the requisite size, e.g., less than about 100 nm, for example. The emulsion may be a single emulsion containing two-phases, such as O/W, or in some embodiments may alternatively be a multiple emulsion including an emulsion contained in a separate continuous phase, such as W/O/W for example. The mixture may further contain surfactants and/or emulisifiers that slow or prevent the dispersed phases from coagulating and/or forming a separate layer of the mixture. Activation agents, nutrients, and or other stimulation compounds may be dissolved in the one or more of the dispersed phases, the continuous phase, or both. For example, the agents/nutrients may be soluble in a polar solvent such as water (i.e., an aqueous phase), or a non-polar solvent such as found in an "oil" phase. Depending on whether the emulsion is (1) oil-in- water or (2) water-in-oil, the agents/nutrients that are soluble in the aqueous phase may be found in the continuous phase of (1), and dispersed phase of (2), respectively, for example. Agents and nutrients that are at least partially soluble in both polar and non-polar solvents may be found in both the dispersed and continuous phases of the emulsions. Examples may further include agents and nutrients that are partially dissolved in one or more of the liquid phases of the emulsion, and that also have a solid phase component suspended and/or precipitated from the liquid phases.

In exemplary emulsions that include polar aqueous phases and a non-polar (e.g., "oil") phase, a non-polar oil phase may include compounds having at least a non-polar, hydrophobic/lipophilic moiety such as a long chain hydrocarbon.

Examples of these non-polar compounds may include mineral oils, essential oils, and organic oils, among other types of oils. They may further include lipids and fatty acids that include non-polar, hydrophobic hydrocarbon tails. Exemplary fatty acids may include naturally occurring, saturated and/or unsaturated fatty acids such as myristoleic acid, palmitoleic acid, sapienic acid, oleic acid, linoleic acid, a-linolenic acid, arachidonic acid, eicosapentaenoic acid, erucic acid, docosahexaenoic acid, etc., among other fatty acids having one or more double-bonds between carbon atoms in the hydrocarbon chains, and including configurations with hydrogen atoms being located on the same or opposite sides of the double bond, such as with cis- or trans- configurations of the acids. Exemplary saturated fatty acids may include lauric acid, myristic acid, palmitic acid, stearic acid, arachidic acid, behenic acid, lignoceric acid, cerotic acid, etc., among other fatty acids that have no double bonds and are saturated with hydrogen atoms. Some of the possible combinations of acids that may be used in the non-polar phase may be from naturally occurring fats and oils, and may include animal fats including lard, duck fat, butter, as well as vegetable fats including coconut oil, palm oil, cottonseed oil, wheat germ oil, soya or soybean oil, olive oil, corn oil, sunflower oil, safflower oil, hemp oil, canola oil, among others. Other possible combinations may include engineered formulations that have been shown to remain dispersed in oil-in- water emulsions for particular periods of time without creaming or separation of the dispersed non-polar phase.

Polar phase compounds may include water, or aqueous solutions

incorporating salts, sugars, protein hydrolyzates, various cell extracts such as yeast extract, algal extracts, or other compounds including volatile fatty acids, or acids such as acetic acid, propionate, butyrate, oxyphosphorous acids, aromatic compounds such as benzoate, salicylate, syringate, vanillin, cinnamate, etc. Additional exemplary polar phase compounds may include formamide, and dimethyl sulfoxide, among others. The included algal extracts may include Chlamydomonaas spp., or Spirulina spp., for example. A broader discussion of emulsion formulation and composition may be found in co-assigned U.S. Prov. Pat. App. Ser. No. 61/613,380 to Mahaffey et al, filed March 20, 2012, and entitled "DISPERSION OF COMPOUNDS FOR THE STIMULATION OF BIOGENIC GAS GENERATION IN DEPOSITS OF CARBONACEOUS MATERIAL," the entire contents of which are hereby incorporated by reference for all purposes.

Whether incorporated into an emulsion or not, the injected fluid mixture may include a variety of other components that may be used by microorganisms within the formation environment to stimulate production of the biogenic gas. When contained in an emulsion or otherwise encapsulated, the stimulation components may be protected from some of the delivery components that may affect the stimulation components. Regardless of whether the components are encapsulated or free-flowing in the fluid mixtures, these compounds may be characterized as amendments, agents, or additional compounds or components. Additionally, compounds may be incorporated in order to adjust or manipulate the formation environment itself. The compounds for incorporation may include one or more of acetate compounds, yeast extracts, algal extracts, phosphorus compounds, vitamins, metals, trace minerals, enzymes, acids, or other organic or inorganic compounds.

Exemplary phosphorus compounds that may be utilized as amendments in the fluid mixtures may include phosphorus compounds (e.g., PO_x compounds were x is 2, 3 or 4), such as sodium phosphate (Na₃P0₄) and potassium phosphate (K₃P0₄), as well as monobasic and dibasic derivatives of these salts (e.g., KH₂P0₄, K₂HP0₄, NaH₂P0₄, Na₂HP0₄, etc.). They may also include phosphorus oxyacids and/or salts of phosphorus oxyacids. For example, the phosphorus compounds may include H₃PO₄, H₃PO₃, and H₃P0₂ phosphorus oxyacids, as well as dibasic sodium phosphate and dibasic potassium phosphate salts. The phosphorus compounds may also include alkyl phosphate compounds (e.g., a trialkyl phosphate such as triethyl phosphate), and tripoly phosphates. The phosphorus compounds may further include condensed forms of phosphoric acid, including tripolyphosphoric acid, and pyrophosphoric acid, among others. They may also include the salts of condensed phosphoric acids, including alkali metal salts of tripolyphosphate (e.g., potassium or sodium tripolyphosphate), among other salts, and may also include oxides of phosphorus (e.g., phosphorus trioxide, pentoxide, etc.), among other compounds.

Examples of acetate compounds that may be used in the fluid mixtures may include acetic acid, and/or an acetic acid salt, e.g., an alkali metal salt of acetic acid, an alkali earth metal salt of acetic acid, sodium acetate, potassium acetate, etc., among other acetate compounds. Carboxylate compounds may also be used that may be an organic compound having one or more carboxylate groups, e.g., COO^" groups. These compounds may include organic acids or their salts. Examples include salts of acetate, benzoate, and formate, among other carboxylate groups.

Other agents or amendments that may be provided include nutrients such as yeasts and yeast extracts, and may include digests and extracts of commercially available brewers and bakers yeasts. Additionally, the yeast extract may include a protein hydrolysate, blood meal, fish meal, meat and bone meal, beef peptone, or products of barley, beet, corn, cottonseed, potato, wheat, oat, soybean, and mixtures thereof. Still other compounds that may be included in the fluid mixture include cyclic and aromatic compounds that may include either or both of an ether linked group and an ester linked group, and may include vanillin and syringic acid, among other compounds and acids with a phenol group or other aryl group, and functional groups that may include, in some embodiments, hydroxyl groups, carboxylates, aldehydes, ethers, esters, etc., among others. Amendments included in the fluid mixture may additionally include metals, minerals, and vitamins. The metals for incorporation may be compounds, salts, acids, oxides, etc., that are configured to provide one or more metal ions to the formation environment. Ions that may be provided may include any alkaline, alkaline earth, transition metal, poor metal, or metalloid, and may include, for example, Mn, Mo, Co, Cr, V, Ni, Cd, Sn, Pb, Li, Na, Fe, Zn, etc. Compounds that may donate one or more of the metals may include, for example, Nitrilotriacetic acid, KOH, MnSo₄ H₂0, Fe(NH₄)2(S0₄)2-6H₂0, CoCl₂-6H₂0, ZnS0₄-7H₂0, CuCl₂-2H₂0, NiCl₂-6H₂0,

Na₂Mo0₄-2H₂0, Na₂Se0₄, Na₂W0₄, etc.

Minerals or trace elements that may be added include compounds that may provide one or more metal or mineral that may be useful for either microbial utilization or to adjust the formation environment. The elements may include one or more of the metals previously described, and may additionally include compounds that provide elements including Fe, Zn, Cu, Se, Si, As, B, F, P, K, N, Mg, Ca, CI, Na, etc., or any other element. Compounds that may provide one or more of the elements may include acids, salts, or oxides, and may include NaCl, NH C1, KC1, KH₂P0₄, MgCl₂-6H₂0, CaCl₂-2H₂0, etc. Vitamin amendments may include one or more supplements that provide additional nutrients to the formation environment. Many vitamins may be useful to a microbial consortium, and exemplary vitamin components for incorporation may include pyridoxine-HCl, Thiamine -HC1, Riboflavin, Calcium pantothenate, Thioctic acid, p-Aminobenzoic acid, Nicotinic acid, Bi₂, MESA, Biotin, Folic acid, etc. The vitamins may be incorporated with any of the previously described components, and may be encapsulated or contained within oils or other materials that will protect the vitamin for delivery into the formation environment so that the vitamin may be utilized by microorganisms.

Still other components that may be delivered to the formation environment include microorganisms. Microorganisms suitable for the described methods include microorganisms native to the formation environment as well as microorganisms not native to the formation. The microorganisms may be from the same geologic formation to which they will be injected, and are being reinjected in order to be dispersed to alternative portions of the geologic formation, or to a broader area of the geologic formation. Alternatively, the microorganisms may be from a different geologic formation and are being transported to the geologic formation containing the carbonaceous material sought to be converted into biogenic gas. In these or other cases, the microorganisms may have been modified, for example genetically, prior to their being injected or reinjected into the geologic formation. In order to maintain an anaerobic environment for the microorganisms, equipment and vehicles that are oxygen impermeable may be used, otherwise the microorganisms may be damaged in the process.

In some instances, microorganisms may be provided in the fluid mixtures directly, and/or in separate solutions introduced to the geologic formation.

Additionally, the microorganisms may be incorporated into a proppant as previously described. The microorganisms may be provided to areas of the geologic formation (such as the carbonaceous material) that show little or no biological activity. They may also be provided to increase the microorganism population in areas where microorganisms are already present (e.g., where there is already a native

microorganism population.) The added microorganisms may be selected to work in concert with the agent/nutrient mixture supplied to the formation. Alternatively, the microorganisms may be encapsulated within emulsions, oils, proteins, or other components to protect them from potentially damaging components of the fluid mixture. For example, certain of the delivery components may be deleterious to the survival of the microorganisms, but these components may not be delivered fully throughout the environment. Accordingly, by protecting the microorganisms at the point of delivery, the microorganisms may survive until they are delivered deeper into the formation environment where they may access and convert the carbonaceous material.

FIG. 3 provides still another method 300 of enhancing energy recovery from a subterranean geologic formation. The method may include forming an access at step 306 into the formation environment containing a carbonaceous material. The access may be a previous access to the formation that is being re-opened for use with the method, or may be newly formed.

After access to the formation has been provided, the method may also include analyzing the formation environment at step 308. The analysis may include environmental analysis of the formation or formation fluid, as well as analysis of microorganisms within the formation. For example, extracted formation samples may be analyzed using spectrophotometry, NMR, HPLC, gas chromatography, mass spectrometry, voltammetry, and other chemical instrumentation. Tests may also be performed in situ. The tests may be used to determine the presence and relative concentrations of elements like dissolved carbon, phosphorous, nitrogen, sulfur, magnesium, manganese, iron, calcium, zinc, tungsten, cobalt, and molybdenum, among other elements. The analysis may also be used to measure quantities of polyatomic ions such as P0₂ ^3~, PO₃ ^3", and P0₄ ^3~, NH₄ ⁺, N0₂ ^", NO₃ ^", and S0₄ ^2", among other ions. The quantities of vitamins, and other nutrients may also be determined. An analysis of the pH, salinity, oxidation potential (Eh), and other chemical characteristics of the formation environment may also be performed. Additional details of chemical analyses that may be performed are described in co-assigned PCT

Application No. PCT/US2005/015259, filed May 3, 2005; and U.S. Pat. No.

7,426,960, filed January 30, 2006, of which the entire contents of both applications are hereby incorporated by reference for all purposes.

These tests may be used to determine components for use within the fluid mixture for injection in order to adjust the environment, or to ensure that the injected fluid does not affect the underground environment substantially. For example, the amount of fluid mixture injected into the formation environment may be in the thousands, tens of thousands, or hundreds of thousands of gallons or more. This amount of fluid may dramatically affect the native formation environment.

Microorganisms within the environment may be susceptible to damage based on fluctuations within the environment, or from the removal or dilution of nutrients or other materials within the environment. Accordingly, the fluid mixture may be developed or tailored to mimic or substantially mimic the characteristics of the formation environment or formation fluid from the environment. Additionally, the testing information may be used to determine ways in which the formation environment may be adjusted to favor one or more metabolic pathways or microorganisms within the environment. For example, the process performed may be based on a desired metabolic process useful in the production of biogenic gas.

Testing performed within or from the formation environment may determine that the environment is too acidic, too basic, the salinity is too high, the environment is deficient in one or more nutrients, etc. Due to potentially numerous environmental characteristics, it may be determined that microorganisms that perform the desired processes are not able to thrive. The components of the fluid mixture may therefore be adjusted accordingly to regulate one or more environmental characteristics to produce an environment more favorable to the microorganisms that perform the conversion processes required. Subsequent to the analysis performed, a fluid mixture may be injected into the formation environment at step 310. The fluid mixture may be developed based on information provided from the analysis, or may be pre-determined prior to the analysis. The injection may be performed as has been previously described, and may be performed to cause fractures to form through the formation to allow the fluid mixture to be delivered to and/or through carbonaceous material contained in the formation environment. The fluid mixture injection may be stopped at step 315 after certain outcomes have occurred. The injection may be stopped, for example, after a certain amount of fluid has been injected, or after a desired effect has occurred within the formation. Access to the environment may be sealed at step 318 after the injection has been stopped.

The environment may be monitored subsequent to the injection at step 322. The formation may be monitored for environmental characteristics, microbial characteristics, or to determine the amount or rate of biogenic gas produced based on the fluid injection. For example, if components of the fluid mixture injected were included to adjust one or more environmental characteristics of the formation environment, the monitoring may be performed to ensure the formation has been so adjusted. The monitoring may be performed in situ, or alternatively samples may be extracted from the formation through the sealed access to run testing on the samples or microorganisms contained in the samples. The monitoring may also include characterization of microorganisms to determine the makeup within the consortium for example. The samples may include both formation structure or formation fluid.

The method may further include increasing the production of biogenic gas at step 325, and may still further include the removal of the produced biogenic gas. The increase may be determined as compared to a production rate prior to the fluid mixture injection. Additional injections may be performed to maintain the rate of production, to further adjust the formation environment, to cause further fracturing within the environment, etc. FIG. 4 shows selected components of a system 400 for supplying a fluid mixture to a formation environment according to embodiments of the present technology. Fluid mixture 440 may be produced at geologic formation 410. The fluid mixture 440 may be transported to the geologic formation or created at the site itself. The fluid mixture may be injected into the geologic formation via pipes or wells 420 either previously located in or formed and emplaced at an access point in the geologic formation. Pumping mechanism 435 may also be utilized to inject the fluid mixture into the formation and/or to disperse the fluid mixture over a greater area of the geologic formation. Additionally, pumping mechanisms may transport make up water to the well head that may gravity feed into the well 420. A separate pumping mechanism may supply a steady stream rate of fluid mixture to the gravity feed water stream going into the well/pipes. The piping or access materials may include gaps or perforations 430 through which the fluid mixture may be delivered to cause fractures to form in the geologic formation. The fractures may release contained biogenic gas, and may additionally provide paths through which the fluid mixture may be delivered to and/or across carbonaceous material for use by microorganisms within the formation. The injected fluid mixture may stimulate these microorganisms to convert a portion of the carbonaceous material into biogenic gas or intermediate metabolites that may be further converted into biogenic gas. After injection of the fluid mixture, the well access may be sealed to allow a buildup of the biogenic gas.

FIG. 5 shows an alternative system 500 that may be used for enhancing energy production from biogenic gas. Fluid mixture 540 may be prepared at the site of injection, or may alternatively be delivered to the formation environment 510, which may be a subterranean geologic formation. The formation environment 510 may include an access 520 that has been previously utilized as a well or as the location for previous fracturing operations. Piping or well access 520 may be already in place, but additional materials may be emplaced for use in the process. The system may include transferring fluid mixture 540 into a vehicle 525 to be delivered to one or more locations at the geologic formation, or the vehicle 525 may deliver a previously formed fluid mixture. The vehicle may be configured to mix or pump various components of the fluid mixture prior to injection, and may include the pumping means 535 for use in the injection. When the fluid mixture 540 is maintained under anaerobic conditions, oxygen impermeable pipes 530 and vehicle components 525 may be utilized to prevent the introduction of oxygen to the fluid mixture.

Either from pumping means incorporated into the vehicle 525 or through additional pumping means 535, the fluid mixture may be injected into the formation environment 510. Perforations or gaps within the piping or access materials 520 may allow the fluid mixture to cause fractures 545 within the formation environment that allow the fluid mixture to be delivered to carbonaceous material located in the subterranean geologic formation for use by microorganisms. The microorganisms may be stimulated to convert a portion of the carbonaceous material into biogenic gas.

The injection may be stopped and access 515 to the formation may be sealed to allow buildup of the biogenic gas.

The fractures may be formed in various directions based on the access materials used and emplaced, and the injection may at least partially be performed horizontally through the formation environment. The injection may also be performed based on previous fractures formed in the formation. For examples, previous fractures may have a directionality from which the new fractures may be based. The new fractures may expand on previous fractures, or may create new fractures entirely. The fluid mixture may be injected such that the newly formed fractures are formed in a direction substantially parallel to the previous fractures.

Alternatively or additionally, the newly formed fractures may be formed in a direction that is substantially orthogonal to the previous fractures. New fractures may similarly be formed in any other direction based on or from previous fractures formed in the geologic formation. It will be understood by one of ordinary skill in the art that the embodiments may be practiced without these specific details. For example, machinery, systems, networks, processes, and other elements in the technology may be shown as components in block diagram form in order not to obscure the embodiments in unnecessary detail. In other instances, well-known processes, structures, and techniques may be shown without unnecessary detail in order to avoid obscuring the embodiments. Also, it is noted that individual embodiments may be described as a process which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations can be performed in parallel or

concurrently. In addition, the order of the operations may be rearranged. A process may be terminated when its operations are completed, but could have additional steps not discussed or included in a figure. Furthermore, not all operations in any particularly described process may occur in all embodiments. A process may correspond to a method, a system, a procedure, etc. As used herein and in the appended claims, the singular forms "a", "an", and

"the" include plural references unless the context clearly dictates otherwise. Thus, for example, reference to "a process" includes a plurality of such processes, and reference to "the nutrient" includes reference to one or more nutrients and equivalents thereof known to those skilled in the art, and so forth. Also, the words "comprise", "comprising", "contain", "containing",

"include", and "including", when used in this specification and in the following claims, are intended to specify the presence of stated features, integers, components, or steps, but they do not preclude the presence or addition of one or more other features, integers, components, steps, acts, or groups. The description and examples above are not intended to limit the scope, applicability, or configuration of the application to only what has been described. It should be understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the technology as set forth in the appended claims.

Claims

WHAT IS CLAIMED IS:

1. A method of stimulating the production of a biogenic gas, the method comprising:

injecting a fluid mixture into a subterranean geologic formation containing a carbonaceous material, wherein the injection causes fractures to form through the formation that allows the fluid mixture to be delivered to the

carbonaceous material;

stopping the injection of the fluid mixture;

allowing the injected fluid mixture to disperse through the formation such that microorganisms native to the formation may access the injected fluid mixture; and

increasing the production of the biogenic gas from microorganisms stimulated by the injected fluid mixture to convert a portion of the carbonaceous material into the biogenic gas.

2. The method of stimulating the production of a biogenic gas of claim 1 , further comprising accessing the geologic formation to determine that microorganisms are present in the formation.

3. The method of stimulating the production of a biogenic gas of claim 2, further comprising characterizing at least one microorganism from the formation.

4. The method of stimulating the production of a biogenic gas of claim 1, wherein stopping the injection of the fluid mixture further comprises sealing access to the geologic formation to allow a buildup of the biogenic gas.

5. The method of stimulating the production of a biogenic gas of claim 4, further comprising monitoring at least one environmental characteristic in situ after the access to the geologic formation has been sealed.

6. The method of stimulating the production of a biogenic gas of claim 5, wherein the pressure within the formation is monitored to determine an amount of biogenic gas produced.

7. The method of stimulating the production of a biogenic gas of claim 1, wherein the injection is at least partially performed horizontally through the formation environment.

8. The method of stimulating the production of a biogenic gas of claim 1 , wherein the fluid mixture comprises an emulsion having at least one of a dispersed phase and a continuous phase.

9. The method of stimulating the production of a biogenic gas of claim 8, wherein the emulsion includes an amendment in at least one of the dispersed phase or the continuous phase.

10. The method of stimulating the production of a biogenic gas of claim 1 , wherein the fluid mixture comprises an amendment including at least one compound selected from the group consisting of an acetate compound, a yeast extract, an algal extract, and a phosphorus compound.

11. The method of stimulating the production of a biogenic gas of claim 1, wherein the fluid mixture comprises an amendment including at least one vitamin.

12. The method of stimulating the production of a biogenic gas of claim 1 , wherein the fluid mixture comprises an amendment including at least one protein or material containing protein.

13. The method of stimulating the production of a biogenic gas of claim 12, wherein the protein or material containing protein comprises milk proteins, casein hydrolyzates, soy protein, peptones, yeast extract, or Brewer's yeast.

14. The method of stimulating the production of a biogenic gas of claim 1, wherein the fluid mixture includes one or more proppants.

15. The method of stimulating the production of a biogenic gas of claim 1 , wherein the fluid mixture includes a foaming or gelling agent.

16. The method of stimulating the production of a biogenic gas of claim 1, wherein the fluid mixture comprises an anaerobic aqueous mixture.

17. The method of stimulating the production of a biogenic gas of claim 1 , wherein the fluid mixture does not inhibit, neutralize, or destroy the native microorganisms.

18. The method of stimulating the production of a biogenic gas of claim 1 , wherein the fluid mixture includes a tracer.

19. The method of stimulating the production of a biogenic gas of claim 1 , wherein the subterranean geologic formation comprises a previously fractured formation environment.

20. The method of stimulating the production of a biogenic gas of claim 19, wherein the fluid mixture is injected such that the fractures are formed in a direction substantially parallel to the previous fractures.

21. The method of stimulating the production of a biogenic gas of claim 19, wherein the fluid mixture is injected such that the fractures are formed in a direction substantially orthogonal to the previous fractures.

22. A method of stimulating the production of a biogenic gas, the method comprising:

forming an access in a subterranean geologic formation containing a carbonaceous material;

analyzing the formation environment;

injecting a fluid mixture into the formation through the access, wherein the injection causes fractures to form through the formation that allows the fluid mixture to be delivered to the carbonaceous material;

stopping the injection of the fluid mixture;

sealing the access to the formation;

monitoring the formation environment; and increasing the production of the biogenic gas from microorganisms stimulated by the injected fluid mixture to convert a portion of the carbonaceous material into the biogenic gas.

23. The method of stimulating the production of a biogenic gas of claim 22, wherein the monitoring the formation environment comprises monitoring at least one environmental parameter.

24. The method of stimulating the production of a biogenic gas of claim 22, wherein the analyzing comprises characterizing at least one microorganism from the formation environment.

25. The method of stimulating the production of a biogenic gas of claim 22, wherein the fluid mixture comprises an emulsion.

26. The method of stimulating the production of a biogenic gas of claim 22, wherein the carbonaceous material comprises coal, oil, carbonaceous shale, oil shale, tar sands, tar, ignite, kerogen, bitumen, or peat.