US20120134749A1

US20120134749A1 - Using noble gas geochemistry to evaluate fluid migration in hydrocarbon bearing black shales

Info

Publication number: US20120134749A1
Application number: US13/297,263
Authority: US
Inventors: Thomas Darrah
Original assignee: Individual
Current assignee: Individual
Priority date: 2010-11-15
Filing date: 2011-11-15
Publication date: 2012-05-31

Abstract

American energy costs steadily increase leading to increased unconventional energy use. However, scientific barriers prevent widespread and economic development of these resources. In gas shale plays, resource utilization is limited by the understanding of how hydrocarbons and other fluids migrate in fractured rock. This limits industry's ability to extract hydrocarbons with enhanced recovery methods; prevents exploration in areas where hydrocarbons do not collect in traditional traps; and could unfortunately lead to dangerous environmental consequences such as contaminated groundwater. To address these concerns, the present invention integrates geochemical and geostructural techniques in a novel method for evaluating and optimizing the placement and drilling strategies of extraction wells in hydrocarbon rich black shales. By correctly choosing hydrocarbon “sweet spots” companies can reduce the number of unprofitable wells, choose directional drilling and completion strategies to accurately reflect the subsurface, and better select prime small- and full-field reservoirs.

Description

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U.S. Provisional Application No. 61/413,967, 2010 Filed Nov. 15, 2010.

FIELD

The following description relates generally to natural gas recovery, and more particularly to a method for identifying highly productive locations for hydrocarbon extraction from black shale.

BACKGROUND OF THE INVENTION

Driven by geopolitical and hydrocarbon reserve uncertainties and the continuously increasing real cost of energy, domestic energy production is necessary to ensure the energy security and independence of the United States. In order to meet these increasing energy demands with domestic production, unconventional energy resources such as shale gas, shale oil and alternative coal technologies must be increasingly utilized. Economically viable production of unconventional energy resources requires enhanced methods of oil and gas recovery such as hydraulic fracturing and horizontal drilling.
The combination of these techniques has had mixed success at extracting economic quantities of natural gas from low permeability shale deposits, which have poor country rock permeability and transmissivity, but can contain natural fractures. Hydraulic fracturing involves the injection and extraction of fluids and propping agents in the subsurface to stimulate fluid flow through natural fractures and increase fracture related permeability (e.g. increased fracture aperture, fracture size, and fracture network connectivity) thus enhancing hydrocarbon production. The use of hydraulic fracturing is limited by: 1) inefficient resource recovery, 2) the potential for groundwater contamination from drilling fluids or mobilized hydrocarbons that can migrate through fractures and interact with groundwater, and 3) the current inability to develop accurate models for fracture fluid flow in the exceedingly complex fracture network present in black shale and other fractured lithologies. Therefore successful, economically viable, and environmentally safe application of these techniques requires a detailed understanding of fluid transport within the subsurface, specifically fluid flow within fracture networks.
Accordingly, there is a need for improved strategies for hydrocarbon extraction. The embodiments of a predictive methodology for directly evaluating fluid flow through natural and stimulated fractures in situ by integrating noble gas geochemistry, trace element geochemistry, and fracture analysis, disclosed below, satisfies this need.

SUMMARY

The following simplified summary is provided in order to provide a basic understanding of some aspects of the claimed subject matter. This summary is not an extensive overview, and is not intended to identify key/critical elements or to delineate the scope of the claimed subject matter. Its purpose is to present some concepts in a simplified form as a prelude to the more detailed description that is presented later.
Black shales are of great interest as domestic hydrocarbon plays because of their high organic content and tight gas-retaining nature. Although market demand is increasing interest in shale hydrocarbon extraction, the present inventor is unaware of any comprehensive methodology capable of identifying highly productive areas known as “sweet spots” because of a paucity of information about geological fracture-related fluid flow. Because of the immense costs associated with horizontal drilling and hydraulic fracturing, as well as the risk of environmental impact, hydrocarbon recovery from unconventional sources, such as black shale, is not economically favorable unless wells hit a sweet spot. By directly evaluating natural fluid migration in situ using conservative noble gas diffusion profiles, trace element proxies for geological fluid flow, and the characteristics of the fracture network, the presently disclosed predictive model for natural gas migration and determination of the location of sweet spots in shale has been developed. The present invention will directly contribute to a comprehensive strategy for hydrocarbon extraction, specifically in regions which lack deformed structures that lead to bed thickening shale and increased fracturing. In addition, because its techniques directly monitor fracture fluid migration on multiple geologic scales, the present invention allows for the evaluation of risk for aquifer contamination from hydraulic fluid and shale gas.
The present invention comprises a combination of methods. Noble gas abundances and isotopic ratios (He, Ne) and trace element geochemistry (transition metals (Ti, Mn, Fe), rare earth elements (La—Lu), actinide chemistry (Th/U)) with advanced techniques in fracture network analysis are integrated, in order to: 1) determine the multi-stage fluid flow history through individual fractures; 2) quantify gas diffusion from relatively impermeable hydrocarbon host rock (i.e. black shale) to fracture sets; 3) develop a 3-D geospatial map of the regional fracture network to determine pathways of fluid migration; and 4) map chemical changes for the development of a regional hydrocarbon “sweet spot” map.

DETAILED DESCRIPTION

Preliminary research focused on the New York State portion of the Marcellus shale because of its potential for hydrocarbon production and because the naturally fractured black shale provides an optimal location for describing in detail the claimed methodologies. A short synopsis of the current state of hydrocarbon production in the Marcellus shale, a review of fracture-related fluid flow, fracture network analysis techniques, and relevant geochemical proxies are presented below.

Regional Geology

The Marcellus shale in New York is located on the Appalachian plateau and is in the foreland of the Appalachian Fold Thrust Belt. It lies to the North and West of the Valley and Ridge province and is characterized by salt-detachment tectonics. The first order deformation structures of the Appalachian plateau are detachment folds, which have a basal decollement in the Silurian-aged Salina Salt. This salt layer acts as the glide plane for the Appalachian plateau detachment sheet and causes surface features characteristic of salt tectonics such as broad, gentle folds and abrupt changes in deformation style at the lateral and frontal termination of the salt. Salt also plays a role in faulting. Salt is thickened in the hinges of detachment anticlines and provides a weak zone that is easily faulted, resulting in blind reverse splays that cut up from the decollement in the salt and slice through this weak core.
The stratigraphy of the Appalachian plateau varies, but in New York the Marcellus shale is the stratigraphically lowest subgroup of the siliciclastic Devonian Hamilton group. The Hamilton group is sourced from the Acadian orogeny and Rb-Sr dating of the lower Devonian black shales in the Hamilton groups puts their age at 384±9 to 377±11 Ma. The Hamilton group is sandwiched between the overlying late Devonian Catskill deltaic sequence and the underlying clean carbonates of the Devonian Onondaga limestone. The Marcellus subgroup is comprised of three formations: 1) the Union Springs-the lowest stratigraphic black shale unit; 2) the Oatka Creek Formation-the highest stratigraphic black shale; and 3) its lateral stratigraphic equivalent, the Mount Marion Formation. The Union Springs formation is made of black shales and dark grey limestones, and is separated from the black shales of the Oatka Creek and Mount Marion formations by the Cherry Valley limestone.
The Appalachian plateau was deformed during the Pennsylvanian-Permian Alleghany orogeny. During this event, deformation progressed from the hinterland to the foreland along the basal salt layer. The Appalachian Plateau detachment sheet progressed to the northwest during this orogeny and did not interact with the underlying basement. Deformation within the detachment sheet varies with stratigraphy; in the lowermost strata shortening was accommodated by low-angle thrust faulting, while at higher levels shortening was first taken up by layer-parallel shortening and then accommodated by broad folding. In all, Alleghanian deformation occurred during two progressive stages: layer parallel shortening occurred first and was followed by a period of detachment folding and reverse faulting.
The first stage of deformation, layer parallel shortening, is expressed in surficial geology by the deformed fossils and solution cleavage. Strains of up to 20% are observed in fossils and both solution cleavage and fossil shortening indicates a strain ellipsoid that has its short axis perpendicular to the regional structural trend. Solution cleavage maintains its bed-perpendicular orientation around folds and confirms that cleavage formed before folding.
During the second stage of deformation, detachment folds formed by buckling above the Salina salt. These folds are characterized by comparatively tight anticlines cored by salt and broad synclines (FIG. 3). The cores of folds are significantly tighter in the salt horizon, but at higher stratigraphic levels folds are open with very gently dipping limbs (<5 degree limb dips). Folds are slightly asymmetric with steeper southeastern limbs. Thrust splays cut up from the decollement through the weak anticlinal fold-cores but do not make it to the surface and both antithetic and synthetic faults are common.
Fracturing is a pervasive and complex feature of the Appalachian plateau that developed during successive phases of the Alleghanian orogeny and is associated with the first order structures. Fractures can be grouped into sets by their orientation, but the relationships between these sets are not completely understood. N-S striking fractures are interpreted as extension fractures due to early E-W extension in the forebulge of the Alleghanian orogeny. Cross-fold fractures (strikes ranging from 012° to 327° are difficult to interpret; explanations vary from fracturing due to multiple phases of the Alleghanian orogeny, to fracturing due to the stress field before the Alleghanian orogeny or tectonic unloading after the orogeny, or a combination of these mechanisms that invokes reactivation of fractures. ENE-striking fractures(˜071°) are interpreted as neotectonic and due to overpressure caused by hydrocarbon generation.
During Alleghanian tectonics, fluids migrated to the Appalachian plateau from the Appalachian fold-thrust belt, with the hypotheses for the driving force ranging from a mechanical “squeegee” to a thermally driven mechanism. This fluid migration caused a widespread resetting of the magnetic signatures in the rocks, suggesting regional-scale fluid flow. This regional fluid flow utilized fractures within the Marcellus shale and is recorded in the geochemistry of the country rock and veins. Although the natural gas found in the Marcellus shale formed in place, this regional fluid flow caused the transport of fluids through fractures and is evidence of past fluid flow through the fracture network. This fluid flow may have altered gas concentrations in the Marcellus, and quantifying these changes can serve to define a model for understanding gas recovery through induced fracturing (eg. hydraulic fracturing)
Hydrocarbons can be created through biogenic and thermogenic means, with biogenic processes being significant at shallow depths and thermogenic production dominating at deeper levels. Significant hydrocarbon generation is usually attributed to a thermogenic process; hydrocarbons are formed at depth from the thermal degradation of kerogen. As rock is buried, temperature and pressure increase and the structure of kerogen becomes unstable. Kerogen progressively adjusts to this increasing temperature and pressure by eliminating functional groups and the linkages between nuclei, thus generating a wide range of compounds including hydrocarbons, CO₂, Water, and hydrogen sulfide. Additionally, natural gas comprised of methane, ethane, propane, and n-butane (C1, C2, C3, and C4, respectively) can be generated through the mechanism of transition-metal catalysis. Laboratory efforts to generate gas by purely thermal mechanisms show higher formation temperatures than observed in nature (up to 400° C.) or result in a higher fraction of heavy gasses (C2-C4) than seen in nature. However, a catalytic mechanism produces gas at low temperatures (□200° C.) with C1—C4 fractions that mimic natural gas. In particular, marine shales (such as the Marcellus shale) show an increase in released light hydrocarbons over time, indicating the opposite effect of traditional desorption. These shales generally contain the necessary transition metals for catalytic gas generation and the Marcellus shale is no exception.

Hydrocarbon Production in the Marcellus Shale

Within the last 5 years interest in natural gas production from the Marcellus shale has spiked because of the development of enhanced recovery technologies. Although there is current drilling for natural gas in the Marcellus shale in Pennsylvania, permitting issues have stalled work in New York. Current drilling efforts in Pennsylvania are focused on the hinges of anticlines where the Marcellus is thickened and where fracturing is most intense, but this strategy is not viable in New York because deformation towards the east is weaker and large scale geologic structures (e.g. folds) are more subtle. Despite political delays and geostructural challenges, there is interest in drilling in New York. The lack of structural controls and an insufficient understanding of fracture fluid flow necessitate more research in order to ensure efficient and safe production of natural gas. The lack of recent exploration in the NY Marcellus shale makes the present invention both timely and useful. With sufficient data, the present invention can develop reservoir-, field-, and regional-scale interpretations of fluid flow without the need for extrapolation; this makes the present predictive technology especially useful to local inhabitants, state governments, and hydrocarbon extractions corporations when implemented in the early stages of exploration.
In addition to the appropriate timing for evaluation and increasing resource demands, the Marcellus shale offers logistical advantages that make it an excellent case study. For example, it is exposed in many quarries across New York State based on its stratigraphic position above the quarried Onondaga limestone. This coincidence allows study of the three-dimensional relationships of fractures with great accuracy, and sampling of fresh, unaltered, outcrops that are revealed through quarrying activities. These outcrops are not weathered and their geochemistry is preserved, making them a useful analogue for more deeply buried rocks.
Some economically important geological advantages to studying the Marcellus shale in New York are the type of deformation, the amount of deformation, the fracture pattern, and the regional fluid flow that this area experienced. Compared with the intensely deformed sections of the Marcellus shale in the Valley and Ridge province of Pennsylvania, the Marcellus shale in New York is relatively undeformed and fracture patterns have not been overprinted by larger structures. This lack of deformation in Appalachian plateau region of the Marcellus prevented the thickening and increased fracturing of shale beds, making it very difficult to determine the best location for extraction wells and predict the location of highly fractured “sweet spots”. This necessitates the understanding of fracture related flow in the plateau section of the Marcellus shale for any drilling program.

Static Conductivity, Fractures, and Hydrocarbon Flow

Fractures are surfaces in rock along which mechanical failure has occurred and the rock has lost cohesion. They can form in tension (mode 1) or shear (mode 2 or 3) and often form sets of similarly oriented members. Fractures that accommodate some degree of slip along their surfaces are faults, while fractures that have no observable slip are joints. A grouping of fractures with sub-parallel orientations is a fracture set, while all of the fractures regardless of orientation form the fracture network.
Because black shale (country rock) is the ultimate source of hydrocarbons, the rate at which hydrocarbons diffuse into fractures and flows through the fracture network limits hydrocarbon production. The rate of hydrocarbon diffusion into fractures and through the fracture network is controlled by the hydraulic conductivity of the system (K). Hydraulic conductivity is a function of a rock's bulk porosity and permeability and describes the ease with which a fluid is transported through pore spaces or fractures.
In black shale, the extractable volume of hydrocarbons is directly proportional to the system's hydraulic conductivity (hereafter: K), which is a factor of 1) the hydraulic conductivity of the country rock (K_CR) and 2) the fracture network (hereafter: K_FN). Thus fluid flow is simultaneously affected by K_CRand K_FNand their interaction (Eaton, 2006). In areas that have low country rock permeability (i.e. shales), flow properties are dominated by fractures, while fractures are less important in areas with higher country rock permeability (e.g. sandstones). As hydrocarbons diffuse from the country rock into fractures, the hydraulic conductivity of the fracture network (K_FN) is directly related to the characteristics of the individual fractures, fracture sets, and the entire fracture network.

Individual Fractures

Size, location, termination style, aperture, planarity and roughness are key characteristics to determine flow within individual fractures. The size of a fracture refers to the three-dimensional surface area of the fracture, while aperture is the openness of fracture planes. Planarity (a measure of a fracture's deviation from a plane) and roughness (planar tortuosity) are important factors in determining permeability. The termination style defines the geometric orientation of the end of a fracture. There are four types of terminations including: T—a perpendicular intersection between fractures; J—an intersection in which one fractures curves into the other; I—a fracture that ends at its tip line without intersection and X—cross-cutting fractures. Combinations of these termination geometries and the location of individual fractures define the 3-D geometry of a fracture network. All of the above parameters influence hydraulic conductivity (i.e. the amount of hydrocarbons that can migrate through the fracture) and each other. For example, permeability and porosity concomitantly increase with increasing country rock grain size and fracture size, and the statistical probability of fracture intersection (connectivity) also increases with larger fracture size. Fracture connectivity, porosity, and permeability all affect hydraulic conductivity implicating a complex relationship between K_FNand fracture properties.

Fracture Sets and Networks

Fractures are grouped by their geometry into fracture sets or groups of sub-parallel oriented fractures. Orientation and spacing of fracture sets in a network are characteristics that affect fluid flow in different ways. For dense and homogeneous fracture networks fluid flow can be treated as flow through a porous medium, while in sparsely fractured areas a few large fractures may dominate flow. Fracture network hydraulic properties depend on fracture intensity (surface area of fractures per unit volume), connectivity (number of fracture intersections per unit volume), hierarchy, and chronology.

Critical Dynamic Parameters Impacting Fracture Regulated Fluid Transport

Modeling the migration of hydrocarbons in fractured black shales is exceedingly complex due in part to the complex nature of hydraulic conductivity in a fractured medium, but also to the many dynamic processes of the earth. For example, dynamic changes in parameters such as regional stress field, in fracture mineralization, fluid pressure, climatic changes (wetness/dryness), fluid gradient, anthropogenic water use, and tectonic processes reduce the accuracy of model inputs significantly and retard the understanding of fluid transport through fractured media.
Most importantly, even at great depths under high overburden pressures, fractures must be open in order to accommodate fluid flow. How fractures remain open (aperture>0) and the relative importance of mechanical and diagenetic characteristics in keeping fractures open is still contentious. Some authors argue for the role of the in situ stress field and suggest that only fractures oriented parallel to the maximum compressive stress will stay open and accommodate fluid flow. Fractures may never completely close if there is a sufficient hydraulic gradient, even though permeability decreases significantly as stress normal to the fracture increases. In addition, some component of shearing can keep fractures open, causing asperities on opposite faces of the fracture to ride up over one another and prop open the fracture.
The diagenetic approach to finding open fractures focuses on mineralization within open fractures and country rock stiffening due to cementation. Mineral bridges can form in fractures and cement can precipitate in the host rock holding fractures open regardless of fluid pressure or stress field changes. In the Travis Peak formation in East Texas, fluid inclusions were used to reconstruct the temperature and pressure of vein formation. Burial models suggest a 48 Myr history of vein growth, indicating that fractures were open and slowly grew minerals for an extended period of time. However, mineralization does not necessarily lead to increased permeability through fractures since complete mineralization can cause fractures to close. For example, the hydrocarbon-rich Barnett Shale of Northern Texas has fault induced fractures, but drill cores show pervasive calcite veining which correlates with low hydrocarbon production in heavily fractured areas and suggests that fractures can be completely sealed by mineralization. Past research indicates that partially mineralized fractures have the greatest potential to stay open, but fracture type and geometry as well as hydraulic gradient can play a role.
Theoretical models and field observations suggest that, local fluid pressures can exceed lithostatic pressure, generating large hydrofractures that are capable of cutting up from a reservoir and through impermeable cap rock. Although only some large fractures cut through many stratigraphic layers, they interact with the entire fracture network by crosscutting smaller features and are capable of transporting fluids over large distances as observed in the Uinta basin, where field observations have identified natural hydrofractures that transported fluids for several kilometers vertically and tens of kilometers horizontally.

Use of Geochemistry in Fluid Flow Studies

The exhaustive list of considerations included above provides an example of the varied and complex manner in which fractures can influence fluid migration and the numerous dynamic fracture-related processes that can change both geospatially and over time. These considerations depict the difficulty of developing a theoretical model for fracture fluid flow and hydrocarbon extraction from shales. The level of current modeling capabilities, varied geological structure throughout hydrocarbon lithology, and dynamic changes within the fracture network lead to expensive and economically imprudent drilling of many failed, non-productive wells. By placing direct empirical measurement of conservative, in situ, and natural tracers for methane diffusion and fluid flow on the micro-, meso-, and macro-scale in its geostructural framework, the present invention provides a cost effective solution. The present invention develops a regional “sweet spot” model, by first understanding micro-scale fluid flow and meso-scale gas diffusion and flow. Therefore, by determining fracture flow rates, fracture flow direction, and the geometry and properties of the fracture network before horizontal drilling and hydraulic fracturing the present invention improves the success rate of drilled wells.
The present invention first considers the appropriate geochemical tracers for evaluating micro-scale and macro-scale fluid flow in fractures. Two tools are chosen for analyzing fluid flow in fractures: (1) Noble Gas Geochemistry (NG): He, Ne, and Ar (useful for directly quantifying fluid migration through the complex fracture network on the meso-scale and macro-scale) and (2) trace element (TE) microchemistry by Cryogenic Laser Ablation Inductively Coupled Plasma Mass Spectrometry (CLA-ICP-MS): transition metals (Mn, Fe, Ti), rare earth elements (La—Lu), and actinides (Th/U) (used to evaluate microchemistry changes (˜5 μm scale) providing a geological record of fluid through fractures).

Noble Gas Geochemistry

The inert chemical nature of noble gases makes them ideal tracers of fluid origin, fluid diffusion, fluid-rock interaction, and fluid flow mass balance in the Earth's crust. In crustal fluids, including hydrocarbons, noble gases are derived from three main sources including mantle (M), crust (C), and atmosphere (A). In most organic-rich shales, mantle-sourced noble gases do not play a significant role and are therefore excluded for brevity. Crustal (C) and atmospheric noble gases, however, do have significant sources in such organic-rich shales, while each respective reservoir has a unique noble gas elemental and isotopic composition. The changes in the noble gas composition that occur as fluids migrate along fractures and interact with crustal fluids primarily relate to the radiogenic nature of the rock protolith and its geologic history. Uranium (U) and thorium (Th) (both of which are present at relatively high concentrations in most black shales decay to ⁴He (alpha-particle: α) (i.e. ^{(235 or 238)}U and²³²Th
⁴He) simultaneously producing an array of minor nuclear reactions. For this study, an important interaction produces Ne-21 when the alpha particle strikes an O-18 nucleus [¹⁸O(α,n)→²¹Ne]. Other various reactions that produce Ne isotopes (i.e. ²⁴Mg (n,α)→²¹Ne and ³He, ²⁵Mg (n,α)→²²Ne and ³He, and ²³Na(n,α)→²⁰Ne and ³He or are not significant in most crustal settings with the exception of fluorine-rich rocks that produce Ne-22. Black shales also contain significant amounts of potassium (⁴⁰K) which decays to (⁴⁰Ar) (⁴⁰K→⁴⁰Ar) that ultimately ends up in many crustal natural gases. The above interactions lead to significant increases in [⁴He] (i.e. low radiogenic or crustal ³He/⁴He (e.g. 1×10⁻⁸or 0.01Ra, where Ra: 1.39×10⁻⁶)), enriched ^{21 Ne/} ²²Ne (e.g. 0.035-0.050 elevated from the air value of 0.029 by nucleogenic production), and drastically increased ⁴He/²¹Ne (excess) (e.g. 20×10⁶) as hydrocarbon and groundwater fluids interact with fracture surfaces. Atmospheric noble gases (ANG) are incorporated into crustal fluids (i.e. mainly groundwater) either when water equilibrates with atmospheric gases prior to being recharged into the subsurface (termed air saturated water (ASW) or as sedimentation pore water at the time of sediment deposition. The relevant concentrations of ANG in groundwater are dependent upon temperature equilibrium at the time of recharge and the Henry's Law solubility of each noble gas where the Henry's Law constant increases in the heavier noble gases (i.e. solubility: He<Ne<Ar<Kr<Xe). In comparison to crustal gas interaction, circulating fluids with ASW composition have low [⁴He] (but higher ³He/⁴He (e.g. 1.36×10⁻⁶or ˜0.985Ra, where Ra: 1.39×10⁻⁶)), atmospheric ²¹Ne/²²Ne (e.g. 0.0289), and low solubility controlled ⁴He/²¹Ne (e.g. 85). Noble gas compositions with ASW composition would indicate fluid flow through permeability, highly fractured fracture network. Thus, the amount of ASW gas in a natural gas deposit (e.g. ³⁶Ar content-ppm) is often a function of the amount of fluid flow or residual pore water. Ballentine et al. (2008) and Gilfillian (2009) have modeled these interactions in a series of papers on the major carbon dioxide rich gases of the western US. It is herein proposed that gas (and rock) samples with dominantly ASW composition may have witnessed major fracture flow that led to extensive hydrocarbon loss. By measuring the noble gas composition in pore fluids and retained in mineral lattices (country rock and vein minerals) the origin and subsurface interaction of hydrocarbons in the subsurface can be constrained, enabling the quantifying of the migration with a fractured network.
Noble gas (NG) geochemistry has been used to constrain the permeability, effective porosity and the interaction of sedimentary basins with groundwater and to trace basin-wide migration of methane and other hydrocarbons. In addition, NG studies have identified when groundwater flow is dominated by advection through fractures and quantified interaction of fracture network fluids with surrounding rock.
In shale, the production of ⁴He and ²¹Ne by radioactive decay of the uranium and thorium series produces an alpha particle that travels 6 to 8 microns and can either embed in a quartz grains as a He atom, or, interact with an ¹⁸O atom within the quartz to produce ²¹Ne. The ⁴He/²¹Ne production ratio in quartz is 2.2×10⁷, that is one out of every 22 million alpha decays produces ²¹Ne in quartz. These two decay products (⁴He, ²¹Ne) are useful for tracing fluid flow because they interact with quartz crystals differently. ⁴He has a small atomic radius that can diffuse through quartz over geologic time scales. Over millions of years, the helium in the pore space (freely available to interact with circulating fluids) and the helium concentration in the quartz crystal reach equilibrium. ²¹Ne formed within the quartz grain has a larger atomic radius and has limited diffusion in quartz at room temperature but is only re-released at higher temperature or as the result of quartz breakdown. Thus, fluid flow along fractures in sedimentary basins reduces ⁴He concentrations in the quartz (as gas is removed with circulating crustal fluids) while ²¹Ne remains trapped in the quartz. Because ¹He and ²¹Ne are produced throughout the lifetime of the shale they give an estimate of the total flow of gases since lithification and when measuring spatially within and/or near fractures can provide an estimate of volume of shale that has been degassed. Helium, which is more diffusive than methane, effectively provides a tracer of gas diffusion from the country rock into fractures with fluid mobility.
This hypothesized behavior of the He and Ne in quartz suggests that in areas with widely spaced and flow accommodating fractures, draining of noble gasses along fractures would result in a gradational decrease in ⁴He/²¹Ne concentrations in rock as the distance to the fracture decreases (i.e. closer to fractures more degassed). In areas that have seen little fluid flow, the He/Ne ratio will approach the anticipated production ratio (e.g. ⁴He/²¹Ne: 2.2×10⁷) as determined by measuring [U] and [Th]. Conversely, in regions close to very conductive fractures more than 95% of the helium will be lost. By contrast, a much lower ⁴He/²¹Ne ratio can be expected in areas with a high density of conductive fractures as has been observed previously (Cook et al., 1996). Measuring the ⁴He and ²¹Ne concentrations and constructing a degassing/diffusion profile is useful for identifying areas where extensive fluid flow has occurred. Testing the retained ⁴He (i.e. highest diffusion coefficient) in a fractured but relatively impermeable rock provides an estimate of total permeability of the formation. If noble gas ratios, specifically at depth, show an ASW profile without significant interaction with crustal fluids (e.g. ³He/⁴He: 0.51.0 Ra, and ASW ²¹Ne/²²Ne: 0.029), there is a potential for extensive noble gas and hydrocarbon loss from previous fluid flow along fractures throughout geological time. These areas can be avoided when choosing where to drill. By contrast, if noble gas compositions show extensive interaction with crustal fluids and a diffused ⁴He/²¹Ne _profile (much below production ratio), then we anticipate high fracture network hydraulic conductivity (K_FN) without prior loss of crustal noble gases and hydrocarbons is anticipated. These locations would define sweet spots because of their high K_FNwill enable fluid extraction along the naturally occurring fracture networks. Alternatively, if an area has a ⁴He/²¹Ne approaching production ratios it would imply true “tight gas” country rock with a poor fracture network. While these potential plays would still retain hydrocarbons, economically viable extraction along natural fracture networks is unlikely. These areas would require more costly horizontal drilling and hydraulic fracturing, but still lead to less production making less than optimal hydrocarbon plays.

Vein Trace Element Microchemistry by Cryogenic LA-ICP-MS

Past research has shown that hydrocarbons, groundwater, and radiogenically produced gases interact in the subsurface with circulating fluids imprinting their chemical signature on the immobile fraction. Indeed, the movement of water in the subsurface has profound implications for collection, migration, and entrapment of natural gas and oil. Helium, methane, and water all migrate along the same fracture pathways, while ⁴He/²¹Ne and ⁴He record the relative amount of fluid degassing and the pathways along which water and mobilized hydrocarbon fluids travel. However, noble gas methodologies alone do not preserve a record of the volume of water flux, timing, or cycles of fluid migration in black shales.
Conversely, vein filling minerals (such as calcite) incorporate the chemical composition of pore fluids during mineralization providing a geochemical archive of pore fluid chemistry throughout various flow events during vein formation. As a result, vein minerals record the micro-scale interactions of fluids with fracture surfaces. Trace element concentrations in calcite veins, specifically rare earth elements (REEs), oxyanion forming trace metals (OFTM) (e.g. Mn, Fe, As), and actinides (Th and U) may be used to estimate the volume of fluid migration, number of pulses of fluid migration, the source chemistry with which fluids interact, changes in fluid chemistry (e.g. pH, redox potential) and the time of vein filling.
This suite of TEs (i.e. oxyanions forming transition metals, REEs, and actinides) is selected in order to evaluate the interaction of migrating fluids and fractured country rock during fluid migration because they have a high degree of interaction with fracture surfaces and a preference to precipitate from water and incorporate into vein forming minerals in a predictable pattern dependent upon each of their individual chemical affinities. These characteristics result in their ability to accurately record relevant changes in pH, E_H(oxygen fugacity), and saturation conditions (i.e. relative volume of water flux). For example, Mn and As oxyanions complexes are conservative and highly mobile at a neutral to basic pH across a range of E_Hconditions, while REEs are only mobile in acidic and highly saline conditions and travel primarily with dissolved organic carbon (DOC) all of which lead to a measurable fraction of these elements in vein calcites. U and Th in country rock are fractionated when interacting with crustal fluids because U has the ability to complex with DOC or form oxyanions, leading to low relative Th/U in fluids transported along fractures as compared to fluids directly interacting with country rock. Comparatively immobile trace elements such as REEs and Th will increase during low fluid transport (i.e. greater interaction with country rock) and decrease during periods of high rates of fluid transport as has been observed for some transition metals including Fe and Mn.
Because vein mineralization occurs slowly over geological time, exceedingly small analytical resolution is needed in order to evaluate spatial changes in chemical composition within vein minerals. The advent of high resolution LA-ICP-MS enables the in situ analysis of these selected trace elements within individual veins to a resolution of several dozen microns (˜20 μm). This capability allows microchemical spatial determination of calcite vein chemistry, a proxy for pore fluid evolution through fractures.
However, the current state of LA-ICP-MS capabilities poses two potential problems for the analysis of vein mineralization, which include significantly lower analytical sensitivity as compared to solution based-ICP-MS and poor laser coupling with organic-rich country rock and vein minerals.
While some trace elements are present at easily detectable concentration in vein minerals (Mn, Fe, Zn, La, Ce), these analytes can only be reliably measured at a resolution of ˜20 μm (20 μm spot size). Although this spatial resolution is markedly better than in solution analysis, optical mineralogical observations show precipitations fronts on the scale of a few microns (˜10 μm). A current laser ablation system can ablate to a spot size approaching 2 microns, but sensitivity is decreased at a smaller spot size. Additionally, even if smaller spot size reaches sufficient spatial resolution, it still does not permit robust ablation of organic-rich materials. To overcome this analytical hurdle, a high sensitivity, fast washout cryogenic laser ablation system (GMA 4200Volante CryoCell) is used. This cryogenic laser ablation system cryogenically freezes the organic material enabling robust and reproducible analysis of organic-rich samples. Additionally, the GMA Volante laser ablation cell, when combined with cryogenic capability, improves analytical sensitivity ˜10× enabling analysis of REEs and actinides (Th/U) and providing sufficient spatial resolution to monitor the record of fluid flow fluctuations throughout geological time.
Therefore, the claimed combination of trace element microanalysis and noble gas techniques provides a framework to understand the characteristics, cycles, and timing of fluid flow and the potential for hydrocarbon fluid extraction. These claimed methodologies, enable the development of basin scale maps depicting “sweet spots” (hydrocarbon-bearing and conductive along natural fracture network), “dead spots” (and highly fractured and extensively diffused without a history of crustal interaction), “potential spots” (where “tight gas” extraction will be expensive despite the presence of hydrocarbons), and ground truthing well selection procedures within hydrocarbon producing black shales.
Although several studies have examined the chemistry of fractured rocks in the Appalachian basin by using fluid inclusions in veins, little work has been done on the partially mineralized fractures that likely accommodate fluid flow. In addition, past research has focused on either the mechanical properties of individual fractures, or modeling flow through fracture networks based on fracture orientations. The present invention takes a uniquely integrated approach, using a combination of fracture network analysis and applying geochemical tools to evaluate the flow of hydrocarbons through the fracture network within hydrocarbon producing black shales.
The present invention addresses the role of natural fractures on fluid distribution and flow in shale in four ways: (1) mapping the physical characteristics of fracture sets such as the 3-D fracture network geometry, and interpreting fracture history based on cross cutting relationships (geostructural analysis); (2) analyzing the microchemistry of individual types of open and vein-filled fractures to determine fracture interaction with fluids (cryogenic LA-ICPMS (CLA-ICP-MS) TE geochemistry) ; (3) measuring the percent change in the bulk permeability of the shale due to fracturing (NG and (CLA-ICP-MS) TE geochemistry); and (4) assessing the current basin scale variations in the NG chemistry to determine system scale gas diffusional loss. By looking at what controls fluid flow at different scales, the present invention enables the identifying of the contributions of different variables, whether regional-scale or microscale, and the understanding of the interplay between them. This is of fundamental importance in understanding geologic fluid flow through a fractured medium and something that previous studies have failed to capture. In addition, the present invention comprises a suite of methods that can accurately assess modern day fluid flow through fractured rock providing near real-time in situ measures of fluid migration.

Microscale Studies

In order to understand the effect of fracture systems on fluid flow, the role of individual fractures in the process must first be understood. Geostructural analysis evaluates the role of individual fracture characteristics (i.e. aperture, size, roughness, mineralization, and chemical characteristics) on fluid flow. Preliminary data finds un-mineralized, partially mineralized, and completely healed fractures in some shale. When fluids migrating along fractures become supersaturated with respect to dissolved elemental concentrations they grow crystals into open fractures, which incorporate and record elemental composition of the fluids. By examining elemental crystal microchemistry of minerals across the aperture of a fracture fluid composition changes over time can be evaluated to determine the fracture characteristics that best accommodate fluid flow and maximize extraction efficiency.
Preliminary optical microscopy shows euhedral calcite crystals, which indicate growth into open and fluid filled fractures. Nascent crystal growth proceeds from fracture walls progressively towards the fracture opening until the fracture heals or fluid flow stops. Preliminary CLA-ICP-MS analyses of vein chemistry show an exciting pattern of Mn and REE concentrations in calcite crystals. Microsampling of an individual vein (˜4.5 mm thick) at 10-micron resolution shows cyclic variations in REE concentrations with three peaks per cross section showing a 6-8 times increase in
REE levels. The average wavelength of these cycles is approximately 1.3 mm and suggests the occurrence of at least three distinct fluid flow events during vein formation. CLA-ICP-MS mapping (multiple stitched lines at 5 μm resolution (spot size) to produce a map ˜6 mm×10 mm) on partially mineralized fractures and healed fractures (veins) is conducted to examine the spatial changes in trace element chemistry across individual fractures as a proxy for cycles of fluid flow and mineralization. CLA-ICP-MS provides accurate spatial micro-sampling at geochemically relevant intervals in organic-rich samples with sufficient analytical sensitivity and specificity to accurately determine actinides and REEs in calcite veins OFTM (e.g. Mn, As), REEs, and actinides (Th/U) in vein minerals are analyzed because they are ideal tracers for the evolution of fluid chemistry and the interaction of migration fluids with fracture surfaces within country rock.
In addition to studying the cycles of fluid flow, noble gas chemistry of vein fluid inclusions is analyzed to provide a snapshot of basin chemistry at the time of vein formation. Noble gas composition from these fluid inclusions is compared with trace element and noble gas chemistry of vein minerals to evaluate gas diffusion as the system changes. The combination of these tracers can then be used to develop a gas diffusion/migration model for fluids on the microscale.

Mesoscale Studies

After determining the fluid flow characteristics of individual fractures (microscale), the findings are integrated to determine the fluid flow properties of a fracture system as a whole to determine the most efficient fluid flow pathways. To understand the role of the mesoscale factors (stress field, fracture geometry) on fluid flow, the history of fracture sets in the target shale and fracture fluid flow relationships are determined. Two techniques are combined: detailed three-dimensional, sub-meter to km-scale mapping of fractures and sampling for NG and vein TE signatures to correlate fracture patterns with fluid flow.
In one embodiment of the present invention, geostructural mapping is conducted in quarries that cut through the target shale into the underlying limestone. Quarrying leaves a terrace at the base of the shale providing optimal opportunity to observe 3-D exposure. Corners of a quarry have been found to allow examination of the intersecting walls and the quarry floor, providing a detailed picture of the 3-D fracture network. The quarry opening also allows opposite walls to be compared at ˜1 km distance and large scale structures (faults, folds) to be accurately mapped and correlated with variations in fracture patterns. Detailed mapping is done using a meter-square grid with 10-cm subdivisions, while mapping at the 10-1000 m scale is carried out with GPS-based laser rangefinder techniques that allow positional accuracy of <10 cm at a distance of 100 m.
Preliminary research has shown multiple fracture sets of different types and orientations in the target shale formations. In addition to joints, conjugate sets of transverse shear fractures, extensional joints and low angle fractures with reverse shear are shown. This allows observation of calcite veins and partially mineralized fractures with calcite bridges that record several generations of fluid flow as described earlier.
When fracture network geometry from field studies is combined with NG isotopic data, it can determine which fracture sets accommodate fluid flow and identify sweet spots, as described earlier from work on groundwater systems in fractured rock. Samples for NG-MS will be collected from different sets of fractures and host rocks in a variety of locations using a 1-inch core drill. Quantitative fluid flow data is compared with fracture patterns to constrain fracture network effects, and group fractures so that the properties of individual fractures can be used to further understand the flow of hydrocarbons in the target shale.

Regional Variations

Quarries from different parts of the target outcrop belt are studied in this way so that the data can be compared to understand regional variations. In one embodiment of the present invention, drill-cores will be available from a few select test wells in the area, so that variations between the shale at-depth and newly exposed shale at the surface in quarries can be tracked.
Basin wide changes due to fracturing of the target shale are evaluated by combining [U] and [Th] data with NG-MS analyses. By measuring shale [U] and [Th], the anticipated ⁴He/2²¹Ne production ratio is calculated in comparison to measured ⁴He/²¹Ne. The mechanically calculated permeability of the shale is then used to determine the partitioning of He between pore space and crystal, which values are compared with the observations to gauge the effect of different degrees of fracturing in different areas. Assuming that the ²¹Ne remains in the mineral phases, the ratio of ⁴He/²¹Ne relative to production will provide evidence for the amount (volume) of fracturing and hydrocarbon loss in the shale.

Summary

It can thus clearly be seen that the predictive methodology for directly evaluating fluid flow through natural and stimulated fractures in situ by integrating noble gas geochemistry, trace element geochemistry, fracture analysis, and regional structural geology is a significant improvement over the extant shale hydrocarbon extraction methods. Not only is well-selection success rate improved and the use of geologic features maximized, but hydrocarbon extraction is improved and recovery costs are reduced dramatically
What has been described above includes examples of one or more embodiments. It is, of course, not possible to describe every conceivable combination of components or methodologies for purposes of describing the aforementioned embodiments, but one of ordinary skill in the art may recognize that many further combinations and permutations of various embodiments are possible. Accordingly, the described embodiments are intended to embrace all such alterations, modifications and variations that fall within the spirit and scope of the appended claims. Furthermore, to the extent that the term “includes” is used in either the detailed description or the claims, such term is intended to be inclusive in a manner similar to the term “comprising” as “comprising” is interpreted when employed as a transitional word in a claim.

Claims

1. A method comprising:

a. Analyzing noble gases to determine the style of fluid migration in the sub-surface;

b. Analyzing noble gases to distinguish fracture density; and

c. Optimizing the direction and orientation of fluid migration with noble gas and trace element chemistry