U.S. patent application number 13/297263 was filed with the patent office on 2012-05-31 for using noble gas geochemistry to evaluate fluid migration in hydrocarbon bearing black shales.
Invention is credited to Thomas Darrah.
Application Number | 20120134749 13/297263 |
Document ID | / |
Family ID | 46126764 |
Filed Date | 2012-05-31 |
United States Patent
Application |
20120134749 |
Kind Code |
A1 |
Darrah; Thomas |
May 31, 2012 |
Using noble gas geochemistry to evaluate fluid migration in
hydrocarbon bearing black shales
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.
Inventors: |
Darrah; Thomas; (Wilburton,
PA) |
Family ID: |
46126764 |
Appl. No.: |
13/297263 |
Filed: |
November 15, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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61413967 |
Nov 15, 2010 |
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Current U.S.
Class: |
405/80 |
Current CPC
Class: |
E21B 47/11 20200501 |
Class at
Publication: |
405/80 |
International
Class: |
E02B 1/00 20060101
E02B001/00 |
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
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/413,967, 2010 Filed Nov. 15, 2010.
FIELD
[0002] 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
[0003] 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.
[0004] 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.
[0005] 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
[0006] 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.
[0007] 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.
[0008] 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
[0009] 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
[0010] 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.
[0011] 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.
[0012] 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.
[0013] 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.
[0014] 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.
[0015] 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.degree. to 327.degree. 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(.about.071.degree.) are
interpreted as neotectonic and due to overpressure caused by
hydrocarbon generation.
[0016] 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)
[0017] 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,
CO.sub.2, 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.degree. 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
(.quadrature.200.degree. 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
[0018] 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.
[0019] 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.
[0020] 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
[0021] 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.
[0022] 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.
[0023] 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.sub.CR) and 2) the fracture network
(hereafter: K.sub.FN). Thus fluid flow is simultaneously affected
by K.sub.CR and K.sub.FN and 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.sub.FN) is directly related to the characteristics of the
individual fractures, fracture sets, and the entire fracture
network.
Individual Fractures
[0024] 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.sub.FN and fracture properties.
Fracture Sets and Networks
[0025] 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
[0026] 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.
[0027] 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.
[0028] 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.
[0029] 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
[0030] 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.
[0031] 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 (.about.5
.mu.m scale) providing a geological record of fluid through
fractures).
Noble Gas Geochemistry
[0032] 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 .sup.4He (alpha-particle: .alpha.) (i.e. .sup.(235 or
238)U and.sup.232Th.sup.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
[.sup.18O(.alpha.,n).fwdarw..sup.21Ne]. Other various reactions
that produce Ne isotopes (i.e. .sup.24Mg
(n,.alpha.).fwdarw..sup.21Ne and .sup.3He, .sup.25Mg
(n,.alpha.).fwdarw..sup.22Ne and .sup.3He, and
.sup.23Na(n,.alpha.).fwdarw..sup.20Ne and .sup.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 (.sup.40K) which decays to
(.sup.40Ar) (.sup.40K.fwdarw..sup.40Ar) that ultimately ends up in
many crustal natural gases. The above interactions lead to
significant increases in [.sup.4He] (i.e. low radiogenic or crustal
.sup.3He/.sup.4He (e.g. 1.times.10.sup.-8 or 0.01Ra, where Ra:
1.39.times.10.sup.-6)), enriched .sup.21 Ne/.sup.22Ne (e.g.
0.035-0.050 elevated from the air value of 0.029 by nucleogenic
production), and drastically increased .sup.4He/.sup.21Ne (excess)
(e.g. 20.times.10.sup.6) 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
[.sup.4He] (but higher .sup.3He/.sup.4He (e.g. 1.36.times.10.sup.-6
or .about.0.985Ra, where Ra: 1.39.times.10.sup.-6)), atmospheric
.sup.21Ne/.sup.22Ne (e.g. 0.0289), and low solubility controlled
.sup.4He/.sup.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. .sup.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.
[0033] 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.
[0034] In shale, the production of .sup.4He and .sup.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 .sup.18O atom
within the quartz to produce .sup.21Ne. The .sup.4He/.sup.21Ne
production ratio in quartz is 2.2.times.10.sup.7, that is one out
of every 22 million alpha decays produces .sup.21Ne in quartz.
These two decay products (.sup.4He, .sup.21Ne) are useful for
tracing fluid flow because they interact with quartz crystals
differently. .sup.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. .sup.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 .sup.4He concentrations in the quartz
(as gas is removed with circulating crustal fluids) while .sup.21Ne
remains trapped in the quartz. Because .sup.1He and .sup.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.
[0035] 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 .sup.4He/.sup.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.
.sup.4He/.sup.21Ne: 2.2.times.10.sup.7) 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 .sup.4He/.sup.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 .sup.4He and
.sup.21Ne concentrations and constructing a degassing/diffusion
profile is useful for identifying areas where extensive fluid flow
has occurred. Testing the retained .sup.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.
.sup.3He/.sup.4He: 0.51.0 Ra, and ASW .sup.21Ne/.sup.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 .sup.4He/.sup.21Ne .sub.profile (much
below production ratio), then we anticipate high fracture network
hydraulic conductivity (K.sub.FN) without prior loss of crustal
noble gases and hydrocarbons is anticipated. These locations would
define sweet spots because of their high K.sub.FN will enable fluid
extraction along the naturally occurring fracture networks.
Alternatively, if an area has a .sup.4He/.sup.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
[0036] 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 .sup.4He/.sup.21Ne and
.sup.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.
[0037] 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.
[0038] 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.sub.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.sub.H conditions, 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.
[0039] 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 (.about.20 .mu.m).
This capability allows microchemical spatial determination of
calcite vein chemistry, a proxy for pore fluid evolution through
fractures.
[0040] 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.
[0041] 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 .about.20 .mu.m
(20 .mu.m 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 (.about.10 .mu.m). 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
.about.10.times. enabling analysis of REEs and actinides (Th/U) and
providing sufficient spatial resolution to monitor the record of
fluid flow fluctuations throughout geological time.
[0042] 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.
[0043] 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.
[0044] 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
[0045] 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.
[0046] 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 (.about.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
[0047] 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 .mu.m resolution (spot size)
to produce a map .about.6 mm.times.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.
[0048] 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
[0049] 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.
[0050] 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 .about.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.
[0051] 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.
[0052] 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
[0053] 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.
[0054] 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 .sup.4He/2.sup.21Ne
production ratio is calculated in comparison to measured
.sup.4He/.sup.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 .sup.21Ne remains in the mineral phases,
the ratio of .sup.4He/.sup.21Ne relative to production will provide
evidence for the amount (volume) of fracturing and hydrocarbon loss
in the shale.
Summary
[0055] 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
[0056] 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.
* * * * *