Woodford Shale Research Articles

Macro- and micro-compression testing of shales

In this study, macro- and micro-geomechanical properties of shales were investigated at millimeter- and micrometer-scale using an example of the Woodford Shale. Geomechanical properties, such as uniaxial (unconfined) compressive strength and Young's modulus, were quantified at the millimeter-scale and compared with results from micro-compression testing experiments of FIB-SEM-nanofabricated micro-pillars. Size-scale and compositional/structural heterogeneity effect on elasto-plastic deformation and failure behavior of shales were investigated. Also, relationship between elemental/mineral composition and unconfined compressive strength and Young's modulus, at a micrometer-scale, was discussed. It was shown that geomechanical properties of shales are scale-dependent and are strongly affected by compositional/structural anisotropy. In particular, micro-compression testing experiments showed non-uniformly distributed compressive strength and Young's modulus within the investigated Woodford Shale rock samples. It was demonstrated, that geomechanical properties of shales, investigated at the micrometer-scale, tend to be affected by different minerals and/or pores, while the same properties, investigated at the millimeter-scale, are governed by different micro-facies (and/or micro-fractures) present within the rock. This shows that geomechanical properties of shales can be dramatically different depending on the scale of investigation and compositional/structural heterogeneity of these rocks, and therefore are not easily transferable across the scales.

The effect of thermal maturity on porosity development in the Upper Devonian –Lower Mississippian Woodford Shale, Permian Basin, US: Insights into the role of silica nanospheres and microcrystalline quartz on porosity preservation

Organic-matter pores are considered to be the dominant contributor to total porosity in many shale reservoirs, and consequently much attention has been paid to investigate the factors influencing their generation, especially thermal maturity. Recent studies have shown that in addition to maturation of organic matter, other diagenetic processes also play important roles in evolution of pore systems, including compaction, mineral dissolution, and quartz cementation. This study investigates the effect of thermal maturity on porosity development in the siliceous Woodford Shale by integrating multiple techniques including helium pycnometry, low pressure gas (N2) adsorption, mercury injection capillary pressure, and field emission scanning electron microscopy (SEM) analyses. We compare samples from two long cores from Woodford Shale at different levels of thermal maturity, one in the early oil window (average calculated Ro = 0.69%) and the other in the wet gas window (average calculated Ro = 1.34%).Porosity, pore size, type, and volume vary systematically with the thermal maturity increasing from early oil window to wet gas window. Porosity measured by helium pycnometry averages 4.1% for early oil window samples, and increased by approximately 50% for the wet gas window samples (average porosity =6.3%). Both pore size and pore throat size distributions display decreasing trends from early oil window to wet gas window. Petrographic examination of SEM images shows that pores developed between clay platelets dominate in the early oil window samples, and secondary organic-matter pores are the dominant pore type in wet gas window samples. Porosity shows no obvious correlation to TOC content in both oil window and gas window samples, but correlates positive to silica content, suggesting that silica content largely controls variations in porosity. Both silica nanospheres and microcrystalline quartz were observed and appear to be significant in preserving pores from compaction by forming rigid frameworks that prevent pores from collapsing. Generation of secondary organic-matter pores and preservation of primary pores by silica nanospheres account for the net porosity increase from early oil window to wet gas window.

Silica and Graphene Oxide Nanoparticle Formulation To Improve Thermal Stability and Inhibition Capabilities of Water-Based Drilling Fluid Applied to Woodford Shale

SummaryDrilling-fluid design for shale plays aims to deal with the lack of wellbore stability associated with fluid-invasion, shale-swelling, and cuttings-dispersion phenomena. Although oil-based mud can be used to achieve these goals, environmental and economic concerns limit its application. This research evaluates the potential of using silica (SiO2) nanoparticles (NPs) (SiO2-NPs) and graphene nanoplatelets (GNPs) as drilling-fluid additives in a single formulation to improve shale inhibition and long-term stability of water-based mud (WBM) against temperature effects. The design of the nanoparticle WBM (NP-WBM) followed a customized approach that selects the additives according to the characteristics of the reservoir. Characterization of Woodford shale was completed with X-ray diffraction (XRD), cation-exchange capacity (CEC), and scanning electron microscopy (SEM). The aqueous-stability test and ζ-potential measurements were used to assess the stability of the NPs. NP-WBM characterization included the analysis of the rheological properties measured with a rotational viscometer and the evaluation of the filtration trends at low-pressure/low-temperature (LP/LT) and high-pressure/high-temperature (HP/HT) conditions. In addition, dynamic aging was performed at temperatures up to 250°F for thermal-stability evaluation. Finally, chemical-interaction tests, such as cutting dispersion and bulk swelling, helped to analyze the effect of introducing NPs on the inhibition capabilities of the WBM. Conventional potassium chloride (KCl)/partially hydrolyzed polyacrylamide (PHPA) fluid was used for comparison purposes. The results of this investigation revealed that SiO2-NPs and GNPs acted synergistically with other additives to improve the filtration characteristics of the WBM, with only minor effects on the rheological properties. NPs exhibited high colloidal stability with ζ-potential values less than –30 mV, which warrants their dispersion within the WBM at an optimal concentration of 0.75 wt%. The high thermal conductivity of NPs played a key role in promoting a nearly flat trend in the cumulative filtrate for the NP-WBM at aged conditions, whereas KCl/PHPA suffered a dramatic increase. Also, NP-WBM preserved 43.97% of its initial cuttings-carrying capacity, whereas KCl/PHPA experienced a severe reduction of 95.24% at extreme conditions (250°F). Despite the high illite content of the Woodford shale, the NP-WBM exhibited superior inhibition properties that reduced cuttings erosion and swelling effect by 24.48 and 35.24%, respectively, compared with the KCl/PHPA fluid. Overall, this investigation supports the potential use of nanomaterials to enhance the inhibition capabilities and the long-term stability of WBM for unconventional shales, presenting an environmentally friendly alternative for harsher environments.

Experimental investigation of oil generation, retention, and expulsion within Type II kerogen-dominated marine shales: Insights from gold-tube nonhydrous pyrolysis of Barnett and Woodford Shales using miniature core plugs

Although oil retention has recently emerged as a key topic of unconventional-shale resource assessment, oil-retention and expulsion controls in organic-rich shales during thermal maturation remain poorly constrained. This study presents an experimental comparison of oil generation, retention, and expulsion in two immature, Type II kerogen-dominated marine shales, the Mississippian Barnett Shale and the Upper Devonian-Lower Mississippian Woodford Shale, mainly with respect to the combined effects of the organic macerals and rock fabric involved. In both cases, miniature core plugs drilled from the given samples were isothermally pyrolyzed at 130 to 425 °C for 72 h under a confining pressure of 68 MPa during gold-tube nonhydrous pyrolysis, corresponding to the thermally immature, early stage of the oil window, the main stage of the oil window, the late stage of the oil window, the main stage of oil cracking to wet gas, and the late stage of oil cracking. Yields of generated oil, retained oil, and expelled oil for the two studied samples were systematically quantified on the basis of mass-balance calculation of measured oil and gas yields, as well as Rock-Eval analyses on pyrolyzed subsamples.Through the six stages of petroleum formation investigated, the principal difference in oil generation was observed in the two studied samples, with approximately 38 to 68% greater yields of generated oil (equivalent to ~130 mg oil/g TOCo) for the Woodford Shale when it evolved into the main and late stages of the oil window. These elevated yields of generated oil for the Woodford Shale were compensated for by additional oil generation resulting from conversion of abundant Type I kerogen-like algae such as Tasmanites and Leiosphaeridia, which lag in onset and have a shorter period of petroleum generation upon maturation. As a response to the difference in oil generation, oil retention was found to be significantly enhanced for the Woodford Shale at equivalent stages, with 0.2 to 1.7 times more free oil (equivalent to 24–105 mg oil/g TOCo) and 0.7 to 3.9 times more sorbed oil (equivalent to 58–76 mg oil/g TOCo) being retained than that of the Barnett Shale, although this effect was not pronounced for oil expulsion. In contrast to the Barnett Shale, relatively low expelled oil yields and expulsion efficiencies both indicate highly limited oil expulsion in the Woodford Shale, implying that the Woodford Shale, whose mineral composition and lithofacies are similar to those of the Barnett Shale, may have a relatively low permeability rock fabric to prevent oil from being expelled. Furthermore, not only significantly higher oil-saturation index (OSI) values but also a wider range of maturity at which the oil crossover effect (OSI > 100 mg/g TOC) occurs is expected for the Woodford Shale when extrapolation to a geological setting occurs. These data suggest that the presence of abundant Type I kerogen-like algae and relatively low permeability rock fabric in the Woodford Shale are critical to significant oil retention during oil generation and expulsion, which jointly raise the possibility of potential commercial shale oil within Type II kerogen-dominated marine shales.

Water-Based Drilling Fluid Using Nanoparticles Proves Effective in Unconventional Shales

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19342, “Design and Evaluation of a Water-Based Drilling-Fluid Formulation Using SIO2 and Graphene Oxide Nanoparticles for Unconventional Shales,” by Jose Aramendiz, SPE, Abdulmohsin H. Imqam, SPE, and Sherif M. Fakher, SPE, Missouri University of Science and Technology, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. Traditionally, oil-based drilling fluids are preferable in drilling shale plays because of their negligible chemical interactions, but strict environmental regulations have motived the industry to design water-based muds (WBMs) capable of controlling shale/water interactions. Still, conventional additives in general are too large to plug shale microfractures and nanopores. Thus, nanoparticles, because of their size, shape, and other properties, can provide a solution for WBMs. This study focus on the design and evaluation of a customized water-based mud (NP-WBM) using silica oxide nanoparticles (SiO2-NPs) and graphene oxide nanoplatelets (GNPs). Experimental Description Experimental Materials. Conventional Drilling-Fluid Additives. The micro-size additives used in this work included bentonite to provide primary viscosity and xanthan gum to adjust the final rheological properties of the base fluid. Polyanionic cellulose low- viscosity and pregelled starch were included as conventional filtrate-loss additives. Graphite was used as conventional lost- circulation-material (LCM) additive. Potassium hydroxide was included as an alkalinity-control agent. Nanomaterials. SiO2-NPs were supplied in a white powder form. The SiO2-NPs are near-spherical with an approximate diameter ranging between 15 and 20 nm. The NPs were unmodified (bare surface) and nonporous with a density of 0.1 g/cm3, a specific surface area of 170–200 m2/g, and purity greater than 99.5 wt%. GNPs used in this study had a density of 0.13 g/cm3. The GNPs have a 2D structure with an average particle size ranging from 1.3 to 2.3 µm and a thickness of less than 3 nm. Shale Rock Properties. Woodford shale was used to test the effect of using NPs to enhance the inhibition capabilities of WBM. This rock is described as a late Devonian-Early Mississippian marine shale. In this study, shale samples of 1 in. in diameter and lengths between 0.5 to 2 in. were cored and stored in high-purity mineral oil to avoid property alterations. The rock contains 31.5% clay minerals (22.8% illite, 5.4% chlorite, and 3.3% kaolinite), 67% quartz, and 1.5% pyrite, indicating a high degree of brittleness as well as low water sensitivity. Fig.• 1 shows a sequence of scanning electron microscope (SEM) images in which Image A is equivalent to 7,000x magnification and Image B shows a 30,000x magnification with respect to the original sample size. The SEM images suggested a pore-size distribution between mesopores (2–50•nm) and macropores (greater than 50 nm) with an estimated median pore size of 112.84 nm. Therefore, the nanomaterials in this study have a scale matching that of the Woodford shale and can be used as theoretical bridging agents.

The effects of organic carbon content and thermal maturity on acoustic parameters in a black shale: Woodford Shale, Permian Basin, West Texas

We have derived relationships between organic carbon and acoustic properties in the Woodford Shale, an Upper Devonian organic-rich shale in the Permian Basin, Texas. Extensive core data enable us to relate measured total organic carbon (TOC) on core samples to gamma log response; in turn, gamma log-calculated TOC is compared with P-wave [Formula: see text] and S-wave [Formula: see text] velocities, density, and derivative properties including [Formula: see text], Young’s modulus, Poisson’s ratio, [Formula: see text], and [Formula: see text]. Because we sampled two wells at very different thermal maturity (early oil window and wet gas window), we can examine the effect of thermal maturity on these parameters. In both wells, [Formula: see text] and [Formula: see text] decrease with increasing TOC, exhibiting a rapid decrease from 0% to approximately 1.5% TOC, and a slower decrease above 1.5% TOC, similar to results from ultrasonic experiments on core samples, that we attribute to a shift from a mineral grain load-bearing to an organic matter load-bearing fabric. The [Formula: see text] decreases by 28% and [Formula: see text] by 20% over the range of 0.5%–12% TOC. [Formula: see text] and [Formula: see text] correlate more strongly to neutron porosity than to TOC in the less mature well, related to the development of a bitumen phase that is relatively soft and less dense and has greater impact on rock physical properties than kerogen; this effect disappears in the high-maturity well in which bitumen was further cracked to petroleum and physical properties of bitumen changed with increased aromatization. The effect of increased thermal maturity is to increase [Formula: see text] by approximately 12%, [Formula: see text] by 25%, and P-wave impedance by 12%. [Formula: see text] ratios decrease with increasing TOC, contrary to the behavior expected for the incorporation of a soft material into a rock. We suggest that the rock develops a horizontal planar fabric at lower TOC values that absorbs S-wave energy, counteracting the effect of the organic matter.

Geochemical characterization of the Upper Mississippian Goddard Formation, Noble Ranch Group, and related oils in the Anadarko Basin of Oklahoma

The Woodford Shale is anecdotally assumed to be the major source of oil for plays in the Anadarko Basin, including the stacked oil and condensate play in the southcentral Oklahoma oil province (SCOOP). However, there is little published geochemical work to confirm this assumption. This study set out to identify a characteristic geochemical fingerprint for the Goddard Formation, another potential source rock in the SCOOP, to determine if the Goddard is contributing to oil accumulations within the SCOOP. The Upper Mississippian Goddard Formation has been a target for unconventional production in SCOOP since 2012. Published geochemical interpretations for the Goddard Formation are still limited, and this study represents the first detailed oil–source rock correlation for the Goddard in the SCOOP area. The most characteristic geochemical signature of the Goddard extracts is a predominance of tricyclic terpanes relative to the hopanes in the mass-to-charge ratio 191 chromatogram, possibly related to enrichment via thermal stress or a unique source signature. Additional distinctive signatures were also identified for the triaromatic steroid hydrocarbons, sesquiterpenoids, and steranes. The biomarker fingerprints of SCOOP oils are nearly identical with those of the Goddard extracts in this study. Oils in the SCOOP, therefore, appear to originate from a Mississippian source, such as the Goddard rather than the Woodford. This observation demonstrates the value of oil–source rock correlation studies and suggests that there may be effective source rocks in the Anadarko Basin that have been overlooked in the past and should be re-evaluated in detail.

The significance of karst unconformities on overlying resource shales: Lessons learned from the Devonian Woodford Formation applied to the Permian Wolfcamp Shale

We have summarized the threefold significance of karst unconformity boundary: (1) The development of a sequence stratigraphic model for the Devonian Woodford Shale Formation is transferable to the Upper Wolfcamp in the Permian Basin, (2) demonstration of the more general application of that model beyond the Woodford to other resource shales, and (3) illustration of a modification of common sequence stratigraphy models specifically to unconventional resource shales. During early transgression, marine encroachment into the paleolows created anoxic, hypersaline marine “pockets” conducive to the preservation of organic matter. The result is deposition of thick, laterally discontinuous, organic-rich strata stratigraphically at or near the unconformity surface. This pattern of deposition and distribution of the organic-rich shale has been well-documented in the Devonian Woodford Shale and is applicable to other resource shales, in this case to the Permian Upper Wolfcamp Formation in the Central Basin Platform of the Permian Basin. The stratigraphy of the distribution of the Upper Wolfcamp on top of the Upper/Middle Wolfcamp Unconformity is similar to that of the Woodford, suggesting a similar origin and distribution. The resulting stratigraphy in both cases resembles that of the classical Exxon sea slug model except that rather than a single organic-rich deposit defining the condensed section and maximum flooding surface, a second organic-rich deposit occurs stratigraphically lower, at or near the unconformity surface. This theoretical summary can support the discovery of potential drillable target zones in the Woodford Shale and the Wolfcamp Shale.

Geochemical characterization of the Devonian-Mississippian Woodford Shale from the McAlister Cemetery Quarry, Criner Hills Uplift, Ardmore Basin, Oklahoma

Abstract It has been estimated that technically recoverable reserves from shales in the continental U.S. are believed to be approximately 24 billion barrels of oil (BBO) and 750 trillion cubic feet (Tcf) of gas. In Oklahoma the most important hydrocarbon source rock is the Woodford Shale, proposed to be the source of some 70% of the state's liquid hydrocarbon reserves. Such a regionally widespread source rock provides potential for both academic study and industrial opportunities. In this study representative samples of the Woodford Shale from the McAlister Quarry outcrop have been characterized by a variety of geochemical techniques. TOC values range from 0.07 to 15.6 wt% and, based on Rock-Eval Pyrolysis, most of the samples plot within the Type I/II kerogen range, with several low TOC samples plotting in the Type III kerogen range. TOC and biomarker parameters, suggests that two sections of the Upper Woodford are immature paleosols, having been subaerially exposed due to abrupt episodes of sea level fall during the Late Devonian. Evidence for these zones of paleoweathering includes highly depleted TOC, increased oxygen index (OI) values, loss of n-alkanes, decreases in the aryl isoprenoid ratio (AIR), sesquiterpenoids, cheilanthanes, hopanoids, and decreases in many of the polycyclic aromatic hydrocarbons (PAHs). The values of several paleoenvironmental proxies for samples immediately following the Frasnian-Famennian (F–F) Stage extinction boundary within the Upper Woodford suggests that a large influx of weathered terrigenous material occurred at that time. The presence of pyrogenic compounds implies that paleowildfires were widespread throughout the Middle and Late Devonian in the North American midcontinent. It is possible that these influxes of weathered terrestrial organic material stimulated algal blooms that led to the anoxic water column conditions often attributed to the F–F Stage extinction event. Investigation of the stratigraphic framework of these source rocks assists in evaluating their potential as hydrocarbon producers and/or unconventional reservoirs. Integration of geochemical data adds another powerful dimension to this approach. It has been proposed that the Woodford Shale was deposited during a 2nd order depositional sequence. The lower member represented the transgressive systems tract (TST), the Upper member the highstand systems tract (HST), and the Middle member bridging the transition between the two. Numerous 3rd order parasequences were also identified as being part of the overall 2nd order sequence and could be correlated to the Devonian sea level curve. The major objectives of the study were: While this study focuses locally on the McAlister Quarry samples, it is also of regional importance. The Woodford is a prolific source rock throughout the Anadarko Basin and has been the subject of extensive exploration and production efforts, particularly in the past decade with the development of horizontal drilling and hydrofracturing techniques. Continued investigation of the heterogeneity of the shale will greatly enhance the ability to predict more productive facies within the formation throughout the basin.

Deep resistivity \u201cturnover\u201d effect at oil generation \u201cpeak\u201d in the Woodford Shale, Anadarko Basin, USA

The Devonian Woodford Shale in the Anadarko Basin is a highly organic, hydrocarbon source rock. Accurate values of vitrinite reflectance (Ro) present in the Woodford Shale penetrated by 52 control wells were measured directly. These vitrinite reflectance values, when plotted against borehole resistivity for the middle member of the Woodford Shale in the wells, display a rarely reported finding that deep resistivity readings decrease as Ro increases when Ro is greater than 0.90%. This phenomenon may be attributed to that aromatic and resin compounds containing conjugated pi bonds generated within source rocks are more electrically conductive than aliphatic compounds. And aromatic and resin fractions were generated more than aliphatic fraction when source rock maturity further increases beyond oil peak. The finding of the relationship between deep resistivity and Ro may re-investigate the previously found linear relationship between source rock formation and aid to unconventional play exploration.

Geochemical evaluation of oil and gas samples from the Upper Devonian and Mississippian reservoirs Southern Anadarko Basin Oklahoma and its implication for the Woodford Shale unconventional play

Abstract The Woodford Shale, Sycamore, and Goddard formations have become important liquid rich unconventional resource play targets. Most petroleum experts believe the mature Woodford Shale is responsible for much of the southern Anadarko conventional and unconventional petroleum production with notable exceptions. This paper will focus on the well head oil and gas samples from the South Central Oklahoma Oil Province (SCOOP) area Woodford Shale and the younger Mississippian reservoirs. The purpose of this paper is to characterize the SCOOP area unconventional resource play using the produced petroleum. Discrepancies between produced oil and gas geochemistry, rock maturity, and production characteristics presents an interesting conundrum. The produced volatile oils contain lower boiling point compounds (C6–C8) that indicate a high maturity product from the Woodford Shale source, whereas the high molecular weight fraction (C15+ biomarkers) suggests a middle mature product from the Woodford Shale source. The produced gas chemistry suggests a low to middle mature product using published gas plots. Lastly, the production Gas Oil Ratio (GOR) and well head fluid gravities are typical of a gas-condensate. There is no simple unified petroleum system process to explain all these observations. There could be a combination of factors resulting in this conundrum such as mixing of multiple charges from both local and off-structure sources, phase separation as a result of production, or well head sampling/storage issues. At present it may be difficult to fully explain the current results, however we do believe the geochemistry and production results demonstrate a significant off-structure contribution. A simple petroleum systems model based on source rock organic matter type and maturity does not always correctly predict production or ultimate recovery.

Analysis and prediction of stimulated reservoir volumes through hydraulic fracturing: Examples from western Arkoma Basin

Geologic models built from well logs and natural fracture (NF) parameters obtained at shale and carbonate outcrops/quarries were employed in understand artificial hydraulic fracture (HF) propagation and stimulated reservoir volume (SRV) geometries. We applied field HF treatment parameters from an Arkoma Basin well, located 20–25 miles (32–40 km) east of the studied quarries. We matched the microseismic cloud (MC) geometries of three field stages, followed by sensitivity analyses of various HF treatment and reservoir parameters.Geometry matches reveal that the average NF permeability in the Viola Group Limestone is nearly eight times that in the Woodford Shale. The sensitivity analyses (forward modeling) disclosed several likely outcomes. First, a minor (5 × 10−6) increase in the minimum horizontal tectonic strain and ensuing increase in the minimum horizontal stress resulted in a sizeable transformation of the SRV geometry. Second, pumping at a higher net pressure (ISIP increased from 6500 to 7000 psi) diminished the stimulation volume and opened more previously non-dilatable NFs closer to the wellbore. Higher net pressure also triggered more stimulation downward and out of the target zone in the studied area. Third, halving the number of NFs and doubling their final storage apertures significantly magnified the fracturing-fluid efficiency (i.e., lowered leak off into NFs) in areas where it was restricted from flowing through non-dilatable NFs. Additionally, this modification caused greater lateral growth and comparatively large downward (out of target zone) growth of the HF and NF reactivation front, lowering the effectiveness of the HF job. However, halving the number of NFs and doubling their final storage apertures did not result in a substantial change in the SRV geometry upon allowing fluid flow through non-dilatable NFs. Fourth, altering the well-landing depth within the Woodford Shale did not result in a major shift in the overall stimulation geometry or volume. Most importantly, the simulated hydraulic fractures emanating from the wellbore do not span the entire recorded microseismic cloud length and height.

Salinity, pH, and temperature controls on fracture mechanical properties of three shales and their implications for fracture growth in chemically reactive fluid environments

Using the double torsion method, we investigated the fracture mechanical properties of clay-rich Woodford and Mancos Shales, and carbonate-rich Marcellus Shale under conditions of varying fluid salinity, pH, and temperature. Both fracture toughness and subcritical fracture growth properties for clay-rich Woodford and Mancos Shales are sensitive to fluid salinity but not sensitive to pH. With increasing salinity, mean fracture toughness increased up to 34% and 39% for Woodford and Mancos Shale, respectively, and mean subcritical fracture growth index increased up to 99% for Woodford Shale. In contrast, fracture toughness for carbonate-rich Marcellus Shale is unaffected by fluid chemistry, but subcritical fracture growth index increases with increasing pH. Subcritical fracture growth index is reduced by 51% with a decrease in pH from 7 to 1.2. Clay–water interaction is identified as the mechanism for enhanced subcritical fracture growth in clay-rich Woodford and Mancos Shales while enhanced calcite dissolution is accountable for the positive correlation between pH and subcritical fracture growth index in carbonate-rich Marcellus Shale. Increasing solution temperature from 23 °C to 63 °C shifts the K–V curves toward lower stress intensity and amplifies the salinity dependence in the shift of the K–V curves for Woodford Shale. The increase in subcritical fracture growth rate at elevated temperature observed in both clay-rich and carbonate-rich shales is interpreted to reflect faster diffusion rates of fluid from the propagating fracture into the matrix at elevated temperature. Our results emphasize the dependence of critical and subcritical fracture behavior on fluid chemical environment with implications for hydraulic fracture growth in shale reservoirs, and for caprock integrity of wastewater and CO2 storage reservoirs. In these applications, fluid chemistry can both strengthen and weaken caprocks depending on caprock lithology and induced changes in formation water chemistry.

XRF (X-ray fluorescence) applied to characterization of unconventional Woodford Shale (Devonian, U.S.A.) lateral well heterogeneity

X-ray fluorescence (XRF) was applied to measuring drill cuttings in order to characterize reservoir heterogeneity along a horizontal wellbore that landed in the organic-rich Woodford Shale. The measured XRF data profile which is composed of different paleoenvironmental and sedimentary element proxies were interpreted along with microseismic data distribution patterns from hydraulic fracturing. Three representative microseismic event distribution patterns were selected as demonstrations for reservoir heterogeneity’s impact on hydraulic fracturing efficiency, reflected by the corresponding variation in the XRF profile. This case study indicates that heterogeneity is a non-negligible factor in unconventional shale reservoirs and controls the efficiency of hydraulic fracturing. XRF is not restricted to conduct vertical scale chemostratigraphic characterization on core and outcrop, but also applicable for lateral well heterogeneity characterization near wellbore, which helps optimizing hydraulic fracturing design and ultimately reducing the risk of production failure.

Palaeomagnetic dating of hydrothermal alteration in the Woodford Shale, Oklahoma, USA

AbstractAn oriented Woodford Shale core from the eastern Ardmore Basin was sampled to test if the shale was an open or closed system to hydrothermal fluids, and to determine the timing of alteration. Mineralized fractures are ubiquitous in the core, and the shale exhibits a complex paragenesis with multiple hydrothermal minerals, including biotite, magnesite, norsethite, gorceixite and potassium feldspar present in and around the fractures. These minerals suggest that the Woodford Shale was an open system during part of its diagenetic history. Vitrinite reflectance (Ro) measurements indicate values of ∼1.81 % (∼230 °C). Palaeomagnetic analysis reveals a characteristic remanent magnetization (ChRM) with south-southeasterly declinations and shallow inclinations that resides in magnetite. This ChRM is interpreted to be either a chemical remanent magnetization (CRM) or a thermochemical remanent magnetization (TCRM) that was acquired at 245 ± 10 Ma during Late Permian time based on the pole position (51.0° N, 115.6° E). Because the palaeomagnetic specimens show evidence of extensive hydrothermal alteration, the CRM/TCRM is interpreted to date the migration of hydrothermal fluids through the shale. The agreement in timing with other studies that report hydrothermal alteration in southern Oklahoma and the Ouachita Mountains in Late Permian time, suggest that there were post-collisional fluid-flow events which accessed reservoirs of warm fluids.

Light Hydrocarbon Geochemistry: Insight into Mississippian Crude Oil Sources from the Anadarko Basin, Oklahoma, USA

The Mississippian limestone is a prolific hydrocarbon play in the northern region of Oklahoma and the southern part of Kansas. The Mississippian reservoirs feature variations in produced fluid chemistry usually explained by different possible source rocks. Such chemical variations are regularly obtained from bulk, molecular, and isotopic characteristics. In this study, we present a new geochemical investigation of gasoline range hydrocarbons, biomarkers, phenols, and diamondoids in crude oils produced from Mississippian carbonate and Woodford Shale formations. A set of oil samples was examined for composition using high-performance gas-chromatography and mass-spectrometry techniques. The result shows a distinct geochemical fingerprint reflected in biomarkers such as the abundance of extended tricyclic terpanes, together with heptane star diagrams, and diamantane isomeric distributions. Such compounds are indicative of the organic matter sources and stages of thermal maturity. Phenolic compounds varied dramatically based on geographic location, with some oil samples being depleted of phenols, while others are intact. Based on crude oil compositions, two possible source rocks were identified including the Woodford Shale and Mississippian mudrocks, with a variable degree of mixing reported. Variations in phenol concentrations reflect reservoir fluid dynamic and water interactions, in which oils with intact phenols are least affected by water-washing conversely and crude oils depleted in phenols attributed to reservoir water-washing. These geochemical parameters shed light into petroleum migration within Devonian-Mississippian petroleum systems and mitigate geological risk in exploring and developing petroleum reservoirs.

Water-based drilling fluid formulation using silica and graphene nanoparticles for unconventional shale applications

The development of unconventional shales started a new era in the oil and gas industry. These reservoirs represent a challenge to conventional drilling fluids since the fluid invasion, cutting dispersion, or shale swelling can lead to wellbore instability problems. Although oil-based drilling fluids (OBM) are capable to control these issues, environmental and economic concerns limit its application. Recently, nanoparticles (NPs) have introduced a new perspective in drilling fluid technology, offering a unique alternative to improve the performance of water-based drilling fluids (WBM) for shale applications. This research evaluates the potential of using silica nanoparticles (SiO2-NPs) and graphene nanoplatelets (GNPs) to formulate a nanoparticle water-based drilling fluid (NP-WBM). The study considers a bottom-up approach, selecting the NPs based on the Woodford Shale's characterization and focuses its primary objective in finding the most suitable NP combination to enhance the rheological, filtration and inhibition properties of the customized NP-WBM. The shale characterization included X-ray diffraction (XRD), cation exchange capacity (CEC), and scanning electron microscopy (SEM). The zeta-potential technique was used to assess the stability of the NPs. The NP-WBM was evaluated by means of API filtration test (LTLP), high-temperature/high-pressure (HTHP) filtration test and rheological measurements using a conventional viscometer. Finally, the inhibition capability of the NP-WBM was tested against the Woodford shale through immersion and cutting dispersion tests. NPs' characterization revealed that both additives can provide stable suspensions with zeta-potential values < −30 mV. A total NP concentration of 0.75 wt% (0.5 wt% of SiO2-NPs and 0.25 wt% of GNPs) yielded to the maximum reduction in filtrate volume at both, LTLP and HTHP conditions. The less permeable filter cake resulted in no spurt-losses, supporting the NPs' plugging effect. A strong cross-linked network created between the NPs and the conventional additives increased the cutting carrying capacity of the NP-WBM with slight effects on its plastic viscosity (PV). The immersion test carried out in water revealed that illitic shales might experience micro-fractures along the bedding planes in the absence of bridging materials. Contrarily, the NP-WBM provided an adequate plugging network between grain boundaries, resulting in no micro-fractures, and the reduction of the cutting erosion by 35.61%. Overall, this study highlights the capability of nanomaterials to extend the reliability of WBM to harsher environments while seeking an eco-friendlier alternative.

Molecular and intramolecular isotope geochemistry of natural gases from the Woodford Shale, Arkoma Basin, Oklahoma

Abstract A combined bulk and position-specific isotope study was conducted on natural gases collected from an unconventional gas field in the Late-Devonian to Early Mississippian Woodford Shale in the southwestern Arkoma Basin in Oklahoma. The set of natural gases records a hitherto underreported case, where gases become wetter with decreasing isotope compositions in an early stage of maturation. A first dataset of position-specific isotope compositions of propane with demonstrated accuracy and precision show that while the bulk δ2H values of propane increased by 30‰ with maturity, position-specific hydrogen isotope deviations of propane (Δ2-1) increased by 80‰. Position-specific δ2H values showed that δ2H values of the central H in propane increased by 70‰ with maturity, but those of terminal H in propane remained constant. This contrasting behavior could have resulted from the hydrogen isotope exchange between shale water and propane with a half-time of the center H, varying strongly from ∼310 to ∼6 m.y. at ∼140–185 °C. On the other hand, bulk and position-specific δ13C values of propane remain nearly constant during the maturation. Position-specific isotope compositions of propane at the highest maturity yield an equilibrium temperature that is consistent with its maturity, thus possibly serving as single-compound isotope geothermometry.

Oil families and inferred source rocks of the Woodford–Mississippian tight oil play in northcentral Oklahoma

Twenty-four oils produced from the Woodford Shale and overlying Mississippian strata in central Oklahoma were characterized geochemically to determine their possible source(s). The 168 core samples from the Woodford and Mississippian sections of 14 wells in central Oklahoma were initially characterized by total organic carbon (TOC), Rock-Eval, and vitrinite reflectance, and select samples (TOC > 1.0 wt. %) were subjected to biomarker analyses to characterize source input, depositional environment, maturity, and oil-to-source rock correlations. Thermal maturity parameters indicate the Woodford Shale is immature to marginally mature in Payne County, Oklahoma, and shows a progressive increase in maturity toward the southwest. Close to the Nemaha uplift, the Woodford is in the main stage of oil generation. It is proposed that the oils in this area have three possible origins: (1) Oils produced from the Woodford and overlying Mississippian strata have similar fingerprints, suggesting the Woodford Shale and overlying Mississippian strata are in communication; (2) oils produced near the Nemaha uplift (Logan and western Payne Counties) were sourced from the Woodford but had a significant Mississippian source contribution based on source-specific biomarkers; (3) oils east of the Cherokee platform (eastcentral Payne County) share strong Woodford source characteristics, and they were not generated in situ from the immature Woodford Shale but probably migrated from the Woodford Shale in the deeper part of the Anadarko Basin in southern Oklahoma. These results are consistent with the findings that indicate abundant marine coarse-grained biogenic silica (radiolarian-rich) chert facies found in eastcentral Payne County may contribute to good reservoir petrophysical properties, suggesting the Woodford Shale may not be a source in this area but simply a tight reservoir.

Regional appraisal of shale resource potential within the Permian, Anadarko and Arkoma basins: how does the Alpine High stack up?

Abstract The Alpine High on the southwestern fringe of the Delaware sub-basin in the Permian Basin (Figure 1) is an emerging unconventional fairway with shale resource potential. In 2016, an operator drilled a series of exploration and appraisal wells on the Alpine High, targeting the stacked resource interval comprising the Woodford, Barnett and Wolfcamp shale plays (Apache Corporation, 2017). All three plays have been successfully developed elsewhere in Texas and/or Oklahoma, but were previously untested on the Alpine High. There are more than 4500 wells targeting the Woodford in the Anadarko and Arkoma basins, more than 24,000 wells targeting the Barnett shale in the Fort Worth Basin and more than 16,000 wells targeting the Wolfcamp in the Delaware and Midland sub-basins of the Permian Basin (Rystad Energy, 2018). The distribution of the wells targeting these shale plays is shown in Figure 1. Initial well results and production tests on the Alpine High are reported to have been promising (Apache Corporation, 2017) and, as a result, the Alpine High is regarded as a highly prospective, but largely untested, unconventional fairway.