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Recovery efficiency (RE) is a poorly constrained parameter with respect to unconventional resource development. However, the increasing volume and quality of data related to Marcellus development in West Virginia provide an opportunity to assess this parameter. In this report, we develop a map of estimated ultimate recovery (EUR) per square mile (mi2) for the Marcellus Play in West Virginia and compare that map to published estimates of both technically recoverable resources (TRR) and original gas-in-place resources (GIP). These comparisons reveal that Marcellus wells appear capable of producing significantly more gas than previously estimated and, throughout large areas of the State, more gas than has been assessed to be in place. While explanations for this observation likely include both potential overestimation of EUR and underestimation of GIP, our review indicates that a primary source of the discrepancy is overly-conservative GIP calculations. New GIP calculations have been conducted for a range of wells that appear to account for the bulk of the "excess gas" by including GIP volumes from bounding formations determined likely to be part of the larger Marcellus Reservoir Unit (MRU). In northeastern West Virginia, the MRU includes both the Marcellus Formation and the lower 300 ft of the Mahantango Formation. In northwestern West Virginia, units up to the Cashaqua Shale Member of the Sonyea Formation are included in the MRU. These new GIP/mi2 values, when compared with our estimates of TRR/mi2, indicate that ultimate RE for ongoing development generally ranges between 20 to 60%.
Our approach to estimate TRR/mi2 is based on identification of 166 Marcellus "development sites" in northern West Virginia. Each development site was selected to consist of multiple horizontal wells that were drilled as a coordinated activity at a common spacing over a short period of time by a single operator. Sites and wells also were selected to maximize both the relevance (post 2012 vintage wells where possible) and reliability (more than 18 months production history) of the EUR forecasts. Site area was determined as the product of cumulative lateral length and well spacing. The cumulative EURs for all wells in each site were estimated (using two independent sources for EUR estimation) and those sums were divided by the area to obtain a single point estimate of TRR/mi2. Our review indicates that Marcellus Play resource assessments tend to be overly conservative. This analysis shows the value of focusing on the most relevant production data and using those data as a ground truth check on resource assessments.
Abstract In self-sourced low-permeability reservoirs the efficiency at the interaction between the mudstone matrix and fractures is a key control on well performance. Commonly, the more heterogeneous (interbedded) the reservoir the more complex fracture network is naturally developed or can be achieved during stimulation. In this study, using observations from two different unconventional shale units, we demonstrate that mudstone stratigraphic heterogeneities are scale dependent, and thus capturing their expression at different scales is key to understanding the level to which facies arrangements can affect important petrophysical, geochemical and geomechanical properties. Characteristics from the Duvernay Formation in Alberta-Canada and the Woodford Shale in Oklahoma-USA were compared in this study; both units are Late Devonian in age and are organic-rich prolific reservoirs. Lithologies in the Duvernay mostly vary according to changes in carbonate content, whereas in the Woodford changes are according to quartz content. However, in both cases a systematic alternation of two distinct rock types is evident at the cm-scale in outcrops and cores: organic-rich and calcite-rich facies for the Duvernay, and mudstones and chert facies for the Woodford. By combining high-resolution geochemical and geomechanical data, two distinct trends were evident for both units, and illustrate that variations in organic contents, mineralogy and relative hardness can be grouped by the two main rock types for each unit. In the Duvernay, the calcite-rich facies occur as low-TOC beds, at the microscale these are dominated by pore-filling calcite cements. In the Woodford, chert beds present the lower TOC content and their microfabric consists of microcrystalline aggregates of biogenic/authigenic quartz. In both units, the higher porosity values correlate with the high-TOC beds with abundant interparticle porosity. As for mechanical hardness and natural fractures, the higher calcite and quartz contents positively correlate with stiffer beds which generally are more brittle and have more natural fractures. The interbedded character between high-TOC and low-TOC beds is common for both units but at different frequencies and thickness. Capturing the degree of interbedding using a heterogeneity index suggests that reservoir behavior might be depicted as a multi-layered model in which properties are affected by the thickness, permeability, storage capacity, stiffness and fracture frequency of each bed. Although sometimes neglected, the study of fine-scale variations in reservoir properties can provide significant criteria for the selection of optimal horizontal landing zones.
Slatt, Roger M. (University of Oklahoma) | Galvis-Portillo, Henry (University of Oklahoma, The University of Calgary) | Becerra-Rondon, Daniella (University of Oklahoma, The University of Calgary) | Ekwunife, Ifunanya C. (University of Oklahoma, Baker Hughes, a GE company) | Brito, Richard (University of Oklahoma, Newfield Exploration Co.) | Zhang, Jing (University of Oklahoma) | Molinares, Carlos (University of Oklahoma) | Torres, Emilio (University of Oklahoma) | Duarte, David (University of Oklahoma) | Milad, Benmadi (University of Oklahoma)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Outcrop and subsurface cores are sampled for a variety of low-cost rock analyses, including: Chemical (XRF) and mineralogical (XRF, XRD, petrography) composition and stratification, hardness (Leeb rebound hardness tester); microfabric, porosity and permeability (SEM); organic content (TOC, RockEval, biomarkers); fractures/folds (visual observations); 2D and 3D seismic volumes, and biostratigraphy (if biota are present) This data set can then be combined to determine depositional environment, measure long-/short-distance lateral continuity of strata away from the wellbore, determine fracturability (brittle vs. ductile rock), categorize reservoir quality (porosity and permeability) and predict the potential for fractures to hold open or to close on proppant. These features provide important screening criteria for geoscientists and decision-makers. An example of the analysis, utility and application of these techniques is provided of the Woodford Formation, which is currently the 3rd most active hydrocarbon play in the U.S. Introduction "Over the past three years, more than 100 oil and gas companies in North America.......... have filed for bankruptcy……" (Jenkins (SPE Reservoir Study Group lunch, Nov. 3, 2017).
The goal of this study is to define a uniform organic matter (OM) correlation for North American shales with fundamental petrophysical parameters taken into consideration. Several log based methods to calculate volume of OM have been developed over the past several decades. This paper compares three of the most common OM correlation techniques in twelve different North American shales. The techniques evaluated are a density based approach similar to Schmoker's relation, a gamma ray based approach similar to that used by Boyce and Schmoker, and Passey's ΔLogR method. It has been hypothesized that thermal maturity, kerogen type, lithofacies, redox potential, sedimentation rate, age and organic source will have a large effect on the shape of the correlations. However, the data shows that despite both geologic and geographic differences, the apparent slope, intercept and LOM values are very similar. In fact, one correlation can often be used in the absence of any additional data.
The Leco and Rock-Eval6® total organic carbon (TOC) measurements in this paper are taken from a core consortium for North American shales and other public core data. For LECO TOC, the samples have been digested in HCL to remove inorganic carbon and in some cases run through a soxhlet extraction if oil based mud was present. For Rock-Eval6 TOC, the samples have been submitted to pyrolysis and oxidation using a discrete temperature program. Log data (density/gamma ray) was used to create correlations because it is more representative of subsurface conditions and less prone to alteration, although there are issues with vertical resolution and depth corrections. Further the log data was normalized to remove any bias based on logging vendor and vintage. All values in this paper have been converted from weight% TOC to volume% OM.
Summary The focus of this work was to obtain reliable kerogen and solid bitumen density data and to establish robust descriptions of the organic matter responsible for liquid hydrocarbon generation in the Devonian organic-rich Duvernay shale. Five wells were selected from Alberta, Canada, for investigation of the organic matter (OM) properties, particularly its density. A comprehensive workflow was designed and executed that includes the selection of representative samples for detailed evaluation of possible vertical heterogeneity of organic facies and on which to perform separation of organic matter and density measurements. The major goals were to understand the various controls on organic matter types (macerals), kerogen density, and to develop a predictive tool for calibrating density to maturity and organic matter distribution. We showed that the sole utilization of Rock-Eval pyrolysis data as the maturity proxy, following published correlations, may lead to substantial overestimation of the actual maturity, as compared to other maturity proxies. We also demonstrated that the organic petrology and the vitrinite reflectance equivalent (VRE) values derived from solid bitumen reflectance and published correlations (Jacob, 1985; Schoenherr et al., 2007) much more closely reflect the maturity of actual fluids being produced in the subject area. The rocks studied vary from 2 to10% in total organic carbon (TOC) content, with VRE values of 1 to 1.2%, and are producing light fluids that correlate with the middle upper maturity range. Geochemical markers corroborate the petrographic maturity estimations observed. The organic matter is dominated by two main constituents—amorphous organic matter (AOM) and solid bitumen—with traces of other liptinites. Kerogen density varies from 1.25 to 1.35 g/cm3, depending on the influence of solid bitumen on overall composition; however, the average density of the kerogen in this area, and taking into consideration the maturity range, was established at 1.28 +/- 0.3 g/cm3. We have also captured kerogen density variation driven by maturity, with one well showing consistently lower-density kerogen than the other four wells. Measured kerogen densities were subsequently used in advanced petrophysical analysis, with an effort to distinguish between bitumen and kerogen volumes and to determine the porosity associated with each OM constituent. While this paper uses the Duvernay shale as an example, the conclusions have universal application to all unconventional resource plays. In addition, our work can be used to better understand OM variability and its control on the type of fluids generated and produced, and it provides measured rather than assumed kerogen properties as direct input to formation evaluation and modeling software.
Abstract Magnetic Susceptibility (MS) is an indicator of the concentration of magnetic particles in rocks. In pre-Quaternary sediments the magnetic susceptibility is often sourced in either Fe-rich clays (chlorites etc), or Fe-oxides (magnetite or hematite), and often shows a dilution-relationship with calcite which has a small negative MS. Mudrocks lend themselves readily to MS analyses, since MS often responds to the gross lithological variations, with a superimposed provenance or sometimes diagenetic signature. Two applications for magnetic susceptibility in shale resource plays will be considered in this paper: a) stratigraphic correlation and b) paleoflow determination. The first is carried out using data acquired from either small samples, measured in the laboratory, or by direct analysis of cores using a hand held MS meter. Paleoflow determinations utilise directional variation in magnetic susceptibility (Anisotropy of Magnetic Susceptibility- AMS) to make an interpretation of grain orientation. Re-orientation of the core is required to convert the preferred grain orientation into geographic coordinates. Direct measurement of core using a handheld magnetic susceptibility meter enables large, high resolution (5-10 cm spacing) datasets to be gathered rapidly. Typically, these data show marked cyclicity, which in a Miocene carbonate sequence from Mallorca will be shown to be controlled by sea level fluctuations. Furthermore, because high resolution measurements are available, parasequences can be imaged in the magnetic susceptibility data. Changes in the symmetry of the transgressive - regressive portions of parasequences allow variations in "stacking patterns" to be compiled, thereby providing input into sequence stratigraphic interpretations. This aspect will be demonstrated using core analysis from a US shale play. AMS measurements provide a rapid and precise determination of the three-dimensional orientation of grains in samples. When dealing with a shale play, any such grain-orientation data are difficult to determine using visual analyses. The AMS expresses the bedding-foliation, and the lineation (i.e. paleoflow direction) within the bedding plane. Hence, it can be used to infer structural information, as well as with-bedding preferred grain-orientation information. Here, we will show initial results from a European shale play that suggests AMS has the potential to be a powerful tool in paleoflow and sediment fabric analysis of mudrocks.
Summary The nanoscale porosities in shales have been widely studied by industry with emphasis on organo-porosity and its significant to migration (and generation) of hydrocarbons. However, not much attention is paid to the next scale up, which would include burrows to provide potential migration pathways. The original intent of the work was to evaluate whether burrows were sufficiently abundant and interconnected to provide permeability pathways at the scale of the burrows. The Woodford Shale in the Anadarko basin, Oklahoma has been one of the major unconventional plays in the United States for nearly a decade. This research has fully utilized ultra-high-resolution (625 micron increment per slice) and advanced 3-D Micro-CT scan technology to quantitatively describe and analyze the ichnofacies and microfacies in selected Woodford cores. The ichnofacies in the Woodford shale cores have been categorized into short and long Chondrites, Paleodictyon, Thalassinoides and Planolites. The 3-D geometries, abundance, and diversity of ichnofacies have been quantitatively described. Bioturbation Index (BI) was calculated from the sum of the abundance of all ichnofacies in each stratigraphic interval. The BI was then compared with XRF, XRD and geochemistry data to relate ichnofacies, paleo-redox environment, and sediment provenance. The stratigraphic distributions of these properties were found to be related to sea-level fluctuation, biostratigraphy (from Conodonts), and sequence stratigraphy. Our results indicate that bioturbation and bio-activities are more common in Woodford shale than previously thought. They are not sufficiently abundant and vertically interconnected to provide permeability pathways at the scale of the burrows. However, in some core sections, the horizontal burrows are sufficiently connected within thin laminae. There is not much in the way of vertical connectivity of burrows, but along what appear to be some bedding planes there are enough touching burrows to make a permeability pathway. Although burrows frequently develop in highstand systems tracts, they also occur in presumably anoxic environments conducive to preservation of high TOC content and biogenic quartz. These relationships can aid in targeting the best horizontal landing zones in the Woodford shale.
Summary Calcite forms variable proportions of source-rock reservoirs ("shale plays"). Although calcite content can be quantified via petrophysical analyses, XRD, XRF and other techniques, the amount of calcite, by itself, is not enough information to predict the likely importance of these minerals for reservoir and completions quality. Four principle types of calcite can be recognized:Pelagic components, mostly foraminifera and coccoliths, form a large component of the Eagle Ford and Niobrara but other types of pelagic carbonates (e.g., tentaculitids) are common in Paleozoic source-rock plays such as the Marcellus, Carbonate "event beds" (turbidites, storm deposits, etc.) are present in the Avalon, Barnett, Vaca Muerta and other plays, In situ benthic carbonates (bivalves, corals) are present in some plays (e.g., Eagle Ford, Marcellus), and Diagenetic calcites (pore filling cements, fracture fills, replacements, etc.) are present to varying degrees in perhaps most source-rock plays. Detailed core descriptions and petrographic observations are critical for assessing the origin of the calcite. Similar concepts apply to other mineral and organic components of mudstones.
Summary Recent developments in shale technology have revolutionized oil and gas production in the United States. However, there is still a strong requirement for assessing the prospectivity of emerging shale plays, both in the United States and internationally. This paper is an attempt to generalize the results from three major US shale plays: Bakken, Eagle Ford and Niobrara, and to use these to assess the prospectivity of emerging shale plays elsewhere. Porosity, permeability, total organic carbon (TOC) content, thickness, brittleness, composition and maturity of shales are all important in the generation and retention of hydrocarbons. Factors such as depositional environment, uplift and burial, proximity to porous media, presence of natural factures, and reservoir pressure distribution over geologic time all also affect the ability of shales to retain hydrocarbons and be economically productive reservoirs.
Abstract Shale gas and tight oil from unconventional deposits is now a very attractive target in the UnitedStates. Thanks to the technological revolution brought about by the combined use of horizontal drilling and hydraulic fracturing the US is now exploiting shale gas and tight oil formations in record numbers. The success of these exploitations were indicated in the most recent report released by the International Energy Agency (IEA) announcing the United States will overtake Russia as the biggest gas producer by 2015 and will become the largest oil producer by 2017. The Energy Information Administration (EIA) estimates that the US has more than 750 trillion cubicfeet of technically recoverable shale gas, and estimates that there could be in excess of 24 billion barrels of on-shore technically recoverable tight oil resources. Already the Barnett Shale play in Texas produces 6 percent of all natural gas produced in the United States, and Leonardo Maugeri predicts the natural endowment of the initial Bakken/Three Forks American shale play could become a big Persian Gulf producing country within the United States on its own. The risks concerning shale plays are the effects of hydraulic fracturing on the environment, whichisperceived as contributing to both land and water contamination among other health and community impacts. The pros and cons of this aspect will be scrutinized in this paper. The analysis in this paper will examine the prospects of the major shale plays in the US and the technology being used to enhance the potential opportunities this boom has for American jobs and the economy. This paper will also review a series of federal laws governing most environmental aspects of shale gas and tight oil development, and the full range of environmental and health risks this potentialshale revolution may hold for the United States.