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Kazak, Ekaterina S. (Lomonosov Moscow State University) | Kazak, Andrey V. (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Bilek, Felix (Dresden Groundwater Research Centre)
Summary In this study, we aim to develop a new integrated solution for determining the formation water content and salinity for petrophysical characterization. The workflow includes three core components: the evaporation method (EM) with isotopic analysis, analysis of aqueous extracts, and cation exchange capacity (CEC) study. The EM serves to quickly and accurately measure the contents of both free and loosely clay-bound water. The isotopic composition confirms the origin and genesis of the formation water. Chemical analysis of aqueous extracts gives the lower limit of sodium chloride (NaCl) salinity. The CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks. A representative collection of rock samples is formed based on the petrophysical interpretation of well logs from a complex source rock of the Bazhenov Formation (BF; Western Siberia, Russia). The EM employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, and X-ray diffraction (XRD) analysis. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δO and δH. A modified alcoholic ammonium chloride [(NH4Cl)Alc] method provides the CEC and exchangeable cation concentration of the rock samples with low carbonate content. The studied rock samples had residual formation water up to 4.3 wt%, including free up to 3.9 wt% and loosely clay-bound water up to 0.96 wt%. The latter correlates well to the clay content. The estimated formation water salinity reached tens of grams per liter. At the same time, the isotopic composition confirmed the formation genesis at high depth and generally matched with that of the region's deep stratal waters. The content of chemically bound water reached 6.40 wt% and exceeded both free and loosely bound water contents. The analysis of isotopic composition proved the formation water origin. The CEC fell in the range of 1.5 to 4.73 cmol/kg and depended on the clay content. In this study, we take a qualitative step toward quantifying formation water in shale reservoirs. The research effort delivered an integrated workflow for reliable determination of formation water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs and general reservoir characterization and reserve estimation. The research novelty uses a unique suite of laboratory methods adapted for tight shale rocks holding less than 1 wt% of water.
Kazak, Ekaterina S. (Skolkovo Institute of Science and Technology, Lomonosov Moscow State University) | Kazak, Andrey V. (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Bilek, Felix (Dresden Groundwater Research Centre)
The research goal is the development of a novel integrated solution of formation water content and salinity determination for petrophysical characterization. The workflow relies on three techniques: evaporation method (EM) with isotopic composition analysis, analysis of water extracts, and cation exchange capacity (CEC) study. The EM offers a fast, efficient, and accurate measurement of the residual water content with breakdown into free and loosely clay-bound types. The isotopic composition reveals the origin and genesis of pore water. The chemical analysis of water extracts delivers a lower bound salinity in terms of NaCl. CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks.
A representative collection of rock samples is formed based on the petrophysical interpretation of well logs for a complex tight gas reservoir rock of the the Bazhenov formation (West Siberia, Russia). The evaporation method employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, XRD. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δ18O and δD. A modified alcoholic NH4Cl method provides CEC and exchangeable cations concentration of the rock samples with low carbonate content.
The target rock samples contained residual formation water 0.11–4.27 wt.%, including free 0.04–3.92 wt.% and loosely clay-bound water 0.09–0.96 wt.%. The loosely bound water content correlates well to the clay mineral fraction. The estimated pore water salinity reached tens of grams per liter; the corresponding isotopic composition indicated the deep formation genesis and generally correlated to that of the deep stratal waters of West Siberia. The amount of chemically bound water fell in a range of 0–6.40 wt.% and exceeds that of free and loosely bound water. The isotopic composition proved the formation origin of the extracted pore water samples. CEC falls in 1.5–4.73 cmol/kg and depends on the clay content.
The study made a qualitative step up towards the quantitative characterization of formation water in shale reservoir rocks. Research effort delivered an integrated workflow for reliable determination formation of water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs, as well as general reservoir characterization and reserves estimation. The research novelty is in using a unique suite of laboratory methods adapted for tight shale rocks with the initial water content of less than 1 wt.%.
Pei, Yanli (The University of Texas at Austin) | Yu, Wei (The University of Texas at Austin / Sim Tech LLC) | Sepehrnoori, Kamy (The University of Texas at Austin) | Gong, Yiwen (Sim Tech LLC / The Ohio State University) | Xie, Hongbin (Sim Tech LLC) | Wu, Kan (Texas A&M University)
The extensive depletion of the development target has triggered the demand for infill drilling in the upside target of multilayer unconventional reservoirs. To optimize the hydraulic fracturing design of newly drilled wells, we need to investigate the stress changes in the upside target induced by parent-well production. In this work, an integrated parent-child workflow is presented to model the spatial-temporal stress evolution and propose the optimal development strategy for the upside target using a data set from the Permian Basin. The stress dependence of matrix permeability and fracture conductivity is determined based on available experimental data and incorporated in our reservoir simulation with the aid of an embedded discrete fracture model (EDFM). With calibrated reservoir properties from history matching of an actual well in the development target (i.e., 3rd BS Sand), we run the finite element method (FEM) based geomechanics simulator to predict the 3D spatial-temporal evolution of the local principal stresses. A displacement discontinuity method (DDM) hydraulic fracture model is then applied to simulate the multi-cluster fracture propagation in the upside target (i.e., L2BSSh) with the updated heterogeneous stress field. Numerical results indicate that stress field redistribution associated with parent-well production not only occurs within the development target but also vertically propagates to the upside target. A smaller parent-child horizontal offset induces a severer deviation of child-fractures towards the parent wellbore, resulting in more substantial well interference and less desirable oil and gas production. The parent-child fracture overlapping ratio in our study is in 0.6 ~ 0.8 for the 400 ft horizontal offset and 0.2 ~ 0.5 for the 600 ft horizontal offset. Varying the parent-child vertical offset gives the same trend as we change the horizontal offset. But with a delayed infill time, placing child-well in different layers causes more significant variation in the ultimate recovery. Moreover, infill operations at an earlier time are less affected by parent-well depletion because of the more homogeneous stress state. The candidate locations to implement infill-wells are suggested in the end for different infill timing by co-simulation of the parent-child production. With the reservoir-geomechanics-fracture model, this work provides a general workflow to optimize the child-well completion in multilayer unconventional reservoirs. The conclusions drawn from this study are of guiding significance to the subsequent development in the Permian Basin.
Abstract The objective of this research was to identify hydraulic fracturing regulations from a range of jurisdictions, verify the grounds for regulatory intervention within the scientific literature and categorize the statements according to the geospatial application. Specific regulations constraining aspects of hydraulic fracturing activities from jurisdictions across the world were collated to identify common features relating to environmental protection, administrative requirements and grammatical structure. Regulations from 55 jurisdictions including states in the US, provinces in Canada, Australian states, European countries, Africa and South America were assessed and common focus areas identified, allowing for the development of a regulatory suite of universal application. Regulations could be ascribed to partitions of the environment including the lithosphere, the atmosphere, the hydrosphere, biosphere and the social framework. Some 32 distinct elements were identified as frequent constraints to hydraulic fracturing located in three geospatial zones: off-site; wellsite; and, wellhead. The scientific literature for each of these areas was critically assessed and summary reviews developed as a comprehensive and wide ranging review of environmental impacts. The specific use of open ended risk regulation as part of control documents (a permit or regulatory framework) appears to have been promoted as a catch-all in the absence of knowledge within the regulatory agency as if there is a lack of evidence supporting directed regulation. As an output of this research a Driver-Pressure-State-Impact-Response model was developed reflecting the substantial literature base that extends well back into the 1970s, with the initial development of coalbed methane in the Rockies and the Southern States and since the 1990s with shale. The paper calls into question claims of "We don't know enough".
Summary We built a 3D geomechanical model using commercially available finite-element-analysis (FEA) software to simulate a propagating hydraulic fracture (HF) and its interaction with a vertical natural fracture (NF) in a tight medium. These newly introduced elements have the ability to model the fluid continuity at an HF/NF intersection, the main area of concern. We observed that, for a high-stress-contrast scenario, the NF cohesive elements showed less damage when compared with the lowstress-contrast case. Also, for the scenario of high stress contrast with principal horizontal stresses reversed, the HF intersected, activated, and opened the NF. Increasing the injection rate resulted in a longer and wider HF but did not significantly affect the NF-activated length. Injection-fluid viscosity displayed an inverse relationship with the HF length and a proportional relationship with the HF opening or width. We observed that a weak NF plane temporarily restricts the HF propagation. On the other hand, a tougher NF, or an NF with properties similar to its surroundings, does not show this type of restriction. The NF activated length was found at its maximum in the case of a weaker NF and at nearly zero in the case of a stronger NF and an NF that has strength similar to its surroundings. In this study we present the results for a three-layered 3D geomechanical model with a single HF and NF orthogonally intersecting each other, using newly introduced cohesive elements for the first time in technical literature. We also conducted a detailed sensitivity analysis considering the effect of stress contrast, injection rate, injection-fluid viscosity, and NF properties on this HF/NF interaction. These results provide an idea of how the idealized resultant fracture geometry will change when several fracture/fracture treatment properties are varied. Introduction The issue of HF and NF interaction has been numerically examined using software packages at both the laboratory and field levels. Warpinski and Teufel (1987) experimentally found that the HFs propagated through joints and formed a multistranded and nonplanar fracture network. The presence of a similar network was also observed in core samples from tight-sandstone reservoirs. Warpinski (1993) and Fisher et al. (2002) interpreted some of the Barnett Shale microseismic data and found that the HF propagation and orientation was affected by the already existing NFs. Lancaster et al. (1992) conducted a core study and found that the HF can propagate along an NF, resulting in propped NFs.
Newby, Warren (Total SA) | Abbassi, Soumaya (Total SA) | Fialips, Claire (Total SA) | D.M. Gauthier, Bertrand (Total SA) | Padin, Anton (Total SA) | Pourpak, Hamid (Total SA) | Taubert, Samuel (Total SA)
Abstract The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its age-equivalent Najhma shale member in Kuwait. The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment. Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays’ productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.
The compressibility factor (Z) of a gas inside a nanosize conduit depends on the conduit’s characteristic size, in contrast to wide conduits whose dimensions have no effect on the gas compressibility. Nanofluidics, which is a field of study concerned with the fluid flow in nanosize conduits, can quantify the gas compressibility factor in a simple topology, such as a uniform tube with a circular cross section, but it is not apparent how those results are relevant to a complex pore space in the matrix of a shale at the core scale. This study determines the compressibility factor of a shale gas by accounting for the effective connectivity of the pore space at the core scale. We use effective pore-throat and pore-body sizes, which are interpreted using an acyclic pore model applied to the core-scale measurements and not high-resolution images. Eleven shale formations whose data are available in the literature are investigated (Bakken, Barnett, Eagle Ford, Haynesville, Marcellus, Monterey, New Albany, Niobrara, Utica, Wolfcamp, and Woodford). The results, which have applications in developing realistic models based on petrophysical measurements, show the compressibility factor (Z) of the shale formation at the core scale as a function of gas pressure.
Abstract Eleven wells in the DJ Basin were drilled utilizing acquired-while-drilling (AWD) Geochemistry in an effort to aid real-time geosteering in optimum rock quality, to provide petrophysical characterization useful to completion design, and to identify geohazards and compartmentalization. The data collected from this effort profoundly improved the ability to geosteer in the best target consistently and was immediately relevant and incorporated into completion design. Geochemical signatures for subseismic faults and fractures were also detected, along with clear identification of stratigraphic location of the borehole. Mass spectrometry (MS), combined with collected thermal maturity data helped advance petroleum system mapping and understand well performance. These methods were found to be lower risk and more cost effective to run than horizontal wireline logs, while providing detailed petrophysical characterization. In a pilot study, two extended reach laterals, one Niobrara C well and one Codell well, were drilled in 2017, with samples collected every 100 feet and tested for energy-dispersive X-ray Fluorescence (ED_XRF), bulk X-ray Diffraction (XRD), and HAWK Pyrolysis to compliment MS analyzing the full hydrocarbon spectrum of C1-C12 and inorganic gasses collected while drilling. The data was synthesized after completion and four main observations were made: 1.) Mineralogical characterization using XRD along the borehole could immediately and precisely identify rock type and stratigraphic zone of drilling (In-zone/Out of zone). 2.) Mineralogical brittleness obtained from XRD was immediately correlated to completion issues and incorporated into completion design 3.) XRF trace yielded a surprising fault and fracture indicator that also became useful to completion design 4.) MS also yielded interesting qualitative comparisons of hydrocarbon fluids and gases and provided further compartmentalization characterization for each well. Together, these collected components led to a significant greater understanding of the borehole than gamma ray, cuttings, mudlogs, and horizontal logs combined.
Abstract The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.
Abstract Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low porosity and low permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara shale in the Denver Basin of the United States: The Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality, and a higher source rock potential. Both the Upper Chalks and the Marls should have major economic potentials. The Lower Chalk has higher porosity and a higher fraction of micro-and nanopores; however, it exhibits poor source rock potential. The measured core data indicates large mineralogy, organic-richness, and porosity heterogeneities throughout the Niobrara interval at all scale. Introduction Unconventional petroleum systems are highly complex hydrocarbon resource plays both at the reservoir scale and at the pore scale (Aplin and Macquaker, 2011; Loucks et al., 2012; Hart et al., 2013; Hackley and Cardott, 2016). These organic-rich sedimentary plays, generally described as shale reservoirs, are composed of very fine silt-and clay-sized particles with grain sizes < 62.5 μm (Loucks et al., 2009; Nichols, 2009; Passey et al., 2010; Kuila et al., 2014; Saidian et al., 2014). They undergo extensive post-depositional diagenesis that transforms rock composition and texture, hydrocarbon storage and productivity, and reservoir flow features (Rushing et al., 2008; McCarthy et al., 2011; Jarvie, 2012; Milliken et al., 2012). Although some shale rock facies can retain depositional attributes during diagenesis, many critical reservoir properties, such as, mineralogy, pore structure, organic richness and present-day organic potential, etc., are significantly perturbed (Hackley and Cardott, 2016).