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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".
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).
Summary A Sand Wash Basin well was drilled for an unconventional target for which the measured core properties did not match production for the well. The crushed‐rock porosity for the core suggested a bulk‐volume hydrocarbon (BVH) of 1.5 to 2.0 p.u., indicating that the stimulation would have to be draining at approximately 400 ft vertically. To resolve this incongruity for further field development, we investigated the validity of crushed‐rock porosity and nuclear magnetic resonance (NMR) to accurately assess the resource. Initial results using conventional 2‐MHz core NMR yielded results similar to those for crushed‐rock porosity. Because unconventional rocks have very fast relaxations in NMR, it was then theorized that with the use of a high‐resolution 20‐MHz machine, the signal/noise ratio would improve and create a more‐accurate quantification of porosity components. The results of using a high‐resolution 20‐MHz NMR showed a porosity increase from 6.5 p.u. using the Gas Research Institute (GRI) methodology (Luffel et al. 1992) to 14 p.u. on an as‐received sample, creating a large increase for in‐place calculations. As a result, a process termed sequential fluid characterization (SFC) was developed using high‐resolution 20‐MHz NMR to quantify all components of porosity (i.e., movable fluid, capillary‐bound water, clay‐bound water, heavy hydrocarbon, residual hydrocarbon, and free water). This method represents an alternative to crushed‐rock methodologies (such as GRI and tight rock analysis) that will accurately quantify movable porosity as well as the other components without the errors introduced by cleaning and crushing. After investigating the application of SFC with the high‐resolution 20‐MHz NMR, it was identified that other unconventional plays (such as Marcellus and Fayetteville) have an average of 45% uplift on in‐place calculations using SFC‐based movable porosity. Identifying in‐place volumes correctly can vastly improve the characterization of fields and prospects for unconventional‐resource development, and, as is shown in this paper, SFC can be used to do so with a great effect on volume assessment in unconventional reservoirs.
ABSTRACT: This paper targets a comprehensive predictive model to evaluate the key success of completion strategies (treatment) for major successful shale plays and guide future selective optimum completion for each shale play. Many important parameters that control producing well behaviors such as number of horizontal wells, spacing between fractures and wells, horizontal well completion configurations, stages per well, fracture type, average water requirement, depth, proppant type, hydraulic horsepower(HHP) per stage, Lb/ft2 of proppants per stage, number of stages, and lateral length of the horizontal wells, have been analyzed.
The proposed analysis is performed on 12 major shale gas and oil plays, for which the data were available. The analysis of the data identified similarity in completion strategies. Learning from these analyses can be used to predict completion strategies in new wells of old or new shale plays.
A case study from Niobrara shale (Colorado) is investigated. The procedure used in exploring the case study can be used as a decision criterion for similar cases in deciding stimulation configurations and main important factors that lead to the optimum way of developing these resources. Principal component analysis (PCA) is used to correlate the commonly used completions strategies with geochemical and geomechanical properties of shale rocks.
Many horizontal wells and fracture stages are needed to drain a shale reservoir, and these is a need for effective fractures and horizontal wells to produce these reservoirs. We conducted a case study of the use of data analytics to study the Niobrara shale rock, and suggest the best completion strategies used to effectively produce from the shale rock.
We then compared the characteristics of the Niobrara shale rock with the 12 most common shale plays in North America. Geochemical and geomechanical properties of these shale rocks vary significantly among the reservoirs and vary within the same reservoir. We believe that this paper will assist in selecting proper completion techniques for horizontal wells.
Katz, David (Whiting Oil and Gas Corporation) | Jung, Marshall (Whiting Oil and Gas Corporation) | Canter, Lyn (Whiting Oil and Gas Corporation) | Sonnenfeld, Mark (Whiting Oil and Gas Corporation) | Odegard, Mark (Whiting Oil and Gas Corporation) | Daniels, John (Whiting Oil and Gas Corporation) | Byrnes, Alan (Whiting Oil and Gas Corporation) | Guisinger, Mary (Whiting Oil and Gas Corporation) | Jones, Kim (Whiting Oil and Gas Corporation) | Forster, John (Whiting Oil and Gas Corporation)
Abstract The brittleness of sedimentary rocks is a critical aspect of their potential to form hydraulically stimulated fractures, resist embedment after stimulation, and thereby produce hydrocarbons over economically significant periods more efficiently. As such it is important to understand how brittle versus non-brittle rocks are organized within a play to improve the recovery of petroleum reserves by identifying higher potential stimulation intervals. The goal of this study is to document the link between the sequence stratigraphic hierarchy and its control on the evolution of mineralogy by FEI's QEMSCAN system, unconfined compressive rock strength, and dipole sonic derived brittleness for the Niobrara Formation. The Niobrara ultimately consists of a combination of sharply to diffusely bedded rocks composed of chalks to claystones with variable organic matter. It is mainly calcium carbonate rich with changing concentrations of detrital quartz, clay, and organic matter that function as the main variables of the mineral brittleness index. The detrital and organic components are relatively dominant in the transgressive systems tract (TST) in the form of laminated and sharply laminated-gradational millimeter to centimeter to decimeter intervals of organic rich chalky claystones-to-marly chalks; high resolution scanning electron photomicrographs also document that this fine scale bedding continues at the nanometer to micrometer scale. Discretely interbedded chalks and marly chalks are interbedded with marls at the cm to decimeter scale during the highstand systems tract (HST); by HST time the shorelines have been pushed landward the furthest and detrital terrestrial contribution to the marine environment has been reduced. This environment is ultimately more favorable to chalk deposition and an overall more brittle mineral assemblage. Mineral derived brittleness logs of the Niobrara ultimately covary with dipole sonic derived rock mechanics (Young's Modulus and Poisson's Ratio), unconfined compressive rock strength measurements from the Equotip-Piccolo, and gamma ray values from downhole tools which in turn may be tuned to identify hydraulic stimulation targets away from cored wells.
Cho, Younki (Colorado School of Mines) | Eker, Erdinc (Colorado School of Mines) | Uzun, Ilkay (Colorado School of Mines) | Yin, Xiaolong (Colorado School of Mines) | Kazemi, Hossein (Colorado School of Mines)
Abstract Liquid-rich shale reservoirs contribute immensely to the United States oil and gas production. Because Bakken, Lower Eagle Ford, and Niobrara formations have different mineralogy, pore structure, organic content, and fluid compositions, it is critical to differentiate the unique characteristics of each formation for field development and oil and gas production. The latter information is also useful in well stimulation design and hydraulic fracturing. This paper presents an experimental study of mineralogy, pore-size distribution, pore geometry, and spatial correlation between minerals and pores to identify the effect of micro-scale properties on flow behavior. Porosity and permeability of several core samples from the Middle Bakken, Lower Eagle Ford, and Niobrara formations were studied and the results, using mercury injection capillary pressure (MICP), X-Ray diffraction (XRD), and scanning electron microscopy (SEM), were shown. Finally, a workflow that estimates cementation factor combining the results obtained from MICP measurements and GRI crushed core analysis will be presented.
The uncemented annulus of an oil and gas well is a possible pathway for migration of thermogenic methane into the shallow subsurface. Poorly cemented wells allow for methane to migrate upwards from the producing formation and accumulate in the annulus between the production casing and the surrounding rock matrix. Additionally, methane from intermediate formations above the target formation may also leak methane into the annulus if they are not sealed off by cement. In the United States., the annulus of the well is capped at the surface by the bradenhead valve to prevent the venting of methane to the atmosphere. However, this valve allows gas to build and increase the pressure above the fluid in the annulus. In this work, we investigate how the buildup of bradenhead pressure influences methane migration in the subsurface. We present a two-dimensional model that simulates single phase flow of dissolved methane away from the wellbore. We consider best and worst case scenarios and we vary the boundary conditions to represent both closed and open wellbores. Our results show that the buildup of pressure in the annulus of a wellbore has a very small impact on methane migration. Of the parameters we consider, the density of the fluid in the wellbore has the greatest influence on methane migration.
Over the last ten years, the extraction of resources from unconventional formations has fueled a significant rise in United States oil and natural gas production [1, 2]. Public concern with the potential environmental impacts of the extraction process has increased as well. In particular, debates have arisen about the fate of the chemicals used in the high volume slick water hydraulic fracturing process . As a result, a number of studies have begun to investigate the quality of groundwater in regions with heavy unconventional oil and gas development [4, 5, 6, 7, 8].
These studies have found varying degrees of methane in the shallow subsurface in the vicinity of oil and gas wells [4, 5, 9]. Although methane itself is not hazardous to human health, unless present in explosive quantities, its isotopic signature provides insight into the origin of the gas. Methane formed through intense heat and pressure (thermogenic) and methane formed by microbes (biogenic) can be distinguished from one another through analysis of the carbon and hydrogen isotopes of the methane molecules . These properties make methane an attractive tracer that could indicate contamination from oil and gas drilling operations. If thermogenic methane is found in a drinking water aquifer, its presence suggests that a flaw in the oil and gas well may exist or a permeable pathway may be present between the producing formation and the shallow subsurface [4, 11].