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Abstract A seven-step workflow to help subsurface teams establish an initial thesis for optimal completion design (cluster spacing, proppant per cluster) and well spacing in emerging / under-explored resource plays is proposed and executed for the Powder River Basin Niobrara unconventional oil play. The workflow uses Rate Transient Analysis (RTA) to determine the parameter and then walks the reader through how to sequentially decouple the parameter into its constituent parts (frac height (h), number of symmetrical fractures achieved (nf), permeability (k) and fracture half-length (xf)). Once these terms were quantified for each of the case study wells, they were used in a black oil reservoir simulator to compare predicted verses actual cumulative oil performance at 30, 60, 90,120 & 180 days. A long-term production match was achieved using xf as the lone history match parameter. xf verses proppant per effective half-cluster yielded an R value of > 0.90. 28 simulation scenarios were executed to represent a range of cluster spacing, proppant per cluster and well spacing scenarios. Economics (ROR and/or NPV10/Net Acre) were determined for each of these scenarios under three different commodity pricing assumptions ($40/$2.50, $50/$2.50 and $60/$2.50). An initial thesis for optimal cluster spacing, proppant per designed cluster and well spacing were determined to be 12’, 47,500 lbs and 8-14 wells per section (based on whether or not fracture asymmetry is considered) when WTI and Henry Hub are assumed to be $50 & $2.50 flat.
Abstract There is a very extensive amount of information and learnings from naturally fractured reservoirs (NFRs) around the world collected throughout several decades. This paper demonstrates how the information and learnings can be linked with tight and shale reservoirs (TSRs) with the objective of maximizing hydrocarbon recovery from TSRs. A classic definition indicates that a natural fracture is a macroscopic planar discontinuity that results from stresses that exceed the rupture strength of the rock (Stearns, 1982). Stearns' definition has been applied successfully for several decades. In this paper, the definition is extended to include not only macroscopic planar discontinuities but also planar and sinuous discontinuities that extend throughout different scales including micro and nano fractures. The paper demonstrates that, as in the case of the continuum that exists in process speed (the ratio of permeability and porosity, Aguilera, 2014), there is also a continuum of pore throat apertures of different sizes, natural fractures with different apertures, and Biot coefficients for different rocks. All of these directly or indirectly which affect reservoir performance. Actual observations in TSRs indicate that micro and nano natural fractures do not flow significant volumes of oil or gas toward horizontal wells. Thus, the wells must be hydraulically fractured in multiple stages to achieve commercial production. Once the wells are hydraulically fractured, the area exposed to the shale reservoir is enlarged and the natural micro and nano fractures flow hydrocarbons toward the hydraulic fracture, which in turn based on the values of hydraulic fracture permeability, feeds those hydrocarbons to the wellbore. In TSRs there are also completely cemented macroscopic fractures that are breakable by hydraulic fracturing and can become very effective conduits of hydrocarbons toward the wellbore. The link that exists between natural fractures at significantly different scales established in this paper is a valuable observation. This is so because the larger tectonic, regional and contractional (diagenetic) fractures that exist in NFRs have been studied extensively for several decades, for example in carbonates, sandstones, and basement rocks. Those learnings from NFRs have not been used to full potential in TSRs for maximizing oil and gas recoveries. This paper provides the necessary tools for remediating that situation. The established link between NFRs and TSRs permits determining how to drill and complete wells in TSRs. It is concluded that this link will lead to (1) improvements in gas production performance, and (2) maximizing economic oil rates and recoveries under primary, improved oil recovery (IOR) and enhanced oil recovery (EOR) production schemes.
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.
The story of the US shale revolution is well known. Hydraulic fracturing techniques were executed by Mitchell Energy in vertical Barnett Play gas wells in the early 2000's, vertical wells matured into horizontal multi-stage frac wells, and one of the largest land leasing campaigns in history exploded as operators chased high gas prices.
As the natural gas market became saturated, the industry started to strip the natural gas liquids (NGLs) out of the gas stream to take advantage of the ever-rising oil pricing. When gas prices tumbled in 2011, and oil prices climbed north of $100/bbl, the industry looked to the liquid rich/oil plays, such as the Williston Basin, the DJ Basin, and the Permian Basin.
The turning point came in November 2014 when oil prices fell rapidly. As prices bottomed out at $22/bbl in February 2015, the industry saw a large exodus of operators and capital from the gas rich plays around the US to the liquid rich Permian. The Permian proved to be the haven for oil and gas development with its multiple pay zone targets, high EURs, low break-even costs, friendly regulatory environment, and access to markets. The rush for land, once again ensued, with the hope of an oil price rebound and promise of high returns to capital investors.
The rapid ramp up in activity from 2015–2018 did not come without challenges as it put strain on the availability of services and people, access to pipelines and markets, and access to frac sand/water. This drove up costs and resulted in mixed results for many companies. In addition, operators soon saw that with higher-than-expected gas and water production, expenses to manage these by-products sky-rocketed. Water handling and disposal became a huge portion of operating expenses and with gas export facilities at full capacity, companies started to flare gas in large volumes. Associated gas became a waste product, causing operators needed remove the gas and associated liquids from the revenue stream, and in some cases pay a high cost for flaring permits, rather than shutting in wells.
By 2019, a shift in the investment community was well underway. The days of growth-focused investment were coming to an end, and investors wanted to see returns on their investments. As prices still hovered around the $55/bbl range, investors were getting anxious to recover their capital invested in the industry, and throughout 2019 operators all talked about the ability to generate free cash flow. This paper analyses the free cash flow for three key unconventional basins across the US and discusses the associated economic impacts in each basin.
Melcher, Howard (Liberty Oilfield Services) | Mayerhofer, Michael (Liberty Oilfield Services) | Agarwal, Karn (Liberty Oilfield Services) | Lolon, Ely (Liberty Oilfield Services) | Oduba, Oladapo (Liberty Oilfield Services) | Murphy, Jessica (Liberty Oilfield Services) | Ellis, Ray (Liberty Oilfield Services) | Fiscus, Kirk (Liberty Oilfield Services) | Shelley, Robert (RF Shelley LLC) | Weijers, Leen (Liberty Oilfield Services)
Selecting appropriate proppants is an important part of hydraulic fracture completion design. Proppant selection choices have dramatically increased in recent years as regional sands have become the proppant of choice in many liquid-rich shale plays. But are these new proppants the best long-term choices to maximize production? Do they provide the best well economics?
The paper presents a brief historical perspective on proppant selection followed by various detailed studies of how different proppant types have been performing in various unconventional basins (Williston, Permian, Eagle Ford, Powder River and DJ) along with economic analyses. As the shale revolution pushed into lower-quality reservoirs, the concept of dimensionless conductivity has pushed our industry to use ever lower-quality materials – away from ceramics and resin-coated proppant to white sand in some Rocky Mountain plays and more recently from white sand to regional sand in the Permian and Eagle Ford plays.
Further, we compare early-to late-time production response and economics in liquid-rich wells where proppant type changed. The performance of various proppant types and mesh sizes is evaluated using a combination of different techniques, including big data multi-variate statistics, lab conductivity testing, detailed fracture and reservoir modeling, as well as direct well group comparisons. The results of these techniques are then combined with economic analyses to provide a perspective on proppant selection criteria. The comparisons are anchored to permeability estimates from production history matching and DFITs and thousands of wellsite proppant conductivity tests to determine dimensionless conductivity estimates that best approach what is obtained in the field.
Proppant selection is typically based on crush resistance to stress loading and fracture conductivity under various flow conditions while having the lowest possible cost. However, dimensionless fracture conductivity is the main driver of well performance as it relates to proppant selection since it includes the relationship of fracture conductivity provided by the proppant relative to the actual flow capacity of the rock (the product of permeability and effective fracture length), which is supported by the production analyses in the paper. The paper shows how much fracture conductivity is adequate for a given effective fracture length and reservoir permeability and then looks at the economics of achieving this "just-good -enough" target conductivity, either through less proppant mass with higher-cost proppants or more proppant mass with-lower cost proppants, as well as mesh size considerations.
This paper does not rely on a single technique for proppant selection but uses a combination of various data sources, analysis techniques and economic criteria to provide a more holistic approach to proppant selection.
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.