Cudjoe, Sherifa (University of Kansas) | Liu, Siyan (University of Kansas) | Barati, Reza (University of Kansas) | Hasiuk, Franciszek (Kansas Geological Survey) | Goldstein, Robert (KICC - University of Kansas) | Tsau, Jyun-Syung (TORP - University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
The objective of this work is to conduct pore-scale analysis of the pore systems in an Eagle Ford (EF) outcrop sample and a Lower Eagle Ford (LEF) sample from a producing interval in the subsurface. After characterization, we estimate bulk transport properties (such as tortuosity and permeability) within each pore network model (PNM) using the lattice Boltzmann method (LBM). Comparing the two will evaluate the degree to which outcrop samples of the EF are or are not applicable analogs to the subsurface for laboratory-scale "huff-n-puff’ enhanced oil recovery experiments.
Grain types and pore systems of both samples were visualized and quantified at the micro- and nanoscale using scanning electron microscopy/backscattered electron microscopy (SHM/BSH), energy- dispersive X-ray spectroscopy (EDS), and focused ion beam-scanning electron microscopy (FIB-SEM). These methods measure mineral content, elemental (mineral) analysis, size distribution of pores and pore throats in addition to serving as the basis to develop pore network models (PNMs) for simulation. The LBM was then applied to the extracted pores to estimate permeability for each medium.
The 2D SEM/BSE/EDS images of the EF outcrop sample showed that the microstructure of finegrained inorganic matrix was modified by calcite neomorphic and passively precipitated microspar, spar, and pseudospar altering the texture of the depositional matrix, low clay content with some of feldspar, solution-enlarged microfractures, compactional fractures, coccolith debris, and calcite deformation (solution-enlarged cleavages). There are abundant microfossils including foraminifer tests ("forams") filled with either diagenetic calcite, quartz, organic matter or a mixture of these minerals; the organic matter in the foram chambers mostly show cracks/shrinkage pores or lack pores in organic matter.
On the other hand, the LEF reservoir sample showed significantly different diagenetic alteration with localized phosphate diagenesis, less calcite neomorphism, and better developed pores within the organic matter infilling the foraminiferal tests as well as in depositional kerogen embedded within the inorganic matrix. In addition, 3D FIB- SEM volumes showed the variation in tortuosity of each extracted PNM and its impact on the diffusion coefficient during gas huff-n-puff recovery. The LBM enabled the estimation of permeability at the molecular level from each extracted PNM.
Not surprisingly, the textural and compositional differences between the outcrop and subsurface samples lead to different PNM and different behavior in huff-n-puff experiments. This work bridges a gap in the literature by comparing and revealing the pore-scale heterogeneities of an outcrop sample to that of a subsurface sample to measure the impact of the underlying mechanisms associated with gas huff-n-puff recovery at the laboratory-scale, while estimating permeability within extracted pores with the LBM.
The number of components present in a system determines the maximum number of phases that can coexist at fixed temperature and pressure. The phase rule of Gibbs states that the number of independent variables that must be specified to determine the intensive state of the system is given by ....................(8.1) For a single-component system, the maximum number of phases occurs when there are no constraints (Nc 0) and no degrees of freedom (F 0). Thus, the maximum number of possible phases is three. If only two phases are present in a pure component system, then either the temperature or the pressure can be chosen.
Anderson, Iain (Heriot-Watt University) | Ma, Jingsheng (Heriot-Watt University) | Wu, Xiaoyang (British Geological Survey) | Stow, Dorrik (Heriot-Watt University) | Underhill, John R. (Heriot-Watt University)
This work forms part of a study addressing the multi-scale heterogeneous and anisotropic rock properties of the Lower Carboniferous (Mississippian) Bowland Shale; the UK's most prospective shale-gas play. The specific focus of this work is to determine the geomechanical variability within the Preese Hall exploration well and, following a consideration of structural features in the basin, to consider the optimal position of productive zones for hydraulic fracturing. Positioning long-reach horizontal wells is key to the economic extraction of gas, but their placement requires an accurate understanding of the local geology, stress regime and structure. This is of importance in the case of the Bowland Shale because of several syn- and post-depositional tectonic events that have resulted in multi-scale and anisotropic variations in rock properties. Seismic, well and core data from the UK's first dedicated shale-gas exploration programme in northwest England have all been utilized for this study. Our workflow involves; (1) summarizing the structural elements of the Bowland Basin and framing the challenges these may pose to shale-gas drilling; (2) making mineralogical and textural-based observations using cores and wireline logs to generate mineralogy logs and then to calculate a mineral-based brittleness index along the well; (3) developing a geomechanical model using slowness logs to determine the breakdown stress along the well; (4) placing horizontal wells guided by the mineral-based brittleness index and breakdown stress. Our interpretations demonstrate that the study area is affected by the buried extension of the Ribblesdale Fold Belt that causes structural complexity that may restrict whether long-reaching horizontal wells can be confidently drilled. However, given the thickness of the Bowland Shale, a strategy of production by multiple, stacked lateral wells has been proposed. The mineralogical and geomechanical modelling presented herein suggests that several sites retain favorable properties for hydraulic fracturing. Two landing zones within the Upper Bowland Shale alone are suggested based on this work, but further investigation is required to assess the impact of small-scale elastic property variations in the shale to assess potential for well interference and optimizing well placement.
Garcia, Artur Posenato (The University of Texas at Austin) | Hernandez, Laura M. (The University of Texas at Austin) | Jagadisan, Archana (The University of Texas at Austin) | Heidari, Zoya (The University of Texas at Austin) | Casey, Brian (University Lands) | Williams, Rick (University Lands)
Reliable formation evaluation in organic-rich mudrocks requires integrated interpretation of well logs and core measurements. More than 80% of the Permian Basin wells have incomplete data sets, lacking photoelectric factor (PEF) or other logs, required for reliable formation evaluation in the presence of complex mineralogy. Hence, we develop a novel workflow to reliably estimate rock properties in wells with incomplete data to enhance reservoir characterization and completion decisions. We propose to (a) use integrated rock classification for enhanced physics-based assessment of rock properties in wells with missing data, (b) combine field-scale geostatistical and machine learning methods to reliably reconstruct missing PEF logs with a confidence interval through a rock-type-based approach which is a unique contribution of this work, and (c) quantify the uncertainty in estimates of petrophysical properties.
We performed a preliminary field-scale formation evaluation on wells with triple-combo logs (more than 70 wells). Next, we performed an initial rock typing and reconstructed the missing PEF logs by combining supervised neural networks with geostatistical analysis on a rock-type basis. We then used an unsupervised neural network method to improve the rock classification based on the updated estimates of petrophysical, compositional, and mechanical properties after PEF reconstruction. The combined rock classification and PEF reconstruction was performed iteratively to improve the multi-mineral analysis results in all wells with missing data. We successfully applied the new workflow to 20 wells in blind tests. The reconstructed well logs agreed with the actual measurements with relative errors of less than 10%.
The new workflow extends the boundaries of reliable formation evaluation, enabling accurate reservoir characterization and completion decisions by enhancing evaluation of wells with missing data. This is achieved by reliably reconstructing missing PEF logs with a confidence interval, in a class-by-class basis, which is a unique contribution of this work. The proposed method can be applied to wells with other types of missing data. Analysis of the production data showed that, ceteris paribus, the best rock types obtained from the workflow had approximately 30% higher hydrocarbon production than other rock types.
In the Midland Basin of west Texas, produced water volumes have historically been disposed into shallow intervals (i.e., Grayburg-San Andres). Over the last decade, the rapid growth in unconventional resource development has resulted in a significant increase in the volume of produced water leading to pressure gradient differences between shallow disposal zones and deeper intervals. These conditions have created drilling challenges and have prompted operators to test additional zones suitable for produced water disposal. In recent years, the Early Ordovician Ellenburger (ELBG) reservoir has become an alternative disposal interval to shallower reservoirs.
The Ellenburger Group of west Texas, a prolific producing reservoir, is part of an extensive carbonate system best known for karst development associated with prolonged subaerial exposure and intervals of high secondary porosity in fracture breccias generated by subsequent cave collapse. Many authors have described fracture occurrence and karst-related breccias of the ELBG, both of which impact productivity at the reservoir scale within the fields and make regional correlations particularly challenging. Ellenburger depositional facies have been described by previous workers in equivalent units across west and central Texas, and textural analysis of high-resolution electrical borehole images from recently drilled disposal wells, combined with core observations, shows corresponding porous intervals to be present in the Midland Basin.
This paper describes the generation of a regional model of porosity distribution within the Ellenburger and assesses the important differences in depositional environment and diagenetic history that exist among the internal units of the ELBG that may impact salt water disposal (SWD) well performance. For example, the Upper ELBG is dominated by fracture porosity in breccia fabrics associated with collapsed cave systems, while the Lower ELBG exhibits preserved porosity associated with original depositional textures. The regional model was tested using multiple datasets: image logs, core descriptions, electric logs from more than 400 well penetrations, and injection data from recent well tests. The integration of these datasets has resulted in a suite of maps of the key stratigraphic intervals within the ELBG that offer the greatest potential for disposal. Additionally, the integration of well performance with observed regional geologic trends was used to identify and tier key performance drivers for deep SWD injection performance, resulting in refined performance maps that can be used for strategic placement of deep SWD wells.
The Finn-Shurley field produces petroleum from the Upper Cretaceous Turner Sandstone of the Powder River Basin. The Turner is a member of the Carlile and is overlain by the Sage Breaks and underlain by the Pool Creek members of the Carlile. The Turner is interpreted to be a shallow marine shelf sandstone deposited along the eastern side of the Western Interior Cretaceous Seaway. Sand-shelf-bar orientation across the field is roughly east-west. Trapping occurs where sandstone beds get shalier up-dip. The field is located along the shallow east margin of the Powder River Basin south of the Clareton lineament.
Three to four coarsening upward cycles are present in the Turner in the field. Most of the production in Finn-Shurely comes from the lower two cycles. Each cycle consists of burrowed to bioturbated, heterolithic mudstones and sandstones coarsening upwards into fine-grained laminated to burrowed sandstones. Trace fossil present fall into the shelf Cruziana ichnofacies. The sandstones are largely litharenites. Porosities range from 11-17% and permeabilities range from 0.06 to 0.5 md. Source rock analysis of the Turner shales indicate Ro values averaging 0.63 and Tmax values of 433°C. Source beds for the oil and gas in the Turner are thought to be the Mowry and Niobrara formations. The low thermal maturity suggests lateral migration of oil into the stratigraphic trap.
The field extends over an area roughly circular in shape of ~65 square miles. Productive depths across the field are 4450 to 5700 ft. First production is reported as 1965 and cumulative production from ~750 vertical wells is 23.6 MMBO and 38.9 BCFG. Cumulative gas oil ratio is 1688 cu ft gas per barrel oil. Average production per well is approximately 31.5 MBO and 52 MMCFG. Horizontal drilling activity in the field area has recently commenced. Although the production is fair to marginal, the field provides an excellent example of trapping style as well as a depositional model for Turner Sandstone elsewhere in the Powder River Basin. Recent drilling in the deeper overpressured parts of the Powder River Basin has encountered excellent production from the Turner (> 1,000 bbls oil equivalent per well).
Finn-Shurley Field is part of a continuous accumulation within the Turner Sandstone in the Powder River Basin. Distinct oil-water contacts are not present in the field area. The accumulation is underpressured and regarded as unconventional.
The reporting of potential resources is essential to assess the future development plan and profitability of a petroleum discovery, but if the project is under appraised and production data are absent, analysts often use analogs for preliminary estimates of technically recoverable volumes. To address this, a workflow is presented for selecting appropriate analogs for unconventional plays and using them to estimate the target play's potential. The proposed technique is demonstrated with a case study of the as-yet undeveloped Bowland Shale, which is the most prominent of the shale plays in the United Kingdom (UK) and is at the early stage of its assessment. The paper describes the current shale gas activity in the UK, highlighting the enviromental constraints placed on would-be Bowland Shale developers, which impact on drilling and production operations and stem from the geographic proximity of urban developments, infrastructure and nature, which limit the size of well pad footprint in the UK where land use is high. Studies have estimated the play's in-place resources for possible future development, but there are few estimates of its corresponding recoverable volumes due to lack of production history. At the outset, a database is created with published minimum-average-maximum ranges of key parameters such as total organic carbon, maturity level, gas filled porosity, permeability, etc. that play a major role in resources estimation and recovery potential for all unconventional plays. A comparison of triangular distributions, key parameter by key parameter, between the target shale play and the analog database, is then carried out using novel graphical and statistical methods to establish a "confidence factor" relating to the analog's viability. The most appropriate analog for the Bowland Shale is chosen from an exhaustive list of North American shale gas plays. Analytical approaches are then used to transform a model of the published type well performance of the selected analog by exchanging key model parameters with those of the target shale play. The paper shows how UK operational constraints can be statistically incorporated into the workflow and have a marked effect on the estimated recovery from the Bowland Shale.
Hydraulic fracturing is being used globally to unlock hydrocarbon resources in unconventional reservoirs. However, the efficient utilization of resources in most treatment designs is debatable. A study of hydraulic fracturing treatments in 56 vertical and horizontal wells representing 1,151 treated stages in the Wolfcamp and Spraberry formations of the Permian Basin in West Texas was conducted in this paper. Intrinsic treatment strategies and operational methodologies used by the well operators were evaluated with the objective of extracting and deducing insights into criteria that characterize operational virtuosity, efficiency and inefficiency.
Treatments of vertical wells were studied with 25 wells in both formations, in the Midland basin. 18 wells were studied in Spraberry horizontal well treatments, while horizontal Wolfcamp treatments were studied with 13 wells in the Delaware basin. Well completion records, treatment reports and well files were reviewed for treatment parameters on each well. The study concentrated on indices like, proppants types and amount; fluid types and volumes pumped; treatment rates and pressures; productivity and treatment cost. Empirical and statistical analysis using correlations and analysis of variance were then conducted and used to identify the best practices that actively and positively increased production rates and decreased production costs in each of these formations and well types.
The Spraberry is very fine-grained sandstone, siltstone and carbonates with interbedded shales in the studied area. The Delaware Wolfcamp is a complex formation with carbonates, mostly limestone, and interbedded organic rich mudstones in varying proportions. Results show that the use of 20/40 white as a proppant is not economical, in both formations either in vertical or horizontal wells, because of the huge increase in treatment costs. Use of 100 mesh and 40/70 white proppant in both formations was amenable to better production rate. Results show that usage of crosslinked gel increases treatment costs drastically. Slickwater was found to improve production rates, although huge volumes were needed for large proppant amounts. The use of HCl acid as spearhead in formations with high carbonate content like the Wolfcamp was found to improve treatment results. Increasing the number of stages increases treatment cost, but increasing the perforated intervals correlates positively with production rate.
We collected more than 500 ft of through-fracture core in the Upper Wolfcamp (UWC) and Middle Wolfcamp (MWC) formations in the Permian Basin. As part of core characterization, we analyzed the core-sludge samples for the presence of proppant and natural-calcite particles. Apart from sample preparation and imaging, we designed and developed a novel image-processing work flow to detect and classify the particles. We used the observations from the identified particle distribution within the stimulated rock volume to understand proppant-transport behavior. We used relative distributions of smaller 100-mesh- and larger 40/70-mesh-proppant particles to interpret proppant placement in relation to perforation clusters. Finally, we used the relative distribution of particles to understand the interaction between natural and hydraulic fractures. We observe that stress variations and the degree of natural fracturing have a bearing on local proppant-screenout behavior. Smaller 100-mesh proppant seems to dominate at larger lateral offsets from the hydraulically fractured wells. We also observe indications of heel-side bias according to lateral proppant distribution. We share our work flow for particle detection and classification, which can serve as a template for proppant analysis in the future if significant through-fracture cores are collected in similar field experiments.