Others, such as subsea power-distribution systems, are still in the product development stage. Many of the emerging products are well-proven surface components modified for subsea application. As in any integrated system, a shortcoming in any one of the links will impair the performance of the whole. Successful implementation requires all the skill sets to work seamlessly and with greater than ever attention to QA/QC in components manufacturing, installation, and system integration. A clear understanding of the process and all its parameters is the first step toward a successful design. As in surface facilities, knowledge of the produced fluid properties, rheology, and flow characteristics are critical. Luckily, whether the process is carried out on the surface or a thousand meters subsea, the process is the same. However, effects of the environmental conditions may be more dramatic and detrimental. Fluids with high foaming tendency will complicate the design and may require mechanical or chemical solutions. For subsea applications, a passive mechanical foam-breaking device (such as a low-shear inlet momentum breaker) is preferred over the more costly to install and operate chemical injection systems. For three-phase separation, the more complex oil/water emulsion/dispersion chemistry will come into play, along with the viscosities of the oil and water and changes in water cut with time.
Siliciclastic (commonly referred to as clastic) rocks are composed of terrigenous material formed by the weathering of pre-existing rocks, whereas carbonate rocks are composed principally of sediment formed from seawater by organic activity. This difference effects hydrocarbon recovery and therefore is important to understand. Clastic sediments are composed of grains and clay minerals, and siliciclastic sediments are first classified according to grain type. Second, siliciclastics are described in terms of grain size (Figure 1b). Mixtures are described with a modifying term for a less-abundant size, such as clayey sandstone, sandy siltstone, or muddy sandstone (Figure 1c).
The objective of our research is to reconcile the differences, in both age and relative stratigraphic position, between the Woodbine and Eagle Ford Groups in the outcrop and subsurface of the East Texas Basin. In the outcrop belt, organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Eagle Ford Group, where they overlie, and are separated by a regional unconformity from Early Cenomanian, organic-poor, and clay-rich mudstones of the Woodbine Group (Pepper Shale). In southern portions of the East Texas Basin, however, these same organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Maness Shale, which in turn, is overlain by Late Cenomanian to Turonian-aged mudstones (Pepper Shale) and sandstones (Dexter Formation) mapped as the Woodbine Group. Our approach to reconcile the lithostratigraphic juxtaposition between the two regions was to use chemo-stratigraphic and petrophysical data collected from the outcrops, as well as an adjacent shallow research borehole, in order to define key sequence stratigraphic units/surfaces, and then correlate the key units/surfaces from the outcrop belt into the subsurface.
Our research indicates that the Woodbine Group, is an older unconformity-bounded depositional sequence which is Early Cenomanian, whereas the Eagle Ford Group, is an overlying (younger) unconformity-bounded depositional sequence, which is Middle Cenomanian to Late Turonian. The unconformities that bound these units can be mapped from the outcrop belt into the subsurface of the East Texas Basin, to define coeval depositional sequences. As defined in this study, marine mudstones of the Woodbine Group, are clay- & silica-rich, TOC-poor, and characterized by low resistivity on geophysical logs. In general, the Woodbine Group thins, as well as transitions to more mudstone-prone facies, from northeast to southwest within the basin. While beyond the scope of this study, the Woodbine Group contains numerous higher-frequency sequences, which are stacked in an overall progradational (highstand) sequence set. The depositional profile of the unconformity which forms the top of this progradational succession sets up the relict physiographic (depositional shelf/slope/basin) profile for the overlying Eagle Ford Group.
Within the Lower Eagle Ford Formation, two high-frequency sequences, defined as the Lower and Upper Members, were defined. Within the Upper Eagle Ford Formation, three high-frequency sequences, defined as the Lower, Middle, and Upper Members, were defined. The Lower and Upper Members of the Lower Eagle Ford Formation, as well as the Lower Member of the Upper Eagle Ford Formation range from Middle Cenomanian to Early Turonian. These three high-frequency sequences contain marine mudstones that are carbonate- & TOC-rich, as well as clay- and quartz-poor, and are characterized by high resistivity values on geophysical logs. Furthermore, they are interpreted as a transgressive sequence set, with sequences that sequentially onlap, from older to younger, the inherited relict physiographic (depositional shelf/slope/basin) profile of the underlying Woodbine Group. In stark contrast, mudstones within the Middle and Upper Members of the Upper Eagle Ford Formation, which are Middle to Late Turonian, are clay-rich, TOC-poor, and characterized by low resistivity on geophysical logs. These two sequences, which are interpreted as a highstand sequence set, are sandstone-prone, and contain petroleum reservoirs that previously were incorrectly included within the Woodbine Group. Based on these correlations, updated sequence-based paleogeographic maps can be constructed for the first time across the East Texas Basin. These maps can in turn be used to define a robust portfolio of conventional, as well as unconventional tight-rock and source-rock, plays and play fairways, which are now based on a modern sequence stratigraphic, versus the traditional archaic lithostratigraphic framework.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Marshall, Craig (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Microscopic analysis including transmitted light, UV epifluorescence, BSE, and FIB-SEM carried out on Lower Eagle Ford (LEF) shale samples, selected from similar depths, show complex depositional fabrics, kerogen, migrated organic matter, and diagenetic history. It is well known that LEF samples contain depositional kerogen and migrated organic matter. Much of the migrated organic matter occupies diagenetically reduced primary porosity. Some of this organic matter is not porous, while some contains large pores and other contains a fine network of nanopores. Where thermal maturity is one control on porosity in organic matter, there is also a control of composition and origin. This paper investigates the chemistry of organic matter in-situ using Raman spectroscopy, to begin to understand what, other than thermal maturation, leads to porosity in both depositional kerogen and migrated organic matter. This is used to evaluate the nature of the pores in LEF, and to assess the impact of hydrocarbon gas injection on organic porosity.
Thin sections of the lower Eagle Ford shale samples are examined with transmitted light microscopy to select samples for Raman spectroscopy, after studying with FIB-SEM to analyze distribution of porosity in organic matter. In the Raman spectra, the separation between the D and G bands, the width of the G-band, and the intensity ratio of the D-to-G-bands are typically ascribed to maturity-related changes. However, composition and origin of the organic matter may also have an effect. The Raman spectra are analyzed to characterize the different types of porous and non-porous organic matter at the same depth. Then, samples are subjected to gas injection in the laboratory in preparation for a gas huff-n-puff operation, and changes in Raman spectra are analyzed once again.
BSE images show depositional kerogen is found as isolated bodies, lamellar forms, and fine material disseminated in the matrix. Transmitted light and UV microscopy reveal that some of this is non-fluorescent and some is fluorescent. Cement-reduced intraparticle pores, other primary pores, intercrystalline pores, and micro-fracture and micro-breccia pores contain migrated organic matter (OM), none of which fluorescences in UV. FIB-SEM images show the migrated OM has either spongy nanopores, larger bubble/meniscate pores, or no pores, all in the same sample. Raman spectroscopy analysis on the different types of organic matter show examples where both G- and D- bands are visible with distinctive separation, intensity ratio, or width, or where the D-band is absent. Moreover, the effect of gas injection on the different types of organic matter is inferred from the G- and D- bands.
This work improves our understanding of organic pore generation and modification, which influences pore size distribution and pore tortuosity, the underlying factors in gas huff-n-puff recovery in shales. It expands the utility of Raman micro-spectroscopy as a tool in understanding the evolution of pore systems and organic constituents in shale. It also presents an in-situ molecular structural study of the effect of hydrocarbon gas huff-n-puff on the different types of organic matter.
Flotron, Alyssa (Kansas Interdisciplinary Carbonates Consortium [KICC], University of Kansas) | Franseen, Evan (Kansas Interdisciplinary Carbonates Consortium [KICC], University of Kansas) | Goldstein, Robert (Kansas Interdisciplinary Carbonates Consortium [KICC], University of Kansas)
Controls on deposition and reservoir quality of mixed unconventional carbonates and siliciclastics are not adequately understood. This project explores the Wolfcamp ‘A’ (early Leonardian) in Howard County, TX to determine what stratigraphic and sedimentologic controls lead to areas with the best reservoirs.
Core, thin section, XRD, TRA, and rock-eval pyrolysis data were used to analyze sedimentary facies and rock properties. Core observations were used to calibrate facies to 1122 well logs, which were used to correlate the Wolfcamp A internal stratigraphy across an area of 3637 km2. Facies distribution and thickness were mapped in each stratigraphic package to analyze controls on distribution of high and low reservoir-quality sediment gravity flow (SGF) facies.
Out of 11 lithofacies, the dominant facies assemblages are coarse-grained packstone-floatstone-rudstone (CGC), fine-grained calcareous mudstone-wackestone (FGMW), and siliceous mudstone-siltstone (SMS). CGC facies have sharp, locally erosive surfaces, rip-up clasts, are massive or have internal grading, suggesting deposition from SGFs. The dominance of detrital quartz, lack of radiolarians, rarity of shallow-water skeletal fragments, and massive or normal graded laminations suggest SMS and FGMW were deposited as SGFs with a separate siliciclastic (SMS) or carbonate slope (FGMW) source. SMS facies have the best unconventional reservoir potential, with total porosity ranging from ~6-10%, TOC of 2-3.2 wt%, and low clay content (<50%).
Six regionally identifiable major units show progradational and compensational geometries, and each pair of major units has wedge-on-wedge relationships. The lowest two major units are CGC-rich, the middle two are characterized by SMS facies, and the upper two contain all three facies assemblages. The three major units that are thickest proximally are lobe-shaped and sourced from between the Eastern Shelf and Glasscock “nose” with internal units downlapping basinwards. The other three major units are thickest distally and laterally with internal units onlapping proximally and, with some exceptions, are mostly sourced from the Eastern Shelf and Glasscock “nose.”
The results suggest CGC facies were commonly deposited during high relative sea level whereas most SMS and FGMW facies were deposited during low relative sea level. Notch-like features in the slope acted as foci for SGFs. Promising sweet spots of greatest thickness and SMS prevalence are in the middle pair of major units and located near a northeast-southwest trend of thick SMS deposition situated medially. The distribution of those sweet spots is predictable by mapping paleotopographic funneling mechanisms, and understanding how relative sea level controls facies distribution and how paleotopography controls sediment dispersal and geometries. These controls are broadly applicable across areas of the Permian Basin.
Proper characterization of heterogeneous rock properties and hydraulic fracture parameters is essential for optimizing well spacing and reliable estimation of EUR in unconventional reservoirs. High resolution characterization of matrix properties and complex fracture parameters requires efficient history matching of well production and pressure response. We propose a novel reservoir model parameterization method to reduce the number of unknowns, regularize the ill-posed problem and enhance the efficiency of history matching of unconventional reservoirs.
Our proposed method makes a low rank approximation of the spatial distribution of reservoir properties taking into account the varying model resolution of the matrix and hydraulic fractures. Typically, hydraulic fractures are represented with much higher resolution through local grid refinements compared to the matrix properties. In our approach, the spatial property distribution of both for matrix and fractures is represented using a few parameters via a linear transformation with multiresolution basis functions. The parameters in transform domain are then updated during model calibrations, substantially reducing the number of unknowns. The multiresolution basis functions are constructed by eigen-decomposition of an adaptively coarsened grid Laplacian corresponding to the data resolution. High property resolution at the area of interest through the adaptive resolution control while keeping the original grid structure improves quality of history matching, reduces simulation runtime and improves the efficiency of history matching.
We demonstrate the power and efficacy of our method using synthetic and field examples. First, we illustrate the effectiveness of the proposed multiresolution parameterization by comparing it with traditional method. For the field application, an unconventional tight oil reservoir model with a multi-stage hydraulic fractured well is calibrated using bottom-hole pressure and water cut history data. The hydraulic fractures as well as the stimulated reservoir volume (SRV) near the well are represented with higher grid resolution. In addition to matrix and fracture properties, the extent of the SRV and hydraulic fractures are also adjusted through history matching using a Multiobjective Genetic Algorithm. The calibrated ensemble of models are used to obtain bounds of production forecast.
Our proposed method is designed to calibrate reservoir and fracture properties with higher resolution in regions that have improved data resolution and higher sensitivity to the well performance data, for example the SRV region and the hydraulic fractures. This leads to a fast and efficient history matching workflow and enables us to make optimal development/completion plans in a reasonable time frame.
Rostami, Ameneh (The University of Texas at Austin) | Jagadisan, Archana (The University of Texas at Austin) | Hernandez, Laura M. (The University of Texas at Austin) | Heidari, Zoya (The University of Texas at Austin) | Fairhurst, Bill (Bureau of Economic Geology) | Yurchenko, Inessa (Bureau of Economic Geology) | Ikonnikova, Svetlana (Bureau of Economic Geology) | Hamlin, Scott (Bureau of Economic Geology)
Complexities in petrophysical and compositional properties as well as significant spatial heterogeneity of rock properties make formation evaluation challenging in organic-rich mudrocks. Conventional methods often overlook the importance of integrated rock classification for evaluation of formation properties, resulting in high uncertainties in estimates of mineralogy, porosity, fluid saturations, and total organic carbon content (TOC). The objectives of this paper include (a) developing an iterative workflow to simultaneously enhance formation evaluation and rock classification, (b) using the estimates of petrophysical, compositional, geochemical, and mechanical properties for completion-oriented rock classification to improve production decisions, and (c) using field-scale geostatistical analysis to extend the introduced workflow to neighboring wells without core measurements and minimizing model calibration efforts, while maintaining reliable formation evaluation results.
First, we perform a joint inversion of well logs for depth-by-depth estimation of volumetric concentrations of minerals, porosity, TOC, mechanical properties, and fluid saturations by integrating information about thermal maturity and core/well-log measurements. These initial estimates are used for a preliminary petrophysical rock classification. Model parameters are updated in each rock class and are used in the second iteration for a class-by-class-based assessment of petrophysical, compositional, and mechanical properties. Spatial geostatistical analysis of formation properties is then used to select the range of neighboring wells where the developed models in each rock type is reliable. This iterative procedure is repeated until convergence of petrophysical/compositional properties in two subsequent iterations or agreement with core measurements (if available) is achieved. Finally, we perform an integrated completion-oriented rock classification to determine the best rock types for completion.
We successfully applied the proposed workflow to more than 100 wells in 20 different counties in the Midland Basin, 7 of which contained core and geochemical data. Results showed that the iterative workflow significantly improved estimates of TOC, porosity, and water saturation by approximately 56%, 28%, and 53% respectively, compared to a conventional method. Results also confirmed that the proposed workflow significantly enhances the formation evaluation and enables reliable reservoir characterization and completion decisions in organic-rich mudrocks. Integrated geostatistical analysis, rock classification, and the advanced iterative formation evaluation workflow, is a novel approach which enables (a) reliable application of the developed rock physics models to wells with no core data or ECS logs and (b) incorporation of spatial heterogeneity of the formation for a reliable field-scale reservoir characterization.
Fu, Qinwen (University of Kansas) | Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Li, Xiaoli (University of Kansas) | Peltier, Karen (University of Kansas - Tertiary Oil Recovery Project (TORP)) | Mohrbacher, David (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy)
Fracture complexity, phase behavior, lithological variations and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research was conducted to define diffusion coefficients coupled with the rock tortuosity. The objective of this work is to conduct a comprehensive experimental and simulation study on Lower Eagle Ford rock samples to measure the diffusion coefficients for different injection cycles in three representative litho-facies.
Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and the effluent oil and gas composition were measured. NMR measurement was repeated at the end. A compositional simulation model was set up using tortuosity values from FIB-SEM analysis to simulate the experimental diffusion and production. History matching on pressure and production results was conducted and diffusion coefficients were estimated for one representative sample.
Pressure profiles vary significantly between different cycles due to different effective diffusion coefficients. This may be caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Diffusion coefficients, represented by pressure drop during the soaking time, vary across different litho-facies and for different cycles. For the produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate and heavier components increased.
Gas huff-n-puff injection into shale oil reservoirs is being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments show favorable results, using constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, the recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively. The history matched oil diffusion coefficients are in the range of ten to the power of negative seven, and are in close relation with the remaining oil composition.
Biological monitoring is the continued examination of biological specimens taken from a specific environment to identify any human-caused issues. In the oil and gas industry, biological monitoring programs provide important data for decision making and to ensure the protection of resources and ecosystems. To evaluate ecosystems, flora, fauna, arthropods, birds, small mammals, and other species are examined within specific sampling zones to determine the effect on their respective habitats and density within those habitats. Tissue samples are analyzed to determine the effect of chemicals on specific species. Air, water, and soil samples are tested for signs of environmental toxicity. Based on findings from data collected, a plan is then created to prevent potential or further damage to the zones affected by the drilling area.
Pioneer shut in 8,000 BOE/D production in its West Panhandle field in Texas on 6 March due to a compression station fire. Planning to use idle compressors, production is expected to restart later this month or in early April. As compressor stations are added to the natural gas gathering and transmission networks, the potential noise issues are coming under increasing public scrutiny at the same time as regulations are being rolled back.