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Collaborating Authors
Permian Basin
Summary Permeability provides a measure of the ability of a porous medium to transmit fluid and is significant in evaluating reservoir productivity. A case study that compares different methods of permeability prediction in a complex carbonate reservoir is presented in this paper. Presence of siliciclastic fines and diagenetic minerals (e.g. dolomite) within carbonate breccias has resulted in a tight and heterogeneous carbonate reservoir in this case. Permeability estimations from different methods are discussed and compared. In the first part of the paper, permeability measurements from conventional core analysis (CCAL), mercury-injection capillary pressure (MICP) tests, modular formation dynamic tests (MDTs), and nuclear-magnetic-resonance (NMR) logs are discussed. Different combinations of methods can be helpful in permeability calculation, but depending on the nature and scale of each method, permeability assessment in heterogeneous reservoirs is a considerable challenge. Among these methods, the NMR log provides the most continuous permeability prediction. In the second part of the paper, the measured individual permeabilities are combined and calibrated with the NMR-derived permeability. The conventional NMR-based free-fluid (Timur-Coates) model is used to compute the permeability. The NMR-estimated permeability is influenced by wettability effects, presence of isolated pores, and residual oil in the invaded zone. A new modified Timur-Coates model is established on the basis of fluid saturations and isolated pore volumes (PV) of the rock. This model yields a reasonable correlation with the scaled core-derived permeabilities. However, because of the reservoir heterogeneity, particularly in the brecciated intervals, discrepancies between the core data and the modified permeability model are expected.
- North America > United States > Texas (1.00)
- Europe > Norway (0.93)
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Dolomite (0.34)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Word Group > San Andreas Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin > Yates Field > Whitehorse Group > Grayburg Formation > San Andreas Formation (0.99)
- Europe > Norway > Barents Sea > Snadd Formation (0.99)
- (2 more...)
Mineralogy and Petrophysical Evaluation of Roseneath and Murteree Shale Formations, Cooper Basin, Australia Using QEMSCAN and CT-Scanning
Ahmad, Maqsood (Australian School of Petroleum, The University of Adelaide, SA 5005, Australia) | Haghighi, Manouchehr (Australian School of Petroleum, The University of Adelaide, SA 5005, Australia)
Abstract It is found that in the deepest part of Cooper Basin (Permian section in Nappamerri Trough) in South Australia, two shale formations, Roseneath and Murteree have potential to be shale gas reservoirs. However, a comprehensive petrophysical evaluation has not been carried out so far. The free porosity among minerals, pore throat geometry, surface area and structure of micro pores for adsorption and diffusion of gas in these formations have not been well understood. Two core samples from two wells (Della 4 and Moomba 46) were selected to evaluate mineralogy, free porosity and other petrophysical characterization. Since routine core analysis is not capable of petrophysical characterization of these very tight rocks, the latest technology of image scanning and processing of QEMSCAN (Quantitative Evaluation of Minerals using Scanning Electron Microscopy) and Computerized Tomography (CT) scanning have been used. QEMSCAN is a novel technology to process images from electron microscope to measure size and distribution of different minerals in a rock sample. QEMSCAN when combined with CT scanning can significantly enhance shale rock characterization and reservoir quality assessment. In this study, the main goal is the evaluation of total free porosity, micro pores and natural network of micro-fracture systems in our ultra fine samples. Based on QEMSCAN analysis, it is found that the sample of Murteree shale has the mineralogy of quartz 42.78%, siderite 6.75%, illite 28.96%, koalinite 14.09%, Total Organic Content (TOC) 1.91 wt%, and pyrite 0.04%, while rutile and other silicates minerals were identified as accessory minerals. Total free porosity is found to be 2 percent. The free porosity is largely associated with clay minerals which shows intergranular linear, isolated and elongated wedge shaped pores. SEM images from the same core sample also show that the pores are mainly present in clay rich zone. QEMSCAN maps have revealed the location of lamination, high and low porosity zones as well as high and low sorption areas. In CT scanning, the porosity found in QEMSCAN, was not identified; however, a network of micro-fracture system in Murteree shale sample is identified.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate (1.00)
- Oceania > Australia > South Australia > Cooper Basin > Roseneath Formation (0.99)
- North America > United States > Utah > Paradox Basin (0.99)
- North America > United States > Colorado > Paradox Basin (0.99)
- (36 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Core analysis (1.00)
Abstract: Heterogeneity of the resource-shale plays and limited knowledge about the shale petrophysical properties demand detailed core-scale characterization in order to understand field-scale measurements that have poor vertical resolution. Analyses of a set of laboratory measured petrophysical properties collected on 300 samples of the Woodford Shale from 6 wells provided an opportunity to track changes in petrophysical properties in response to thermal maturity and their effect on hydrocarbon production. Porosity, bulk density, grain density, mineralogy, acoustic velocities (Vp-fast, Vs-fast and Vs-slow), mercury injection capillary pressure along with total organic carbon content (TOC), Rock-Eval pyrolysis, and vitrinite reflectance were measured. Visual inspections were made at macroscopic-, microscopic- and scanning electron microscope-scale (SEM) in order to calibrate rock-petrophysical properties with the actual rock architecture. Mineralogically, the Woodford Shale is a silica-dominated system with very little carbonate presence. Crossplot of porosity and TOC clearly separate the lower thermal maturity (oil window) samples from higher thermal maturity (wet gas-condensate window) as porosity is lower at lower thermal maturity. Independent observations made through SEM-imaging confirm much lower organic porosity at lower thermal maturity while organic pores are the dominant pore types in all samples irrespective of thermal maturity. Crack-like pores are only observed at the oil window. Cluster analyses of TOC, porosity, clay and quartz content revealed three clusters of rocks which could be ranked as good, intermediate and poor in terms of reservoir quality. Good correlations between different petro-types with geological core descriptions, along with the good conformance between different petro-types with production data ascertain the practical applicability of such petro-typing. Introduction The Woodford Shale has long been known as the source of most of Oklahoma's hydrocarbon reserves until it emerged as resource play following the huge success of the Barnett Shale play in 2005.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (14 more...)
Reservoir Description Of The Subsurface Eagle Ford Formation, Maverick Basin Area, South Texas, USA
Driskill, Brian (Shell Exploration and Production Company) | Suurmeyer, Nathan (Shell Exploration and Production Company) | Rilling-Hall, Sarah (Shell Exploration and Production Company) | Govert, Andrew (Shell Exploration and Production Company) | Garbowicz, Amy (Shell Exploration and Production Company)
Abstract The Cretaceous Eagle Ford Formation (EF) is a marl deposited during a highstand on a broad shelf along the paleo-Texas coast. In south Texas, the EF is thickest in the Maverick Basin, which is a small sag related to crustal thinning. Extensive datasets were collected to use in subsurface studies that support exploration and development activities, including core, cuttings, chemostratigraphy, biostratigraphy, and well logs. Computed X-ray tomography (CT) scans, thin sections, scanning electron microscopy (SEM) images, focused ion beam-SEM (FIB-SEM) volumes, and X-ray diffraction/X-ray fluorescence (XRD/XRF) tables were acquired from whole core and cuttings. The goal of the integrated study was to understand EF depositional processes and rock textures, and to create a predictive model for reservoir properties. The regional EF study began with a correlation of 400+ wireline logs. The correlation involved a stratigraphic framework that was initially based on log character, and was then refined with ash correlations, biostratigraphy data, and chemostratigraphy data. Textural information seen in core, core CT scans, and the SEM/FIB-SEM work was compared to the framework. The data gave insights into patterns of fluctuating oxygen and energy levels in the EF, which were then included into an idealized depositional model. The datasets show regional patterns of composite cycles in which properties such as TOC, porosity, carbonate content, and rock texture are predictable. SEM/FIB-SEM images show that pores in the EF are mainly intergranular or within organic matter (OM), and that the structure of OM pores is related to maturity level. Reservoir properties can be predicted along the EF trend using the SF. Cycles of the EF with good reservoir properties can be mapped with respect to hydrocarbon fluid zones to yield risk maps. Combining biostratigraphical, sedimentological, chemical, and physical properties is the key to understanding depositional cycles and cycle architecture. Geographic and stratigraphic sweet spots for well productivity can then be predicted by understanding how and where different parts of a cycle are stacked. As each unconventional play is unique, what works for reservoir characterization and risk mapping in one play is not necessarily applicable to another. However, developing an understanding of the interaction of the main reservoir properties should lead to less uncertainty, particularly in areas of the play with few existing wells.
- Geology > Sedimentary Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (1.00)
- Geology > Geological Subdiscipline > Stratigraphy > Biostratigraphy (0.88)
- (2 more...)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Delaware Basin (0.99)
- (27 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)