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Results
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...)
Abstract: Unconventional shale reservoirs have gained significant importance in the recent years in terms of reserves and production perspective. The formation evaluation aspect of these reservoirs is still in the phase of continuous evolvement. There are several petrophysical models that have been proposed for the shale plays ranging from volumetric solutions by reproducing the measured logs to applying conventional techniques like Archie, Simandoux, etc. In this paper we propose a new physically consistent solution based on partitioning the system into kerogen and non-kerogen domains with their associated porosities. These domains are not simply an arbitrary construct: they are directly suggested by the nano-scale images that have been acquired for these shale plays. The new model follows an approach that have been used in the past for understanding other systems in which there is a heterogeneity at a scale significantly finer than the measurements. The model is based on the premise that the hydrocarbon phase occupies the kerogen-related porosity with water occupying the non-kerogen matrix porosity thereby eliminating the need to compute saturations using conventional methods. The innovative aspect to this approach is that the new model solves for the kerogen porosity created by the organic diagenesis and constrained by physically meaningful bounds. The model also successfully explains industry standard approach such as Schmoker's equation. The model has been successfully applied across all shale plays in North America and drives the data acquisition program for the unconventional shale plays. Introduction Unconventional shale plays are characterized by complex pore systems. These reservoirs usually fall under the category of reservoirs that requires hydraulic stimulation to make economic rates. The proper evaluation of shale gas reservoirs draws upon and extends the range of technologies that have been applied to clastics and carbonates as well as in source rock evaluation (Vivian, 2011).
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.95)
ABSTRACT: This paper reviews and compares three recently published approaches for simplicity, validity, and parameter sensitivity. The first two approaches are based on deterministic models; the third approach uses a response equation technique in which models are defined by means of tool response equations and interpretation constraint equations. The first approach assumes that the weight fraction total organic carbon (TOC) is available from an external source, the rock grain density is known, and total water saturation is constant. This enables for the first approach the use of a single equation based upon the bulk density log to solve for total porosity from which the gas-filled porosity can be obtained with the assumption of constant water saturation. The second approach assumes that the formation consists of two constituents: porous mineral matrix and porous kerogen. It makes use of the fact that in gas shale, kerogen generally contains oil-wet porosity, so that constant kerogen porosity, completely gas saturated, is imposed. The volumes of porous mineral matrix, porous mineral kerogen, and porous mineral porosity can be obtained by using the sonic and density logs with an assumed known rock grain density and assuming the porous mineral matrix gas saturation is a constant. The assumption of constant porous mineral gas saturation can be relaxed by iteratively using the resistivity log to update the assumed value of the hydrocarbon saturation. This paper shows that Methods 1 and 2 can be replicated by using a response equation based statistical optimization technique. This technique requires some simple constraints, such as constant kerogen porosity or constant gas saturation. Moreover, the constant saturation assumptions can be easily removed, and it is possible to calibrate to core grain density and gas-filled porosity with or without wireline geochemical data, TOC, or x-ray diffraction (XRD) mineral data.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Silicate (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.64)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.46)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- (11 more...)