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Denver, CO, United States

Zargari S.,Colorado School of Mines | Canter K.L.,Whiting Petroleum Corporation | Prasad M.,Colorado School of Mines
Fuel | Year: 2015

The origin of porosity and mechanisms of fluid flow in the presence of organic matter and clay minerals in source rocks are poorly understood. Burial and maturation of the source rock modify or create the pore systems in these rocks. Kerogen decomposition and consequent shrinkage may change the load bearing state of the minerals and organic matter and affect pore system since early stages of maturation. Geochemical evidence confirms that the hydrocarbon expulsion process (i.e. primary migration) is not 100% efficient. Expulsion of hydrocarbon is mainly driven by (1) pressure increase in the source rock due to solid kerogen conversion and volume increase and (2) continued compaction of the sediment. Converted organic matter is partly retained in the source rock diverse framework constituents. Quantitative measurement of and determining producibility of the retained hydrocarbon in the source rock is to date highly debated. The source rock hydrocarbon storage capacity is controlled by pore-hosting particles, pore system topology and rock-fluid interactions. The presence of organic matter and clay minerals affect log responses by generally overestimating porosity, because the low density kerogen is not accounted for, and together with low resistivity caused by presence of clay minerals can result in erroneous saturation calculations; thus, accurate reserve estimation often is challenged if the impact of low organic matter density is not explicitly addressed. In order to understand porosity evolution and the interaction of organic byproducts (i.e. bitumen and pyrobitumen) with rock minerals during thermal maturation, one must study source rock samples with different maturities. For this reason, ten Bakken Shale samples with varying maturity and mineralogy were selected in this study. Pore size distributions (PSD), specific surface areas (SSA) and geochemical characteristics of the samples were measured in native state and after successive solvent extraction. The PSD and SSA measured after each extraction shows recovery of the pore system with successive cleaning. Most significant was the recovery of kerogen-hosted pores with removal of soluble, oil-like organic material. Using successive extractions we are able to determine the evolution of organic matter porosity through maturation which is otherwise not feasible using visual techniques or other conventional laboratory procedures. © 2015 Published by Elsevier Ltd.

Curnow J.S.,Whiting Petroleum Corporation | Tutuncu A.N.,Colorado School of Mines
Society of Petroleum Engineers - SPE Hydraulic Fracturing Technology Conference, HFTC 2016 | Year: 2016

The benefits of hydraulic fracturing horizontal wells in unconventional reservoirs for production enhancement are evident; however, the best methods to truly increase recovery efficiency through these stimulations are still under examination. Analogous to how operators and service companies discovered that Barnett-style slickwater treatments were not successful in all reservoirs, companies are beginning to recognize the importance of engineered stimulations, specifically in regard to geomechanics. Rather than perforating for only production purposes, hydraulic fracturing design has now turned its focus to perforating for reservoir rock stimulation. Enhanced fracture network complexity through induced fractures greatly increases the contact area and reservoir drainage for maximum productivity. However, to accomplish the stimulation of both primary and secondary fracture networks, the coupled behaviors of geomechanics and fluid flow in response to the hydraulic fracturing operations must be considered. In this research study, development of a coupled geomechanics and fluid flow model for the purpose of hydraulic fracture design optimization through the evaluation of different stimulation patterns with primary focus on how the stress and strain distributions within the reservoir that affect porosity and permeability, ultimately influence flow has been discussed in detail. The patterns under consideration include the Zipper, Texas Two-Step, and Modified Zipper designs. Although the Texas Two-Step Pattern requires a special down-hole tool and as such is very difficult operationally to perform, it is being considered in this analysis for conceptual purposes concerning the stress behavior within a single lateral well. Furthermore within these patterns, the well locations and hydraulic fracture properties have been analyzed to determine the optimum design for a shale oil reservoir based on recovery efficiency and generated fracture complexity. The results of this study indicate that with the staggered fracture placement offered by the Modified Zipper Pattern, a highly conductive secondary complex fracture network is generated allowing for enhanced hydrocarbon recovery. In comparison to the Zipper and Texas Two-Step Patterns, the Modified Zipper Pattern reduces the stress anisotropy within the formation to a much greater extent, aiding in the fracture generation process to increase the flow area. This advantage coupled with its high oil recovery factor and potential for greater drilling density discerns the Modified Zipper as the ideal pattern for the development of an Eagle Ford-Type shale oil reservoir. Copyright 2016, Society of Petroleum Engineers.

Chitale V.D.,Reservoir Evaluation Services | Johnson C.,and Hills Inc. | Entzminger D.,Whiting Oil and Gas Corporation | Canter L.,Whiting Petroleum Corporation
AAPG Memoir | Year: 2010

This chapter presents the results of field testing a modern generation wireline electrical borehole imager together with a new borehole image interpretation technique applied in a development well drilled in the Permian Basin, Texas. The borehole imager is designed so as to acquire superior quality images even under conditions of a very high ratio of formation resistivity to mud resistivity (Rt:Rm) ratio, which enhances the quality of formation evaluation of carbonate reservoirs particularly. A new borehole image interpretation technique was developed specifically to evaluate the porosity and permeability of carbonate reservoirs by integrating high-resolution data from an electrical borehole image log with the conventional wireline logs. As shown in the chapter, the X-tended Range Micro Imager (XRMI™, manufactured by Halliburton) with improved signal-to-noise ratio and expanded dynamic range was able to yield a high-resolution microconductivity signal. This helped generate very high-resolution borehole images showing millimeter-size features in the fabric of carbonate beds. The microconductivity signal was then analyzed with the help of a newly developed software technique that first equates the total signal with total porosity, which is then resolved into fractions correctable with micro-, primary, and secondary porosity. The new technique of image interpretation treats permeability based on published petrophysical models of equating rock types in carbonates with porosity types. Integrated analysis of XRMI and other logs from a Whiting Oil and Gas Corporation well drilled in the Wolfcampian carbonate reservoir in the Permian Basin of the United States shows that facies and layer boundaries, the internal fabric of the carbonates, and the estimates of different porosity fractions and permeability determined using the new imager and the new interpretation technique closely follow the core descriptions and laboratory analysis of porosity and permeability. These results are encouraging because the single well correlation(s) will be applicable in the future to newly drilled wells in similar geological facies in locations without core control. Copyright © 2010 by The American Association of Petroleum Geologists.

Guthrey H.,National Renewable Energy Laboratory | Johnston S.,National Renewable Energy Laboratory | Weiss D.N.,Scifiniti | Weiss D.N.,First Solar | And 6 more authors.
Solar Energy | Year: 2016

In this contribution, we demonstrate the value of using a multiscale multi-technique characterization approach to study the performance-limiting defects in multi-crystalline silicon (mc-Si) photovoltaic devices. The combination of dark lock-in thermography (DLIT) imaging, electron beam induced current imaging, and both transmission and scanning transmission electron microscopy (TEM/STEM) on the same location revealed the nanoscale origin of the optoelectronic properties of shunts visible at the device scale. Our site-specific correlative approach identified the shunt behavior to be a result of three-dimensional inversion channels around structural defects decorated with oxide precipitates. These inversion channels facilitate enhanced minority-carrier transport that results in the increased heating observed through DLIT imaging. The definitive connection between the nanoscale structure and chemistry of the type of shunt investigated here allows photovoltaic device manufacturers to immediately address the oxygen content of their mc-Si absorber material when such features are present, instead of engaging in costly characterization. © 2016.

Rodrigues P.E.,Whiting Petroleum Corporation | Batzle M.L.,Colorado School of Mines
Geophysics | Year: 2015

Although heavy oils are an enormous resource and a common seismic monitoring target, their geophysical properties remain poorly understood. The shear modulus is of particular interest, because under the right conditions, these oils can transmit S-waves. However, there is a large uncertainty on how to measure the shear modulus of heavy oils. The use of the rheometer, common in chemical engineering applications, has been proposed as a good alternative to tension/compression techniques. Rheometers are an attractive alternative for measuring the shear modulus because of their widespread use and availability. In order to test the validity of the rheometer as a method to measure the shear modulus of heavy oils for geophysical applications, we tested two samples using techniques familiar to geophysics (tension/ compression and ultrasonic) and compared the results with the rheometer measurements. We noticed a difference in the measured shear modulus between the two techniques. The samples showed a solid-like behavior when tested in the tension/ compression equipment while behaving liquid-like in the rheometer. Both measurements were done in the linear regime (in which there is no change in modulus with amplitude), indicative of the potential presence of two linear viscoelastic regimes (LVRs) at different amplitudes. We developed a model that explains the presence of the two LVRs for heavy oils with a large content of resins and asphaltenes and at temperatures that allows the formation of large aggregates. We analyzed the presence of the two LVRs in terms of the weak interaction that appeared between aggregates when subjected to small-amplitude strains, resulting in a solid-like behavior; those weak interactions were not present when the sample was subjected to larger strains resulting in a liquid-like behavior. © 2015 Society of Exploration Geophysicists.

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