Thesis (Ph. D.)--University of Texas at Austin, 2004. / Available also in an electronic version.

<p> The objective of this study is threefold: 1) Build a dual-porosity, geological reservoir model of Niobrara formation in the Wishbone Section of the DJ Basin. 2) Use the geologic static model to construct a compositional model to assess performance of Well 1N in the Wishbone Section. 3) Compare the modeling results of this study with the result from an eleven-well modeling study (Ning, 2017) of the same formation which included the same well. The geologic model is based on discrete fracture network (DFN) model (Grechishnikova 2017) from an outcrop study of Niobrara formation.</p><p> This study is part of a broader program sponsored by Anadarko and conducted by the Reservoir Characterization Project (RCP) at Colorado School of Mines. The study area is the Wishbone Section (one square mile area), which has eleven horizontal producing wells with initial production dating back to September 2013. The project also includes a nine-component time-lapse seismic. The Wishbone section is a low-permeability faulted reservoir containing liquid-rich light hydrocarbons in the Niobrara chalk and Codell sandstone.</p><p> The geologic framework was built by Grechishnikova (2017) using seismic, microseismic, petrophysical suite, core and outcrop. I used Grechishnikova&rsquo;s geologic framework and available petrophysical and core data to construct a 3D reservoir model. The 3D geologic model was used in the hydraulic fracture modeling software, GOHFER, to create a hydraulic fracture interpretation for the reservoir simulator and compared to the interpretation built by Alfataierge (2017). The reservoir numerical simulator incorporated PVT from a well within the section to create the compositional dual-porosity model in CMG with seven lumped components instead of the thirty-two individual components. History matching was completed for the numerical simulation, and rate transient analysis between field and actual production are compared; the results were similar. The history matching parameters are further compared to the input parameters, and Ning&rsquo;s (2017) history matching parameters.</p><p> The study evaluated how fracture porosity and rock compaction impacts production. The fracture porosity is a major contributor to well production and the gas oil ratio. The fracture porosity is a major sink for gathering the matrix flow contribution. The compaction numerical simulations show oil production increases with compaction because of the increased compaction drive. As rock compaction increases, permeability and porosity decreases. How the numerical model software, CMG, builds the hydraulic fracture, artificially increases the original oil-in-place and decreases the recovery factor. Furthermore, grid structure impacts run-time and accuracy to the model. Finally, outcrop adds value to the subsurface model with careful qualitative sedimentology and structural extrapolations to the subsurface by providing understanding between the wellbore and seismic data scales.</p><p>

<p> In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale. </p><p> Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10^&ndash;1&ndash;10^&ndash;2 mD) and in the vertical direction (~10^&ndash;4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^&ndash;5 to 10^&ndash;8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation. </p><p> Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.</p><p>

<p> To efficiently produce oil from unconventional reservoirs, it is imperative to determine and understand the geomechanical properties of the formation. But, due to the high cost of obtaining these properties from geomechanical well logs, businesses are looking for all possible ways to cut cost. The plummeting oil prices have been reflected in company spending and have driven companies to prioritize focusing attention on the rising production costs and venture all possible ways to reduce these costs. The real challenge is how to preserve these profitable gains? There is a need for an alternate and cost- effective way to obtain geomechanical properties of the rocks. </p><p> By utilizing Data Analytics, Data Mining, and ANN, patterns are observed between parameters from large amounts of data and, thus, important information regarding the formation can be understood. In this study, a relationship between conventional well logs and geomechanical well logs are established. Properties such as Young&rsquo;s Modulus, Poisson&rsquo;s Ratio, Shear Modulus, Bulk Modulus, and Minimum Horizontal Stress are determined from Conventional Logs such as Gamma Ray and Density Log utilizing ANN. Ultimately, data-driven models are developed to predict accurate geomechanical properties for future wells of the Upper and Middle Bakken Formation. Finally, the efficacy of the data-driven models achieved is tested on randomly selected new wells that were not used in the training of the model. The accurate prediction and analysis of these properties help in better reservoir characterization and efficient production from the future wells in the Bakken Formation.</p><p>

No description available.

The Hecate sub-basin is one of two similar sedimentary structures comprising Queen Charlotte Basin, which is located between the British Columbia mainland and the Queen Charlotte Islands. The Queen Charlotte Basin was the locale of an active but unsuccessful exploration program, including drill holes, in the 1960's. However, recent studies incorporating modern concepts of plate tectonics have indicated a re-evaluation of the resource potential of the area is warranted. The Hecate sub-basin and its southern counterpart, the Charlotte sub-basin, are filled with Tertiary sediments that are underlain by a thick sequence of Tertiary volcanics. Penetration of the latter unit using the reflection method has been difficult. Thus the thickness of the volcanics and the existence or not of more sediments below them has not been established. To address this problem an airgun/ocean bottom seismograph (OBS) refraction survey was carried out across the Hecate sub-basin in 1983. Data from the airgun shots at approximately 160 m spacings were recorded on four OBSs deployed at 20 km intervals to provide a series of reverse profiles extending over 60 km. The principal interpretation procedure involved calculation of theoretical seismograms and travel-time curves for 2-D velocity structure models and comparisons with observed record sections. The interpreted structure model shows significant lateral variations. Low velocity Pleistocene and Pliocene sediments form an upper layer varying between 0.5 and 1.0 km thick. The principal sedimentary unit is the Tertiary Skonun Formation with interpreted velocities of 2.7 km/s and a gradient averaging 0.4 km/s/km, values that are consistent with well log data. These sediments are generally thicker (approximately 2.5 km) on the western side of the sub-basin although they reach their maximum thickness of 3 km in a depression near the central part of the basin. Toward the eastern side of the basin, the Tertiary sediments thin to about 1 km as the underlying Tertiary volcanics rise toward the mainland. The maximum sediment thickness in the basin is about 4 km. The upper surface of the volcanic unit shows a pronounced topography which is consistent with the erosional nature of this surface. Velocities for the volcanics vary between 4.8 and 5.0 km/s; thickness of the unit ranges from about 0.2 km to 1.8 km. Below the Tertiary volcanics on the eastern 20 km of the model, a low velocity zone less than 1 km thick had to be introduced to satisfy the data. This zone is inferred to contain Upper Cretaceous sediments. A unit with a poorly constrained velocity of 5.9 km/s which underlies the Tertiary volcanics and low velocity zone on the eastern side is interpreted to be the Paleozoic Alexander Terrane. Most of the characteristics of this model are similar to those determined from an earlier study in the Charlotte sub-basin. An additional component of this thesis project was the development of an interactive procedure for the inversion of densely spaced seismic refraction data by wavefield continuation to derive a l-D velocity-depth profile, and its application to data derived from 2-D structures. The procedure consists of two steps: a slant stack followed by a downward continuation. The method was found to yield velocity-depth structures which, when compared with an average velocity-depth structure from the 2-D model, have very similiar gradients and velocity increases. In general the velocity depth curve from the inversion had lower velocities at deeper depths than the averaged 2-D structure. / Science, Faculty of / Earth, Ocean and Atmospheric Sciences, Department of / Graduate

No description available.

Master of Science / Department of Geology / Sambhudas Chaudhuri and Matthew Totten / The current model of hydrocarbon generation involves the thermogenic maturation of organic material as a consequence of burial. This process only considers energy generated from temperature increase due to burial. The majority of organic rich source beds contain high concentrations of radioactive elements, hence the energy produced from radioactive decay of these elements should be evaluated as well. Previous experiments show that α-particle bombardment can result in the generation of hydrocarbons from oleic acid. This study investigates the effects of γ-rays in a natural petroleum generating system. In order to determine the effects of γ-rays, experiments were conducted using cesium-137 as the γ-ray source at the KSU nuclear facilities to irradiate crude oil and organic material commonly found in petroleum systems. The samples were then analyzed using Fourier Transform Infrared Spectroscopy (FTIR) and Rock-Eval pyrolysis to determine changes in the samples. The FTIR results demonstrated that γ-radiation can cause the lengthening and/or shortening of hydrocarbon chains in crude oils, the dissociation of brine (H2O (aq)), the production of free radicals, and the production of various gases. These changes that come from γ-radiation hold the possibilities to distort the configuration of organic molecules, dissociate molecular bonds, and trigger oxidation-reduction reactions, all of which could provide an important step to the onset of dissociation necessary to create hydrocarbons in petroleum systems. Further understanding the effects of γ-radiation in hydrocarbons systems could lead to more information about the radiolytic processes that take place. This could eventually lead to further understanding of oil generation in organic-rich source beds.

Master of Science / Department of Geology / Matthew Totten / Jackson County, Kansas is situated on the west side of the Forest City Basin, location of the first oil discovery west of the Mississippi River (KGS), Production in the area is predominately from the Viola Limestone, and a noticeable trend of oil fields has developed where the basin meets the Nemaha Anticline. Exploration has been sluggish, because of the lack of an exploration model. Production rates have varied widely from well to well, even when they are structurally equivalent. The goal of this study was to determine the factors controlling reservoir quality in the Ordovician-aged Viola Limestone so that a better exploration model could be developed. A two township area was studied to examine relationships between subsurface variations and production rates. In the absence of an available core through the Viola, drill cuttings were thin-sectioned and examined under a petrographic microscope to see the finer details of porosity, porosity type and dolomite crystal-size that are not visible under a binocular microscope. Production appears to be controlled by a combination of structural position and dolomite crystal size, which was controlled by secondary diagenesis in the freshwater-marine phreatic mixing zone. The best wells exhibited a Viola Limestone made up of 100% very coarsely crystalline, euhedral dolomite crystals. These wells occur on the east and southeast sides of present day anticlines, which I have interpreted to be paleo-highs that have been tilted to the east-southeast.

The offshore Sierra Leone basin is an exploration frontier area with commercial hydrocarbon potential. The basin is located at the northernmost end of the equatorial Atlantic margin in the South Atlantic; it is bound to the South by the Gulf of Guinea Petroleum province. The Sierra Leone margin has not had the exploration attention like most basins in the equatorial Atlantic, such lack of attention may be explained by the structural complexity of the basin. Despite the recent successful petroleum activities in the basin, very little geological information have been placed in the public domain by the operators. This research will be the first published detailed analysis of the offshore Sierra Leone basin. This work focuses on the broader aspects of basin structural evolution, seismic stratigraphy and reservoir development. The basin analysis is based on 2D seismic dataset, acquired in 2002 by TGS-NPEC. Seven megasequence boundaries have been identified in the offshore Sierra Leone basin. There is one megasequence boundary each in the pre-transform and syn-transform phases. The post-transform phase is composed of five megasequences. They have been dated using well data information and through correlation with the seismic surfaces of adjacent basins in the region. The Sierra Leone margin is structurally divided into three segments, which evolved through transtensional and/or extensional rifting. From a geological perspective, this basin straddles a major tectonic transition zone (the Sierra Leone Transform). The Mesozoic-Cenozoic tectonic evolution of the basin was partly controlled by basement heterogeneity and plate kinematics. This study also highlights the importance of N-S and ENE-WSW trending Archaean structural lineaments, which were vectors for the Sierra Leone margin segmentation. The structural division of the Sierra Leone margin into the Northern, Central andSouthern segments is based on varying structural geometries. The Northern and Central segments developed as rift-transform margins, while the Southern segment developed as a volcanic rifted margin. Syn-transform sequences (late Early Cretaceous) show the influence of normal fault related subsidence and uplift, modified by localised transpressional deformation. The basin bounding faults and half grabens are oriented at high angles to the ensuing passive margin slope strike. Post-transform sequences (Late Cretaceous to Present) are dominated by major phases of slope failure and the development of extensive lowstand submarine fan systems. Some models of slope failure and synchronous development of submarine channel and canyon systems have been developed for this basin. Extensional slope failure is controlled by pre-existing structural trends. Submarine canyons which developed in the hanging-walls of these fault-blocks, became the site of rapid head-ward expansion of turbidite filled channels. The temporal development of these systems are expected to have profoundly affected the distribution and quality of key play elements, such as reservoirs and stratigraphic traps in slope settings, and the distribution of sands in deeper water and base of slope plays.