The estimation of porosity, water saturation, kerogen concentration, and mineral composition is an integral part of unconventional shale reservoir formation evaluation. Porosity, water saturation, and kerogen content determine the amount of hydrocarbon-in-place while mineral composition affects hydro-fracture generation and propagation. Effective hydraulic fracturing is a basic requirement for economically viable flow of gas in very-low permeability shales. Brittle shales are favorable for initiation and propagation of hydraulic fracture because they require marginal or no plastic deformation. By contrast, ductile shales tend to oppose fracture propagation and can heal hydraulic fractures. Silica and carbonate-rich shales often exhibit brittle behavior while clay-rich shales tend to be ductile. Many operating companies have turned their attention to neutron capture gamma-ray spectroscopy (NCS) logs for assessing in-situ mineral composition. The NCS tool converts the energy spectrum of neutron-induced captured gamma-rays into relative elemental yields and subsequently transforms them to dry-weight elemental fractions. However, NCS logs are not usually included in a well-logging suite due to cost, tool availability, and borehole conditions. Conventional well logs are typically acquired as a minimum logging program because they provide geologists and petrophysicists with the basic elements for tops identification, stratigraphic correlation, and net-pay determination. Most petrophysical interpretation techniques commonly used to quantify mineral composition from conventional well logs are based on the assumption that lithology is dominated by one or two minerals. In organic shale formations, these techniques are ineffective because all well logs are affected by large variations of mineralogy and pore structure. Even though it is difficult to separate the contribution from each mineral and fluid component on well logs using conventional interpretation methods, well logs still bear essential petrophysical properties that can be estimated using an inversion method. This thesis introduces an inversion-based workflow to estimate mineral and fluid concentrations of shale gas formations using conventional well logs. The workflow starts with the construction and calibration of a mineral model based on core analysis of crushed samples and X-Ray Diffraction (XRD). We implement a mineral grouping approach that reduces the number of unknowns to be estimated by the inversion without loss of accuracy in the representation of the main minerals. The second step examines various methods that can provide good initial values for the inversion. For example, a reliable prediction of kerogen concentration can be obtained using the ΔlogR method (Passey et al., 1990) as well as an empirical correlation with gamma-ray or uranium logs. After the mineral model is constructed and a set of initial values are established, nonlinear joint inversion estimates mineral and fluid concentrations from conventional well logs. An iterative refinement of the mineral model can be necessary depending on formation complexity and data quality. The final step of the workflow is to perform rock classification to identify favorable production zones. These zones are selected based on their hydrocarbon potential inferred from inverted petrophysical properties. Two synthetic examples with known mineral compositions and petrophysical properties are described to illustrate the application of inversion. The impact of shoulder-bed effects on inverted properties is examined for the two inversion modes: depth-by-depth and layer-by-layer. This thesis also documents several case studies from Haynesville and Barnett shales where the proposed workflow was successfully implemented and is in good agreement with core measurements and NCS logs. The field examples confirm the accuracy and reliability of nonlinear inversion to estimate porosity, water saturation, kerogen concentration, and mineral composition. / text

We introduce a new quantitative approach to improve the petrophysical evaluation of thinly bedded sand-shale sequences that have undergone extensive diagenesis. Formations under analysis consist of carbonate-rich clastic sediments, with pore system heavily reworked by calcite and authigenic clay cementation, giving rise to rocks with high spatial heterogeneity, low porosity, and low permeability. Porosity varies from 2 to 20% and permeability varies from less than 0.001 mD to 200 mD. Diagenesis and thin laminations originate complex magnetic resonance (NMR) T2 distributions exhibiting multimodal distributions. Furthermore, reservoir units produce highly viscous oil, which imposes additional challenges to formation evaluation. Petrophysical evaluation of thinly bedded formations requires accurate estimation of laminar and dispersed shale concentration. We combined Thomas-Stieber’s method, OBMI, and Rt-Scanner measurements to calculate laminar shale concentration. Results indicate that hydrocarbon reserves can be overestimated in the presence of high-resistivity streaks and graded beds, which give rise to electrical anisotropy. To account for electrical anisotropy effects on petrophysical estimations, we classified reservoir rocks based on the cause of electrical anisotropy. Thereafter different interpretation methods were implemented to estimate petrophysical properties for each rock class. We also appraised the advantages and limitations of the high-resolution method for evaluating thinly bedded formations with respect to other petrophysical interpretation methods. Numerical simulations were performed on populated earth-model properties after detecting bed boundaries from resistivity or core images. Earth-model properties were iteratively refined until field and numerically simulated logs reached an acceptable agreement. Results from the high-resolution method remained petrophysically consistent when beds were thicker than 0.25 ft. Numerical simulations of NMR T2 distributions were also performed to reproduce averaging effects of NMR responses in thinly bedded formations, which enabled us to improve the assessment of pore-size distributions, in-situ fluid type, and saturation. Permeability of sand units was estimated via Timur-Coates’ equation by removing the effect of laminar shale on porosity and bulk irreducible volume water. Shoulder-bed corrected logs were input to the calculations. Petrophysical properties obtained with the developed interpretation method honor all the available measurements including conventional well logs, NMR, resistivity images, multi-component induction, and core measurements. The developed interpretation method was successfully tested across four hydrocarbon-saturated intervals selected from multiple wells penetrating a deep turbidite system. Permeability values obtained with the new interpretation method improved the correlation with core measurements by 16% as compared to permeability calculations performed with conventional methods. In addition, on average the method yielded a 62% increase in hydrocarbon pore-thickness when compared to conventional petrophysical analysis. / text

A petrophysical study of the upper grainstone/packstone reservoir of the Oxfordian Smackover Formation in Little Cedar Creek Field was conducted, integrating core description, thin section analysis, log interpretation and cathodoluminescense to characterize controls on oil production in the upper reservoir. Little Cedar Creek Field produces approximately 2.4 million barrels (bbls) of oil annually and is currently in secondary recovery. By analyzing petrophysical characteristics such as porosity and pore type and correlating them to facies changes, better predictions can be made to optimize secondary recovery. The diagenetic history of the ooid-peloid grainstone records six separate events. Early marine phreatic dogtooth sparry rim cement helped create the framework that allowed it to maintain a good portion of its depositional porosity as it underwent subsequent compaction, dissolution and cementation events. The most common porosity types are vuggy, oomoldic and intercrystalline. The Smackover Formation ooid-peloid grainstone/packstone unit consists of multiple alternating ooid-peloid grainstone and peloid packstone/wackestone facies with varying porosity types. The most common types are oomoldic and vuggy with a range of preserved intergranular porosity. Porosity in the grainstone facies averages 17% and 5.6% in the packstone/wackestone facies. The number of facies changes within the upper reservoir does not play a significant role in controlling well production. Facies changes are too thin to be identifiable utilizing well logs alone, although neutron and density well logs do trace a close relationship between log values and core plug analysis values of porosity. Core reports indicate that porosity and permeability correlate strongly with pore size and facies. Areas with thicker accumulations of grainstone facies have higher porosity and permeability values and have higher oil production. Isopach maps of the cumulative grainstone facies indicate thick build-ups parallel to strike for the formation, consistent with a shoal environment. The strongest predictor of well production is the cumulative thickness of grainstone facies within the grainstone/packstone unit of the Smackover Formation. The grainstone is thickest in the southwest part of the field and pinches out updip in the northwest. Secondary recovery gas injection would be most effective if applied in the southwestern portion of the field because it could effectively sweep the oil updip towards the stratigraphic trap.

Masters of Science / Petrophysical evaluation of four wells within Cretaceous gas-bearing sandstone reservoirs in blocks 4 and 5 Orange Basin, South Africa. Thierry Kamgang The present research work evaluates the petrophysical characteristics of the Cretaceous gasbearing sandstone units within Blocks 4 and 5 offshore South Africa. Data used to carry out this study include: wireline logs (LAS format), base maps, well completion reports, petrography reports, conventional core analysis report and tabulated interpretative age reports from four wells (O-A1, A-N1, P-A1 and P-F1). The zones of interest range between 1410.0m-4100.3m depending on the position of the wells. The research work is carried out in two phases: The first phase corresponds to the interpretation of reservoir lithologies based on wireline logs. This consists of evaluating the type of rocks (clean or tight sandstones) forming the reservoir intervals and their distribution in order to quantify gross zones, by relating the behavior of wireline logs signature based on horizontal routine. Extensively, a vertical routine is used to estimate their distribution by correlating the gamma-ray logs of the corresponding wells, but also to identify their depositional environments (shallow to deep marine).Sedlog software is used to digitize the results. The second phase is conducted with the help of Interactive Petrophysics (version 4) software, and results to the evaluation of eight petrophysical parameters range as follow: effective porosity (4.3% - 25.4%), bulk volume of water (2.7% – 31.8%), irreducible water saturation (0.2%-8.8%), hydrocarbon saturation (9.9% - 43.9%), predicted permeability (0.09mD – 1.60mD), volume of shale (8.4% - 33.6%), porosity (5.5% - 26.2%) and water saturation (56.1% - ii 90.1%). Three predefined petrophysical properties (volume of shale, porosity and water saturation)are used for reservoir characterization. The volume of shale is estimated in all the wells using corrected Steiber method. The porosity is determined from the density logs using the appropriate equations in wells O-A1 and P-A1, while sonic model is applied in well A-N1 and neutron-density relationship in well P-F1. Formation water resistivity (Rw) is determined through the following equation: Rw = (Rmf × Rt) / Rxo, and water saturation is calculated based on Simandoux relation. Furthermore, a predicted permeability function is obtained from the crossplot of core porosity against core permeability, and it results match best with the core permeability of well O-A1. This equation is used to predict the permeability in the other wells. The results obtained reveal that average volumes of shale decrease from the west of the field towards the east; while average porosities and water saturations increase from the south-west through the east despite the decreasing average water saturation in well P-A1. A corroboration of reference physical properties selected for reservoir characterization, with predefined cut-off values result to no net pay zones identified within the reservoir intervals studied. Consequently, it is suggested that further exploration prospects should be done between well O-A1 and A-N1.

Masters of Science / This study is focused on the Coal Bed Methane resources of Botswana with specific reference to the Central Kalahari basin where prospect license blocks forming the focus of this study are located. The aim of this study is to evaluate the fracture network in the coal seams and the fracture systems in the surrounding coal bearing sedimentary sequences and their contribution to dynamic flow. Coal bed methane sources are dual-porosity media documented on the natural fracture network, seen as micropores (matrix/natural fractures) and macropores (cleat). The coals of this region belong to the Ecca Group’s Morupule Fm (Permian) (70 m), focus of this study and have been preserved in the extensive Karoo basin within the Southern Africa region. Fractures can easily be identified in Acoustic Televiewer logs (ATV) and their orientation and structural character interpreted by rose plots, tadpoles and stick dip plots. In-situ stress fields have been determined from breakout structural evaluation and maintains a general E-W dip direction and N-S strike, thus most fractures are orientated optimally with inferred in-situ stress and enhancing flow potential in pore systems. A qualitative (MID plots & M-N cross-plots) and quantitative description of the fracture system is fundamental to the petrophysical evaluation, and involves the estimation of fracture parameters (fracture porosity, resistivity fracture index and both horizontal and vertical fracture indices).

>Magister Scientiae - MSc / Clay diagenesis phenomenon and their effects on some petrophysical properties of lower cretaceous silliciclastic sandstones, offshore Orange basin have been established. Previous studies on Orange basin revealed that chlorite and quartz cements have significantly compromised the reservoir quality in this basin but it is expected that the reservoirs shows better improvement basinward, an analogy of this is displayed by tertiary sandstones deposit, offshore Angola. The main goal of this thesis is to perform reservoir quality evaluation by intergrating geological, geochemical and geophysical tools to substantiate the effects of clay minerals distribution and its subsequent diagenesis on the intrinsic properties (porosity, permeability and saturation) of reservoir intervals encountered within three wells in block 3A (deeper waters), offshore Orange basin. Five lithofacies were identified based on detailed core description from wells KF-1, KH-1 and AU-1 in this block. The facies were grouped based on colour and grain sizes, they are named : A1 (shale), A2 (sandstone), A3 (siltstone), A4 (dark coloured sandstone) and A5 (conglomerates).Depositional environment is predominantly marine, specifically, marine delta front detached bars and deepwater turbiditic sandstone deposit. Geophysical wire line logs of gamma ray, resistivity logs combo and porosity logs were interpreted, parameters and properties such as VCL, porosity, permeability and saturation were estimated from these logs and the values obtained were compared with values from conventional core analysis data, the values agreed well with each other. Detailed petrographic studies (SEM, XRD and thinsection) plus geochemical studies (CEC, EDS, pH, Ec) were carried out on twenty two core samples to establish if these clay minerals and other cements have pervasive effects on the reservoir quality or otherwise.

>Magister Scientiae - MSc / The goal of this study is to enhance the evaluation of subsurface reservoirs by improving the prediction of petrophysical parameters through the integration of wireline logs and core measurements. Formation evaluations of 13A and 14A sequences in the Bredasdorp Basin, offshore South Africa have been performed. Five wells in the central area of the basin have been selected for this study. Four different lithofacies (A, B, C, D) were identified, in the two cored wells, and used to predict the lithofacies from wireline logs in uncored intervals and wells. A method based on artificial neural network was used for this prediction. Facies A and B were recognized as reservoir rocks and 13 reservoir zones were identified and successfully evaluated in a detailed petrophysical model. The final shale volume was considered to be the minimum among five different methods applied in this study at any point along the well log. The porosity model was taken from the density model. A value of 2.66 g/cm3 was obtained from core measurements as the field average grain density, whereas the value of the fluid density of 0.79 g/cm3 was obtained from core porosity and bulk density cross-plot. In a water saturation model; an average water resistivity of 0.135 Ohm-m was estimated from SP method. The calculated water saturation models were calibrated with core measurements, and the Indonesia model best matched with the water saturation from conventional core analysis. Six hydraulic flow units were recognized in the studied reservoirs, and were used for permeability predictions. The permeability predicted from hydraulic flow units were found more reliable than the permeability calculated from porosity-permeability relationship. The net pay was identified for each reservoir by applying cut-offs on permeability 0.1 mD, porosity 7%, shale volume 0.35, and water saturation 0.60. The gross thickness of the reservoirs ranges from 4.83m to 41.07m and net pay intervals from 1.21m to 29.59m.

>Magister Scientiae - MSc / Pletmos Basin is a Mesozoic half graben located in the southern part of South Africa and has undergone numerous tectonic changes which involve alteration of structure and reworking of sediments. Clay diagenesis has become a more prominent factor affecting the quality of the tight shaly sandstone reservoirs in the southern Pletmos Basin. The present study focused on Block 11a as a primary area of interest .The tight sandstone reservoirs encountered in the four wells, viz. Ga-Q1, Ga- Q2, Ga-Z1 and Ga- E2 were studied using four different methods to incorporate and infer the overall diagenetic effect on the reservoirs, caused by materials of argillaceous origin. The methods adopted in the present research are formation evaluation using wireline logs and calibration of core data using Interactive Petrophysics software, thin section petrography, X-Ray Diffraction (XRD) and, Scanning Electron Microscope (SEM) along with Energy Dispersive X-Ray Spectroscopy (EDS). The availability of core samples were limited to wells Ga- Q1 and well Ga- Z1. Four reservoirs within the Cretaceous age were identified in each well and the best reservoirs were associated with facies B and D. / 2022-04-30

No description available.

The development of hydrocarbon energy resources from shale, a fine-grained, low-permeability geological formation, has altered the global energy landscape. Constricting pressure exerted on a shale formation has a significant effect on the rock's apparent permeability. Gas flow in low-permeability shales is significantly different from liquid flow due to the Klinkenberg effect caused by gas molecule slip at the nanopore wall surfaces. This has the effect of increasing apparent permeability (i.e., the measured permeability). Optimizing the conductivity of the proppant assembly is another critical component of designing subsurface hydrocarbon production using hydraulic fracturing. Significant fracture conductivity can be achieved at a much lower cost than conventional material costs, according to the optimal partial-monolayer proppant concentration (OPPC) theory. However, hydraulic fracturing performance in unconventional reservoirs is problematic due of the complex geomechanical environment, and the experimental confirmation and investigation of the OPPC theory have been rare in previous studies. In this dissertation, a novel multiphysics shale transport (MPST) model was developed to account for the coupled multiphysics processes of geomechanics, fluid dynamics, and the Klinkenberg effect in shales. Furthermore, A novel multi-physics multi-scale multi-porosity shale gas transport (M3ST) model was developed based on the MPST model research to investigate shale gas transport in both transient and steady states, and a double-exponential empirical model was also developed as a powerful substitute for the M3ST model for fitting laboratory-measured apparent permeability. Additionally, throughout the laboratory experiment of fracture conductivity with proppant, the four visible stages documented the evolution of non-monotonic conductivity and proppant concentration. The laboratory methods and empirical model were then applied to the shale plugs from Central Appalachia to investigate the formation properties there. The benefits of developing these regions wisely include a smaller surface footprint, reduced infrastructure requirements, and lower development costs. The developed MPST, M3ST, double-exponential empirical models and research findings shed light on the role of multiphysics mechanisms, such as geomechanics, fluid dynamics and transport, and the Klinkenberg effect, in shale gas transport across multiple spatial scales in both steady and transient states. The fracture conductivity experiments successfully validate the theory of OPPC and illustrate that proppant embedment is the primary mechanism that causes the competing process between fracture width and fracture permeability and consequently the non-monotonic fracture conductivity evolution as a function of increasing proppant concentration. The laboratory experimental facts and the numerical fittings in this study provided critical insights into the reservoir characterization in Central Appalachia and will benefit the reservoir development using non-aqueous fracturing techniques such as CO2 and advanced proppant technologies in the future. / Doctor of Philosophy / Production of oil and gas from the extremely tight rock has changed the global energy industry, including job growth, energy security, and environment protection. However, the oil and gas production from the tight rock is difficult because of the complex rock properties. Hydraulic fracking can resolve the issue and contribute to the high production. The higher and safer production needs us to have a better understanding of oil and gas flow under the ground. A series of laboratory experiment were conducted, and a new shale gas transport model is introduced in this dissertation to explain the oil and gas flow under the complicated scenarios. The experimental results show that many factors can impact the oil and gas flow, and the model can match the experimental results very well. A few statistical methods are also used in the data analysis. The optimization of proppant pack is another important component of hydraulic fracking. Proppant particles are usually man-made ceramic tiny balls, which will be injected into the underground to keep the fractures from closing during the production. From the previous papers, it is possible to achieve high fracture conductivity at a much lower cost than traditional proppant costs. Many groups of laboratory experiment were conducted to demonstrate this guess. Many rock samples in the experiment are from Central Appalachian area, which can help the resource development in this area. The developed model and experimental research findings in this study provided critical insights into the role of the many physics mechanisms on shale gas transport, proppant optimization, and hydraulic fracking.