Petrophysical evaluation of the albian age gas bearing sandstone reservoirs of the o-m field, orange basin, South Africa

Philosophiae Doctor - PhDPetrophysical evaluation of the Albian age gas bearing sandstone reservoirs of the O-M field, Offshore South Africa has been performed. The main goal of the thesis is to evaluate the reservoir potentials of the field through the integration and comparison of results from core analysis, production data and petrography studies for the evaluation and correction of key petrophysical parameters from wireline logs which could be used to generate an effective reservoir model. A total of ten wells were evaluated and twenty eight sandstone reservoirs were encountered of which twenty four are gas bearing and four are wet within the Albian age depth interval of 2800m to 3500m. Six lithofacies (A1, A2, A3, A4, A5 and A6) were grouped according to textural and structural features and grain size from the key wells (OP1, OP2 and OP3). Facies A6 was identified as non reservoir rock in terms of reservoir rock quality and facies A1 and A2 were regarded as the best reservoir rock quality. This study identifies the different rock types that comprise reservoir and non reservoirs. Porosity and permeability are the key parameters for identifying the rock types and reservoir characterization. Pore throat radius was estimated from conventional core porosity and permeability with application of the Winland’s method for assessment of reservoir rock quality on the bases of pore throat radius. Results from the Winland’s method present five Petrofacies (Mega porous, Macro porous, Meso porous, Micro porous and Nanno porous). The best Petrofacies was mega porous rock type which corresponds to lithofacies A1 and A2. The nano porous rock type corresponds to lithofacies A6 and was subsequently classified as non reservoir rock. The volume of clay model from log was taken from the gamma-ray model corrected by Steiber equations which was based on the level of agreement between log data and the x-ray diffraction (XRD) clay data. The average volume of clay determined ranged from 1 – 28 %. The field average grain density of 2.67 g/cc was determined from core data which is representative of the well formation, hence 2.67 g/cc was used to estimate porosity from the density log. Reservoir rock properties are generally good with reservoir average porosities between 10 – 22 %, an average permeability of approximately 60mD. The laterolog resistivity values have been invasion corrected to yield estimates of the true formation resistivity. In general, resistivities of above 4.0 Ohm-m are productive reservoirs, an average water resistivity of 0.1 Ohm-m was estimated. Log calculated water saturation models were calibrated with capillary pressure and conventional core determined water saturations, and the Simandoux shaly sand model best agree with capillary and conventional core water saturations and was used to determine field water saturations. The reservoir average water saturations range between 23 – 69 %. The study also revealed quartz as being the dominant mineral in addition to abundant chlorite as the major clay mineral. The fine textured and dispersed pore lining chlorite mineral affects the reservoir quality and may be the possible cause of the low resistivity recorded in the area. The reservoirs evaluated in the field are characterized as normally pressured with an average reservoir pressure of 4800 psi and temperature of 220 ºF. An interpreted field aquifer gradient of 0.44 psi/ft (1.01 g/cc) and gas gradient of 0.09 psi/ft (0.2 g/cc) were obtained from repeat formation test measurements. A total of eight gas water contacts were identified in six wells. For an interval to be regarded as having net pay potential, cut-off values were used to distinguish between pay and non-pay intervals. For an interval to be regarded as pay, it must have a porosity value of at least 10 %, volume of clay of less than 40 %, and water saturation of not more than 65 %. A total of twenty four reservoir intervals meet the cut-off criteria and was regarded as net pay intervals. The gross thickness of the reservoirs range from 2.4m to 31.7m and net pay interval from 1.03m to 25.15m respectively. In summary, this study contributes to scale transition issues in a complex gas bearing sandstone reservoirs and serves as a basis for analysis of petrophysical properties in a multi-scale system.South Afric

Petrophysical interpretation and fluid substitution modelling of the upper shallow marine sandstone reservoirs in the Bredasdorp Basin, offshore South Africa

The fluid substitution method is used for predicting elastic properties of reservoir rocks and their dependence on pore fluid and porosity. This method makes it possible to predict changes in elastic response of a rock saturation with different fluids. This study focused on the Upper Shallow Marine sandstone reservoirs of five selected wells (MM1, MM2, MM3, MM4, and MM5) in the Bredasdorp Basin, offshore South Africa. The integration of petrophysics and rock physics (Gassmann fluid substitution) was applied to the upper shallow marine sandstone reservoirs for reservoir characterisation. The objective of the study was to calculate the volume of clay, porosity, water saturation, permeability, and hydrocarbon saturation, and the application of the Gassmann fluid substitution modelling to determine the effect of different pore fluids (brine, oil, and gas) on acoustic properties (compressional velocity, shear velocity, and density) using rock frame properties

Sandstone reservoir zonation of the north-western Bredasdorp Basin South Africa using core data

This study delineates sandstone reservoir flow zones in the north-western Bredasdorp Basin, offshore South Africa, using conventional core porosity and permeability data. The workflow begins by integrating sedimen- tology reports and logs to identify lithofacies before evaluating petrophysical flow zones. Three lithofacies were classified as lithofacies 1, 2, and 3. Lithofacies 1 is a silty shale and bioturbated sandstone, lithofacies 2 is an interbedded sandstone and shale, with very fine sandstone with well-sorted grains, and is heavily cemented. Conversely, lithofacies 3 is a fine-to medium-grained sandstone with minor shale that is moderately cementation. Lithofacies 3 is ranked as the best reservoir rock, followed by lithofacies 2 and 1. Four independent reservoir zonation methods (permeability anisotropy, Winland r35 pore throat, flow zone indicator (FZI), and stratigraphic modified Lorenz lot (SMLP)) were applied to core samples from three wells (MO4, MO5, and MO6). The core samples predominantly had slight anisotropic permeability (0.5–1.1). The reservoir units were ranked into four flow zone categories as tight, very low, low, and moderate, based on porosity and permeability, and calculated parameters

Determination of total organic carbon content using Passey's method in coals of the central Kalahari Karoo Basin, Botswana

This paper focuses on determining total organic carbon (TOC) from boreholes in the Kalahari Basin, Botswana, using Passey's method. The Kalahari Karoo basin is one of several basins in southern Africa filled with Late Carboniferous to Jurassic sedimentary strata that host Permian age coal seams. Nine exploration boreholes (wells) drilled in the central Kalahari Karoo basin are used to determine the Total Organic Carbon potential. Vitrinite reflectance (Ro), proximate and ultimate analyses were conducted on cored coal intervals. Passey's ΔLogR method applied in this study employs resistivity and porosity logs to identify and quantify potential source rocks. Results of Passey's method compared with laboratory-measured carbon showed that Passey's method effectively identifies coal intervals. In terms of TOC calculations, the method works poorly in coal metamorphosed by dolerite intrusions

Source rock evaluation of Afowo clay type from the Eastern Dahomey Basin, Nigeria: Insights from different measurements

The Cretaceous Afowo Formation in the Eastern Dohamey Basin is characterized by an admixture of lithofacies ranging from sandstones, claystones, shales, clays, sand/shale, and sand/clay intercalations. The sandy facies, a mix of sandstone, clay, shale, and intercalations, contain biodegraded hydrocarbons while the shales and claystones that underlie it are rich in organic matter. The hydrocarbon-bearing interval is commonly referred to as the oil sand or tar sand. In this study, Afowo clay type underlying an outcrop of the oil sand was appraised for its hydrocarbon potential with loss on ignition, thermogravimetry, and rock evaluation pyrolysis

Metal–metal correlation of biodegraded crude oil and associated economic crops from the Eastern Dahomey Basin, Nigeria

The presence of heavy metals in plants from oil sand deposits may reflect mineralization resulting from petroleum biodegradation. Petroleum composition and heavy metal analyses were performed using thermal desorption gas chromatography and atomic absorption spectrophotometry on oil sand and plant root samples from the same localities in the Dahomey Basin. The results from the oil sand showed mainly heavy-end hydrocarbon components, humps of unresolved complex mixtures (UCM), absences of C6-C12 hydrocarbon chains, pristane, and phytane, indicating severe biodegradation. In addition, they showed varying concentrations of vanadium (2.699–7.708 ppm), nickel (4.005–11.716 ppm), chromium (1.686–5.733 ppm), cobalt (0.953–3.223 ppm), lead (0.649–0.978 ppm), and cadmium (0.188–0.461 ppm). Furthermore, these heavy metals were present in Citrus, Theobroma Cacao, Elaeis guineensis, and Cola

Static reservoir modeling using stochastic method: A case study of the cretaceous sequence of Gamtoos Basin, Ofshore, South Africa

Gamtoos Basin is an echelon sub-basin under the Outeniqua ofshore Basin of South Africa. It is a complex rift-type basin with both onshore and ofshore components and consists of relatively simple half-grabens bounded by a major fault to the northeast. This study is mainly focused on the evaluation of the reservoir heterogeneity of the Valanginian depositional sequence. The prime objective of this work is to generate a 3D static reservoir model for a better understanding of the spatial distribution of discrete and continuous reservoir properties (porosity, permeability, and water saturation). The methodology adopted in this work includes the integration of 2D seismic and well-log data. These data were used to construct 3D models of lithofacies, porosity, permeability, and water saturation through petrophysical analysis, upscaling, Sequential Indicator Simulation, and Sequential Gaussian Simulation algorithms, respectively. Results indicated that static reservoir modeling adequately captured reservoir geometry and spatial properties distribution. In this study, the static geocellular model delineates lithology into three facies: sandstone, silt, and shale. Petrophysical models were integrated with facies within the reservoir to identify the best location that has the potential to produce hydrocarbon. The statistical analysis model revealed sandstone is the best facies and that the porosity, permeability, and water saturation ranges between 8 and 22%, 0.1 mD (<1.0 mD) to 1.0 mD, and 30–55%. Geocellular model results showed that the northwestern part of the Gamtoos Basin has the best petrophysical properties, followed by the central part of the Basin. Findings from this study have provided the information needed for further gas exploration, appraisal, and development programs in the Gamtoos Basin

The impact of detrital minerals on reservoir flow zones in the North Eastern Bredasdorp basin, South Africa, using core data

The present study uses core data to group reservoirs of a gas field in the Bredasdorp Basin offshore South Africa into flow zones. One hundred and sixty-eight core porosity and permeability data were used to establish reservoir zones from the flow zone indicator (FZI) and Winland’s methods. Storage and flow capacities were determined from the stratigraphy-modified Lorenz plot (SMLP) method. The effects of the mineralogy on the flow zones were established from mineralogy composition analyses using quantitative X-ray diffraction (XRD) and Scanning Electron Microscopy (SEM). Results reveal five flow zones grouped as high, moderate, low, very low, and tight reservoir rocks

Shale-gas potential from Cretaceous succession in South Africa’s orange basin: insights from integrated geochemical evaluations

Shale sediments were collected from four Cretaceous stratigraphic units across four explorations well locations in South Africa’s Orange Basin and analysed to determine organic-matter characteristics, such as amount, quality, thermal maturity, and their viability as gas resources. The geochemical results show that the Cretaceous shales contain moderate organic quantities, as shown by TOC averagely up to 1.29%. The organic facies consist primarily of Type III kerogen, as proven alongside low hydrogen indexes between 40 and 133 mg HC/g TOC. As seen under a reflected light microscope, the dominance of such land plant-rich organic matter is in harmony with the significant amount of Vitrinite macerals. These organic sediments can produce primarily gas when they mature. The geological and geochemical properties of the organic sediments, chiefly Type III kerogen, generate both wet and dry gas, particularly when adequate thermal maturity is enhanced at deeper locations. Thus, the Orange Basin is considered promising for shale gas exploration and production

Preliminary Investigation of Trace Elements in Acid Mine Drainage from Odagbo Coal Mine, Northcentral, Nigeria

The objective of this study was to assess the concentration of trace elements in acid mine drainage (AMD) from Odagbo coal mine. Composite AMD samples were collected from active and abandoned mining pits and were analysed for lead, nickel, cobalt, chromium, mercury, zinc, arsenic and iron using Atomic Absorption Spectroscopy (AAS). Comparisons were made between the trace elements and environmentally acceptable quality standard (EQS) for heavy metal discharges from mines using student’s t-test. The mean concentrations of these elements were lead (0.10 mg/l), nickel (0.49 mg/l), cobalt (0.88 mg/l), chromium (0.55 mg/l), cadmium (0.19 mg/l), arsenic (0.01 mg/l) and iron (5.80 mg/l). There were significant differences between the means of lead, mercury, cadmium, arsenic and EQS for heavy metal discharges from mines (P &lt; 0.05). There were no significant differences between the means of nickel, chromium, iron and EQS for heavy metal discharges from mines (P &gt; 0.05). Cobalt, iron, nickel and chromium were the dominant trace elements in the AMD. Further studies are required to determine the influence of AMD on surface water and soils around the mine. Keywords: Acid mine drainage, trace elements, coal, mine, sulphide minerals