Search Results (7)

Pore pressure prediction gives drillers an early warning of potential oil and gas kicks, enabling them to adjust mud weight pre-emptively. A kick causes a delay in drilling practices, blowouts, and jeopardization of the wells. Changes in pore pressure affect the type of fluid contact in the reservoir. This study predicted the pore pressure and determined fluid contacts within the Lower Cretaceous and early Upper Cretaceous (Barremian to early Cenomanian) sandstone reservoirs of the Bredasdorp Basin using well logs and repeat formation test (RFT) data from three wells: E-BK1, E-AJ1, and E-CB1. Eaton’s method of developing a depth-dependent Normal Compact Trend (NCT), using resistivity and sonic wireline logs, as well as other methods including the Mathews and Kelly, Baker and Wood, and Modified Eaton and Bowers methods, were employed for pore pressure prediction. Eaton’s method provided reliable pore pressure results in all the wells when compared to alternative methods in this study. Overburden gradient and predicted pore pressures ranged from 1.84 gm/cc to 2.07 gm/cc and from 3563.74 psi to 4310.06 psi, respectively. Eaton’s resistivity and density/neutron log method results indicated normal pressure in E-BK1 and E-AJ1, as well as overpressured zones in E-AJ1. However, in E-CB1, the results showed only overpressured zones. The E-AJ1 significant overpressures were from 2685 m to 2716 m and from 2716 m to 2735 m in the pores exceeding 7991.54 psi. Gas–water contact (GOC) was encountered at 2967.5 m in E-BK1, while oil–gas contact (OGC) was at 2523 m in E-CB1, and gas–oil and oil–water contacts (GOC and OWC) were at 2699 m and 2723 m, respectively, in E-AJ1. In E-CB1, oil–water contact (OWC) was at 2528.5 m. Fluid contacts observed from the well logs and RFT data were in close agreement in E-AJ1, whereas there was no agreement in E-CB1 because the well log observations showed a shallower depth compared to RFT data with a difference of 5.5 m. This study illustrated the significance of an integrated approach to predicting fluid contacts and pore pressure within the reservoirs by showing that fluid contacts associated with overpressures were gas–water and oil–water contacts. In contrast, gas–oil contact was associated with normal pressure and under pressure. Full article

Routine core permeability and porosity are crucial in assessing flow units within a reservoir because they define a reservoir’s storage and flow capacities. A limited amount of work has been conducted on the lower cretaceous (Barremian to Valanginian) sandstones in the Bredasdorp Basin, offshore South Africa, focusing on the flow zones and the possible effect of diagenetic minerals on the individual flow zones, limiting understanding of reservoir quality and fluid flow behavior across the field. Nine hundred routine core analysis datasets were used to determine the flow units within the reservoir from three wells (F-A10, F-A13, and F-O2) from independent methods, namely: the Pore Throat Radius, Flow Zone Indicator, Stratigraphic Modified Lorenz Plot, and Improved Stratigraphic Modified Lorenz Plot. The results showed six flow units: fracture, super-conductive, conductor, semi-conductor, baffle, and semi-barrier. The super-conductive flow units contributed the most flow, whereas the semi-barrier and baffle units contributed the least flow. Petrography analyses revealed that the diagenetic minerals present were smectite, illite, glauconite, siderite, micrite calcite, and chlorite. The pore-filling minerals reduced the pore spaces and affected pore connectivity, significantly affecting the flow contribution of the baffle and semi-barrier units. Micrite calcite and siderite cementation in FU5 of F-A13 and FU9 of F-O2 significantly reduced the intergranular porosity by filling up the pore spaces, resulting in tight flow units with impervious reservoir quality. It was noted that where the flow unit was classified as super-conductive, authigenic clays did not significantly affect porosity and permeability as they only occurred locally. However, calcite and silica cementation significantly affected pore connectivity, where the flow unit was classified as a very low, tight, semi-barrier, or barrier. Full article

The upper shallow marine sandstone reservoirs of the Barremian-to-Valanginian formation are the most porous and permeable sandstone reservoirs in the Bredasdorp Basin and an important target for oil and gas exploration. There is a paucity of information on the reservoir characterization and effect of diagenetic mineral studies focusing on the upper shallow marine sandstone reservoirs in the central Bredasdorp Basin; thus, there is a need to investigate the effect of diagenetic minerals and to characterize these reservoirs due to their high porosity and permeability. Datasets, including a suite of geophysical wireline logs, routine core analysis, geological well completion reports, description reports, and core samples, were utilized. A total of 642 core porosity measures, core water saturation, and core permeability data were used for calibration with the log-derived parameters, ranging in depth from 3615 m to 4259 m. Rock samples were prepared for diagenetic mineral analyses, such as thin sections and Scanning electron microscopy, for each well to investigate the presence of diagenetic minerals in the selected reservoir units. The petrophysical analyses showed the results of porosity, volume of clay, water saturation, and permeability, ranging from 9% to 27%, 8.6% to 19.8%, 18.9% to 30.4%, and 0.096 mD to 151.8 mD, respectively, indicating a poor-to-good reservoir quality. Mineralogical analyses revealed that micrite calcite, quartz cement, quartz overgrowth, and authigenic pore-filling and grain-coating clay minerals (illite–smectite and illite) negatively affected intergranular porosity. Porosity-versus-permeability cross plot showed good correlation of 0.86 for ZN1 and 0.83 for ZN3 reservoirs, suggesting that although porosity is the main drive of permeability, there were other geological factors at play, such as diagenetic minerals and compaction. Full article

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. The high flow zone is the best reservoir quality rock and has porosity and permeability values ranging from 12 to 20% and 100 to 1000 mD. The high and moderate zones contribute more than 60% of each well’s flow capacities. The moderate and low flow zone extends laterally to all the wells. The tight flow zone is an impervious rock and has the lowest rock quality with porosity and permeability values less than 8% and 1 mD, respectively. This zone contributes less than 1% to flow capacity. The impact of minerals on flow zones is evident in plagioclase and muscovite content increases. An accompanied decrease in quartz content is observed, which implies that low plagioclase content ≤4% and muscovite content of ≤1% corresponds to the low, moderate, and high flow zones, while plagioclase content of ≥4% and muscovite content of ≥1% belong to the tight flow zone. Consequently, the quantity of plagioclase and muscovite can be used as a proxy to identify better quality reservoir rocks. The diagenetic process that reduces the rock quality can be attributed to quartz overgrowth and the accumulation of mica flakes in the pore spaces. In contrast, the fracture in the high flow zone is the reservoir quality enhancing process. The flow zones are generally controlled by a combination of facies and diagenetic factors. Full article

The Cretaceous sandstones of the Bredasdorp Basin were investigated to recognize their composition, provenance, and tectonic setting. Ninety-two samples of sandstones from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1, and E-D3 were investigated using both petrographic and X-ray diffraction (XRD) methods. Petrographic studies based on quantitative investigation of the detrital framework grain shows that the Bredasdorp sandstones chiefly consist of quartz (52.2–68.0%), feldspar (10.0–18.0%), and lithic fragments (5.0–10.2%). These sandstones are mostly fine grained, moderately well-sorted, and subrounded to rounded. The modal composition data shows that the sandstones could be classified as subarkosic arenite and lithic arkose. Such a composition of the sandstones perhaps indicates the interplay of pulses of fast uplift of the source area and rapid subsidence of the Bredasdorp Basin, with subsequent periods of calmness within the transgressive-regressive sequence in a rift tectonic regime. The provenance ternary diagrams revealed that the sandstones are mainly of continental block provenances (stable shields and basement uplifted areas) and complemented by recycled sands from an associated platform. The tectonic provenance studies of Bredasdorp Basin revealed that the sandstones are typically rift sandstones and have undergone long-distance transport from the source area along the rift. In the regional context of the evolution of the Bredasdorp Basin, the results presented in this study inferred that the basin developed on a rift passive setting (trailing edge) of the stable continental margins. Full article

The Cretaceous sandstone in the Bredasdorp Basin is an essential potential hydrocarbon reservoir. In spite of its importance as a reservoir, the impact of diagenesis on the reservoir quality of the sandstones is almost unknown. This study is undertaken to investigate the impact of digenesis on reservoir quality as it pertains to oil and gas production in the basin. The diagenetic characterization of the reservoir is based on XRF, XRD SEM + EDX, and petrographic studies of 106 thin sections of sandstones from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 in the basin. The main diagenetic processes that have affected the reservoir quality of the sandstones are cementation by authigenic clay, carbonate and silica, growth of authigenic glauconite, dissolution of minerals and load compaction. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed up by the development of partial pore-lining and pore-filling clay cements, particularly illite. This clay acts as pore choking cement, which reduces porosity and permeability of the reservoir rocks. The scattered plots of porosity and permeability versus cement + clays show good inverse correlations, suggesting that the reservoir quality is mainly controlled by cementation and authigenic clays. Full article

The southern Bredasdorp Basin, off the south coast of South Africa, is only partly understood in terms of its hydrocarbon potential when compared to the central and northern parts of the basin. Hydrocarbon potential assessments in this part of the basin have been limited, perhaps because the few drilled exploration wells were unproductive for hydrocarbons, yielding trivial oil and gas. The partial integration of data in the southern Bredasdorp Basin provides another reason for the unsuccessful oil and gas exploration. In this study, selected Cretaceous mudrocks and sandstones (wacke) from exploration wells E-AH1, E-AJ1, E-BA1, E-BB1 and E-D3 drilled in the southern part of the Bredasdorp Basin were examined to assess their total organic carbon (TOC), thermal maturity, organic matter type and hydrocarbon generation potential. The organic geochemical results show that these rocks have TOC contents ranging from 0.14 to 7.03 wt.%. The hydrogen index (HI), oxygen index (OI), and hydrocarbon index (S₂/S₃) values vary between 24–263 mg HC/g TOC, 4–78 mg CO₂/g TOC, and 0.01–18 mgHC/mgCO₂ TOC, respectively, indicating predominantly Type III and IV kerogen with a minor amount of mixed Type II/III kerogen. The mean vitrinite reflectance values vary from 0.60–1.20%, indicating that the samples are in the oil-generation window. The Tmax and PI values are consistent with the mean vitrinite reflectance values, indicating that the Bredasdorp source rocks have entered the oil window and are considered as effective source rocks in the Bredasdorp Basin. The hydrocarbon genetic potential (SP), normalized oil content (NOC) and production index (PI) values all indicate poor to fair hydrocarbon generative potential. Based on the geochemical data, it can be inferred that most of the mudrocks and sandstones (wackes) in the southern part of the Bredasdorp Basin have attained sufficient burial depth and thermal maturity for oil and gas generation potential. Full article