Magister Scientiae - MSc / The Bredasdorp Basin is one of the largest hydrocarbon producing blocks within Southern Africa. The E-M field is situated approximate 50 km west from the FA platform and was brought into commission due to the potential hydrocarbons it may hold. If this field is brought up to full producing capability it will extend the lifespan of the refining station in Mosselbay, situated on the south coast of South Africa, by approximately 8 to 10 years. An unexpected pressure drop within the E-M field caused the suite not to perform optimally and thus further analysis was imminent to assess and alleviate the predicament. The first step within the project was to determine what might have cause the pressure drop and thus we had to go back to cores drilled by Soekor now known as Petroleum South Africa, in the early 1980’s. Analyses of the cores exposed a high presence of granulation seams. The granulation seams were mainly subjected within sand units within the cores. This was caused by rolling of sand grains over one another rearranging themselves due to pressure exerted through compaction and faulting, creating seal like fractures within the sand. These fractures caused these sand units to compartmentalize and prohibit flow from one on block to the next. With advance inquiry it was discovered that there was a shale unit situated within the reservoir dividing the reservoir into two main compartments. At this point it was determined to use Petrel which is windows based software for 3D visualization with a user interface based on the Windows Microsoft standards. This is easy as well as user friendly software thus the choice to go with it. The software uses shared earth modeling tool bringing about reservoir disciplines trough common data modelling. This is one of the best modelling applications in the available and it was for this reason that it was chosen to apply within the given aspects of the project A lack of data was available to model the granulation seams but with the data acquired during the core analyses it was possible to model the shale unit and factor in the influences of the granulation seams to asses the extent of compartmentalization. The core revealed a thick shale layer dividing the reservoir within two sections which was not previously noted. This shale layer act as a buffer/barrier restricting flow from the bottom to the top halve of the reservoir. This layer is thickest at the crest of the 10km² domal closure and thins toward the confines of the E-M suite. Small incisions, visible within the 3 dimensional models could serve as a guide for possible re-entry points for future drilling. These incisions which were formed through Lowstand and Highstand systems tracts with the rise and fall of the sea level. The Bredasdorp Basin consists mainly of tilting half graben structures that formed through rifting with the break-up of Gondwanaland. The model also revealed that these faults segregate the reservoir further creating bigger compartments. The reservoir is highly compartmentalized which will explain the pressure loss within the E-M suite. The production well was drilled within one of these compartments and when the confining pressure was relieved the pressure dropped and the production decrease. As recommendation, additional wells are required to appraise the E-M structure and determine to what extent the granulation seems has affected fluid flow as well as the degree of sedimentation that could impede fluid flow. There are areas still containing untapped resources thus the recommendation for extra wells. / South Africa

>Magister Scientiae - MSc / This study was aimed at determining the sedimentary environment, its evolution and facies areal distribution of the Upper Shallow Marine (USM, Late Valanginian). The study was conducted in wells E-S1, F-AH4 and E-W1 in the Bredasdorp basin between E-M and F-AH fields, located in a basinwards transect roughly transverse to the palaeocoast. The wells were studied by logging all the cores in detail between the chosen intervals, followed by facies analysis. Each core log was tied with its respective gamma ray and resistivity well logs. The logs were then correlated based on their log signatures, trends and facies interpretation. The Gamma ray logs show a fining-upwards and coarsening-upwards trend (“hour-glass shape”) in E-S1 and F-AH4 while in E-W1 it shows more accommodation space. These trends are believed to have been influenced by relative sea level changes, such as transgression and regression. Facies analysis identified seven facies in the study area: Facies A, B, C, D, E, F and G. Facies A, B and C were interpreted as fair-weather and storm deposits of the offshore-transition zone, shoreface and foreshore respectively. Facies D was considered as lagoonal mud deposits, while Facies E and F were interpreted as tidal channel and tidal bar deposits respectively. Finally Facies G was considered as fluvial channel deposits. The facies inferred that the sedimentary environment of the study area is a wave-dominated estuary or an Island-bar lagoon system. This led to the production of a conceptual model showing the possible locations for the three wells in the Island bar-lagoon system. The conceptual model inferred the previous findings from PGS (1999) report, that the Upper Shallow Marine beds were deposited in a tidal/estuarine to shoreface setting. This model also supports the findings of Magobiyane (2014), which proposed a wave-dominated estuary for the Upper Shallow Marine reservoir between E-M and F-AH fields, located west of the study area.

>Magister Scientiae - MSc / The area of concentration of this particular project is focused on the central part of the Bredasdorp Basin, block 9, offshore South Africa. Petrophysical evaluation of sandstone reservoirs of the F-0 tract offshore South Africa has been performed. The main aim of this study is to investigate the reservoir potential of this tract, using processed data of four wells which include; F-01, F-02, F-R1 and F-Sl. The data used for this evaluation include; wireline logs, conventional core data and special core analysis data (SCAL). Combining these laboratory results with wireline log examinations and core descriptions gives an idea of the sedimentary environment, sandstone properties and ultimately generates an effective model. Six facies were identified from the core, based on the grain size (facies 1, 2, 3, 4, 5 and 6). Facies 1 and 2 had the best reservoir rock qualities, whereas facies 3 to 6 are classified as poor or non - reservoir rock. These reservoirs are deposited in a shallow marine environment. Porosity and permeability are the two main properties which ultimately determine the quality of the reservoir. These two property measurements were taken from the routine core analysis and SCAL data and generated for the entire well using various methods. The Steiber equation was used to calculate the volume of clay from the gamma ray log. The average porosity for all four wells range between 0.5% to 17%. The minimum value recorded for permeability is 0.009mD and the maximum value is 235mD, even though permeability seems to have a broad range, the majority of the values recorded is less than lOmD. Based on these values, the reservoir rock properties are generally classified as moderate to fair. In some places, where the permeability is more than 100mD, the reservoir is classified as very good. Capillary pressure and conventional core data was compared to the log calculated water saturation models. The best fit model was the Indonesia model. The average water saturations range from 10% to 88 %. A total of eleven reservoir intervals were identified from the four wells based on the cut - off parameters. For an interval to be classified as a reservoir interval, the porosity should be equal or greater than 6%, water saturation equal or less than 35% and the volume of clay should be equal to or less than 40%. From the eleven intervals identified, four intervals contain gas and the remainder of the intervals identified are water bearing. The gross thickness of the reservoir ranges from 10m to 66m and net pay interval from 0.46m to 51.6m.

>Magister Scientiae - MSc / This study describes porosity and permeability distribution in the deep marine play of the central Bredasdorp Basin, Block 9, offshore South Africa using methods that include thin section petrography, X-ray diffraction, and scanning electron microscopy, in order to characterize their porosity and permeability distributions, cementation and clay types that affect the porosity and permeability distribution. The study includes core samples from nine wells taken from selected depths within the Basin. Seventy three thin sections were described using parameters such as grain size measurement, quantification of porosity and permeability, mineralogy, sorting, grain shape, matrix, cementation, and clay content. Core samples were analyzed using x-ray diffraction for qualitative clay mineralogy and phase analysis. Scanning electron microscope analysis for qualitative assessment of clays and cements. X-ray diffraction (XRD) and scanning electron microscope (SEM) analyses were conducted on fifty-four (54) and thirty-five (35) samples respectively to identify and quantify the clay mineralogy of the sandstones. The SEM micrographs are also useful for estimating the type and distribution of porosity and cements. Analyses of these methods is used in describing the reservoir quality. Detrital matrix varies in abundance from one well to another. The matrix consists predominantly of clay minerals with lesser amounts of detrital cements. X-ray diffraction analyses suggest these clays largely consist of illitic and kaolinite, with minor amounts of chlorite and laumontite. Because these clays are highly illitic, the matrix could exhibit significant swelling if exposed to fresh sea water, thus further reducing the reservoir quality. The majority of the samples generally have significant cements; in particular quartz cement occurs abundantly in most samples. The high silica cement is possibly caused by the high number of nucleation sites owing to the relatively high abundance of detrital quartz. Carbonate cement, particularly siderite and calcite, occurs in variable amounts in most samples but generally has little effect on reservoir quality in the majority of samples. Authigenic, pore-filling kaolinite occurs in several samples and is probably related. to feldspar/glauconite alteration, it degrades reservoir quality. The presence of chlorite locally (plate 4.66A & B) and in minute quantities is attributed to a late stage replacement of lithic grains. Don't put references to plates and figures in abstract. A high argillaceous content is directly responsible for the low permeability obtained in the core analysis. Pervasive calcite and silica cementation are the main cause of porosity and permeability destruction. Dissolution of pore filling intergranular clays may result in the formation of micro porosity and interconnected secondary porosity. Based on the combination of information derived from thin section petrography, SEM and XRD, diagenetic stages and event sequences are established for the sandstone in the studied area. Reservoir quality deteriorates with depth, as cementation, grain coating and pore infilling authigenic chlorite, illite and kaolinite becomes more abundant.

>Magister Scientiae - MSc / Southern offshore basins of South Africa are well known as potential provinces of hydrocarbon exploration and production. The complex nature of the Bredasdorp sub-basin’s syn-rift architecture (transform fault system) can have adverse effects on reservoir distribution due to periodic local and regional uplift of horsts and grabens. This present investigation focusses on an integrated approach of the 1AT1-V horizon or early Cretaceous sediments in the Bredasdorp sub-basin to identify the depositional environment and provenance of these sediments as well as their role in regionally complex compositional heterogeneities associated with the late stage rifting of Gondwana break-up. An integrated seismic, sedimentological (including petrography and geochemistry) and ichnologic analysis of the 1AT1-V horizon sediments showed an overall lower regressive element complex assemblage set and an upper transgressive element complex assemblage set that occurred as a >120m thick succession. The analysis identified a mixed-energy deltaic succession followed by an estuarine succession. The 1AT1-V interval (late syn-rift) consisted of nine sedimentary facies associations (and associated petrofacies) on a dipslope setting with variations occurring along the strike and the downdip depositional slope areas. Two overall sequences were identified as a lower regressive and upper transgressive sequence (Element complex assemblage sets). The regressive sequence consisted of middle to distal delta front lobe fringes, hyperpycnal event beds (sourced from basement highs), offshore migrating tidal bars (and associated inter-bar regions), distal mouth bars, terminal distributary channels (and associated inter-terminal distributary regions). The distal delta plain to proximal delta front consisted of interdistributary bays, distributary channels, crevasse splay sub-deltas, mouth bars, tidal flats and offshore embayments. In the laterally isolated depocenter, these deposits also consisted of basement high slopes with upliftment of the basement highs leading to proximal/central embayment to regressive shoreface/foreshore environments. These sequences consisted generally of low diversity and intensities (impoverished abundances) of trace fossils. The paleoclimate inference from this sequence indicates a humid climate with intermediate degrees of weathering intensities (possibly fluctuating arid-humid conditions). The transgressive sequence consisted of estuarine sedimentation with the occurrence of tidal sand ridges and compound dune fields, embayment facies and tidal bars. These sequences consisted of relatively higher ichnodiversities and intensities than their relative regressive sequences. The paleoclimate inference during these times consisted of more arid to semi-arid settings with low degrees of weathering in the source terrain. Local tectonic upliftment and subsidence, with exposed basement highs, gave rise to differential process regimes (tidal, wave and fluvial) and hence depositional facies in the diachronous updip/downdip areas (spatial) and within-stratigraphic (temporal) variations. There are several modern analogues that are similar to the 1AT1-V horizon sequence and they are the Mahakam, Ganges-Brahmaputra, Po, Burdekin deltaic and Satpara lake environments Compaction and dissolution diagenetic features as well as transportation were responsible for the major compositional heterogeneities concerning the reservoir quality and distribution. Proximal and distal sources were identified with first cycle and polycyclic sediments being deposited in the northern and southern part of the basin during the late stages of rifting in the Bredasdorp sub-basin. The provenance lithology has been identified as recycled sedimentary rocks (and their meta-equivalents) with an ultimate source terrain that was largely felsic in nature (Cape granite suite). The northern part of the studied section is suggested to have received sediments from the main metasedimentary rocks of the Cape fold belt (including the Table Mountain Group and Bokkeveld Group) whereas the southern sections received more sediments from the basement highs (recycled Malmesbury Group (and Pre-Cape sediments) and Cape granite suite), which is further supported by seismic data. Provenance analysis revealed that the Cape Fold belt (most recent collision) was possibly a provenance terrain but overprinting of several collisions are also acknowledged. The tectonic setting was envisaged to be of a rifted margin during the break-up of Gondwana. This compositional heterogeneity due to facies and provenance-related terrains had major consequences to the reservoir quality and distribution from the northern part to the southern part of the studied section

>Magister Scientiae - MSc / An accurate prediction of pore pressure is an essential in reducing the risk involved in a well or field life cycle. This has formed an integral part of routine work for exploration, development and exploitation team in the oil and gas industries. Several factors such as sediment compaction, overburden, lithology characteristic, hydrocarbon pressure and capillary entry pressure contribute significantly to the cause of overpressure. Hence, understanding the dynamics associated with the above factors will certainly reduce the risk involved in drilling and production. This study examined three deep water drilled wells GA-W1, GA-N1, and GA-AA1 of lower cretaceous Hauterivian to early Aptian age between 112 to 117.5 (MA) Southern Pletmos sub-basin, Bredasdorp basin offshore South Africa. The study aimed to determine the pore pressure prediction of the reservoir formation of the wells. Eaton’s resistivity and Sonic method are adopted using depth dependent normal compaction trendline (NCT) has been carried out for this study. The variation of the overburden gradient (OBG), the Effective stress, Fracture gradient (FG), Fracture pressure (FP), Pore pressure gradient (PPG) and the predicted pore pressure (PPP) have been studied for the selected wells. The overburden changes slightly as follow: 2.09g/cm3, 2.23g/cm3 and 2.24g/cm3 across the selected intervals depth of wells. The predicted pore pressure calculated for the intervals depth of selected wells GA-W1, GA-N1 and GA-AA1 also varies slightly down the depths as follow: 3,405 psi, 4,110 psi, 5,062 psi respectively. The overpressure zone and normal pressure zone were encountered in well GA-W1, while a normal pressure zone was experienced in both well GA-N1 and GA-AA1. In addition, the direct hydrocarbon indicator (DHI) was carried out by method of post-stack amplitude analysis seismic reflectors surface which was used to determine the hydrocarbon prospect zone of the wells from the seismic section. It majorly indicate the zones of thick hydrocarbon sand from the amplitude extraction grid map horizon reflectors at 13AT1 & 8AT1 and 8AT1 & 1AT1 of the well GA-W1, GA-N1 and GA-AA1 respectively. These are suggested to be the hydrocarbon prospect locations (wet-gas to Oil prone source) on the seismic section with fault trending along the horizons. No bright spot, flat spot and dim spot was observed except for some related pitfalls anomalies

Philosophiae Doctor - PhD / The use of integrated approach to evaluate the quality of reservoir rocks is increasingly becoming vital in petroleum geoscience. This approach was employed to unravel the reason for the erratic reservoir quality of sandstones of the F-O gas field with the aim of predicting reservoir quality, evaluate the samples for presence, distribution and character of hydrocarbon inclusions so as to gain a better understanding of the fluid history. Information on the chemical conditions of diagenetic processes is commonly preserved in aqueous and oil fluid inclusion occurring in petroleum reservoir cements. Diagenesis plays a vital role in preserving, creating, or destroying porosity and permeability, while the awareness of the type of trap(s) prior to drilling serves as input for appropriate drilling designs. Thus an in-depth understanding of diagenetic histories and trap mechanisms of potential reservoirs are of paramount interest during exploration stage.This research work focused on the F-O tract located in the eastern part of Block 9 on the north-eastern flank of the Bredasdorp Basin, a sub-basin of Outeniqua Basin on the southern continental shelf, offshore South Africa. The Bredasdorp Basin experienced an onset of rifting during the Middle-Late Jurassic as a result of dextral trans-tensional stress produced by the breakup of Gondwanaland that occurred in the east of the Falkland Plateau and the Mozambique Ridge. This phenomenon initiated a normal faulting, north of the Agulhas-Falkland fracture zone followed by a widespread uplift of major bounding arches within the horst blocks in the region that enhanced an erosion of lower Valanginian drift to onset second order unconformity.This study considered 52 selected reservoir core samples from six wells(F-O1, F-O2, F-O3, F-O4, F-R1 and F-S1) in the F-O field of Bredasdorp Basin with attention on the Valanginian age sandstone. An integrated approach incorporating detailed core descriptions, wireline log analysis (using Interactive petrophysics), structural interpretation from 2D seismic lines (using SMT software) cutting across all the six wells, multi-mineral (thin section, SEM,XRD) analyses, geochemical (immobile fluid and XRF) and fluid inclusion(fluid inclusion petrography and bulk volatile) analyses were deployed for the execution of this study. Core description revealed six facies from the six wells grading from pure shale (Facies 1), through progressively coarsening interbedded sand-shale “heterolithic facies (Facies 2 - 4), to cross bedded and minor massive sandstone (Facies 5 - 6). Sedimentary structures and mineral patches varies from well to well with bioturbation, synaeresis crack, echinoid fragments, fossil burrow, foreset mudrapes, glauconite and siderite as the main observed features. All these indicate that the Valanginian reservoir section in the studied wells was deposited in the upper shallow marine settings. A combination of wireline logs were used to delineate the reservoir zone prior to core description. The principal reservoirs are tight, highly faulted Valanginian shallow-marine sandstones beneath the drift-onset unconformity, 1At1 and were deposited as an extensive sandstone “sheet” within a tidal setting. The top and base of the reservoir are defined by the 13At1 and 1At1 seismic events,respectively. This heterogeneous reservoir sandstones present low-fair porosity of between 2 to 18 % and a low-fair permeability value greater than 0.1 to 10 mD. The evolution of the F-O field was found to be controlled by extensional events owing to series of interpreted listric normal faults and rifting or graben generated possibly by the opening of the Atlantic. The field is on a well-defined structural high at the level of the regional drift-onset unconformity, 1At1.Multi-mineral analysis reveals the presence of quartz and kaolinite as the major porosity and permeability constraint respectively along with micaceous phases. The distribution of quartz and feldspar overgrowth and crystals vary from formation to formation and from bed to bed within the same structure. The increase in temperature that led to kaolinite formation could have triggered the low-porosity observed. Three types of kaolinite were recognized in the sandstone, (1) kaolinite growing in between expanded mica flakes; (2)vermiform kaolinite; and (3) euhedral kaolinite crystals forming matrix.Compositional study of the upper shallow marine sandstones in the Valanginian age indicates that the sandstones are geochemically classified as majorly litharenite having few F-O2 samples as subarkose with all F-O1 samples classified as sub-litharenite sandstone.Most of the studied wells are more of wet gas, characterized by strong response of C2 – C5 with F-O1 well showing more of gas condensate with oil shows (C7 – C11) based on the number of carbon atom present. In some cases,sulphur species (characterized by the presence of H2S, S2, CS2 and SO2) of probably thermal origin were identified while some log signatures revealed aromatic enriched sandstones possibly detecting nearby gas charges. The studied wells in the F-O field, based on fluid inclusion bulk volatile analysis are classified as gas discoveries except for F-O1 with gas condensate and oil shows.The integration of multi-mineral results and fluid inclusion studies show a dead oil stain with no visible liquid petroleum inclusion in the samples indicating the presence of quartz, kaolinite and stylolite as a major poro-perm constraint.

Magister Scientiae - MSc / Pressure drop within a field can be attributed to several factors. Pressure drop occurs when fractional forces cause resistance to flowing fluid through a porous medium. In this thesis, the sciences of petrophysics and rock physics were employed to develop understanding of the physical processes that occurs in reservoirs. This study focussed on the physical properties of rock and fluid in order to provide understanding of the system and the mechanism controlling its behaviour. The change in production capacity of wells E-M 1, 2, 3, 4&5 prompted further research to find out why the there will be pressure drop from the suits of wells and which well was contributing to the drop in production pressure. The E-M wells are located in the Bredasdorp Basin and the reservoirs have trapping mechanisms of stratigraphical and structural systems in a moderate to good quality turbidite channel sandstone. The basin is predominantly an elongated north-west and south-east inherited channel from the synrift sub basin and was open to relatively free marine circulation. By the southwest the basin is enclose by southern Outeniqua basin and the Indian oceans. Sedimentation into the Bredasdorp basin thus occurred predominantly down the axis of the basin with main input direction from the west. Five wells were studied E-M1, E-M2, E-M3, E-M4, and E-M5 to identify which well is susceptible to flow within this group. Setting criteria for discriminator the result generated four well as meeting the criteria except for E-M1. The failure of E-M1 reservoir well interval was in consonant with result showed by evaluation from the log, pressure and rock physics analyses for E-M1.iv Various methods in rock physics were used to identify sediments and their conditions and by applying inverse modelling (elastic impedance) the interval properties were better reflected. Also elastic impedance proved to be an economical and quicker method in describing the lithology and depositional environment in the absence of seismic trace.