<p>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&rsquo / s.</p> <p><br> <br /> </br>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 10km&sup2 / 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.</p>

<p>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&rsquo / s.</p> <p><br> <br /> </br>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 10km&sup2 / 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.</p>

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 / 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.

<p>The main purpose of this study was to identify and characterize the various sand prone depositional facies in the deepwater Southern Outeniqua Basin which generally tend to form during&nbsp / lowstand (marine regression) conditions producing progradational facies. It made use of sequence stratigraphy and turbidite facies models to predict the probable location of deepwater&nbsp / reservoirs in the undrilled Southern Outeniqua Basin using data from basin margin Pletmos Basin and the deepwater Southern Outeniqua Basin. Basin margin depositional packages were&nbsp / correlated in time and space with deepwater packages. It was an attempt at bridging the gap between process-related studies of sedimentary rocks and the more traditional economic geology&nbsp / f commercial deposits of petroleum using prevailing state-of-the-art in basin analysis. It enabled the most realistic reconstructions of genetic stratigraphy and offered the greatest&nbsp / application in exploration. Sequence stratigraphic analysis and interpretation of seismics, well logs, cores and biostratigraphic data was carried out providing a chronostratigraphic framework of the study area within which seismic facies analysis done. Nine (9) seismic lines that span the shallow/basin margin Pletmos basin into the undrilled deepwater Southern Outeniqua basin were analysed and interpreted and the relevant seismic geometries were captured. Four (4) turbidite depositional elements were identified from the seismic lines: channel, overbank deposits,&nbsp / haotic deposits and basin plain (basin floor fan) deposits. These were identified from the relevant seismic geometries (geometric attributes) observed on the 2D seismic lines. Thinning attributes, unconformity attributes and seismic facies attributes were observed from the seismic lines. This was preceded by basic structural analyses and interpretation of the&nbsp / seismic lines. according to the structural analysis and interpretation, deposition trended NW-SE and NNW-SSE as we go deepwater into the Southern Outeniqua basin. Well logs from six (6)&nbsp / of the interpreted wells indicated depositional channel fill as well as basin floor fans. This was identified in well Ga-V1 and Ga-S1 respectively. A bell and crescent shape gamma ray log&nbsp / signature was observed in well Ga-V1 indicating a fining up sequence as the channel was abandoned while an isolated massive mound-shape gamma ray log signature was observed in&nbsp / Ga-S1 indicating basin plain well-sorted sands. Core analyses and interpretation from two southern-most wells revealed three (3) facies which were derived based on Walker&lsquo / s 1978, turbidite&nbsp / facies. The observed facies were: sandstone, sand/shale and shale facies. Sequence stratigraphic characterisation of petroleum reservoirs in block 11b/12b of the Southern Outeniqua&nbsp / Basin. Cores of well Ga-V1 displayed fine-grained alternations of thin sandstone beds and shales belonging to the thin-bedded turbidite facies. This is typical of levees of the upper fan channel but&nbsp / could easily be confused with similar facies on the basin plain. According to Walker, 1978 such facies form under conditions of active fan progradation. Ga-S1 cores displayed not only classic&nbsp / turbidite facies where there was alternating sand and shale sections but showed thick uninterrupted sections of clean sands. This is typical of basin plain deposits. Only one well had&nbsp / biostratigraphic data though being very limited in content. This data revealed particular depth sections and stratigraphic sections as having medium to fast depositional rates. Such rates are&nbsp / characteristic of turbidite deposition from turbidity currents. This study as well as a complementary study by Carvajal et al., 2009 revealed that the Southern Outeniqua basin is a sand-prone&nbsp / basin with many progradational sequences in which tectonics and sediment supply rate have been significant factors (amongst others such as sea level change) in the formation of these&nbsp / deepwater sequences. In conclusion, the Southern Outeniqua basin was hereby seen as having a viable and unexplored petroleum system existing in this sand prone untested world class.</p>

<p>The main purpose of this study was to identify and characterize the various sand prone depositional facies in the deepwater Southern Outeniqua Basin which generally tend to form during&nbsp / lowstand (marine regression) conditions producing progradational facies. It made use of sequence stratigraphy and turbidite facies models to predict the probable location of deepwater&nbsp / reservoirs in the undrilled Southern Outeniqua Basin using data from basin margin Pletmos Basin and the deepwater Southern Outeniqua Basin. Basin margin depositional packages were&nbsp / correlated in time and space with deepwater packages. It was an attempt at bridging the gap between process-related studies of sedimentary rocks and the more traditional economic geology&nbsp / f commercial deposits of petroleum using prevailing state-of-the-art in basin analysis. It enabled the most realistic reconstructions of genetic stratigraphy and offered the greatest&nbsp / application in exploration. Sequence stratigraphic analysis and interpretation of seismics, well logs, cores and biostratigraphic data was carried out providing a chronostratigraphic framework of the study area within which seismic facies analysis done. Nine (9) seismic lines that span the shallow/basin margin Pletmos basin into the undrilled deepwater Southern Outeniqua basin were analysed and interpreted and the relevant seismic geometries were captured. Four (4) turbidite depositional elements were identified from the seismic lines: channel, overbank deposits,&nbsp / haotic deposits and basin plain (basin floor fan) deposits. These were identified from the relevant seismic geometries (geometric attributes) observed on the 2D seismic lines. Thinning attributes, unconformity attributes and seismic facies attributes were observed from the seismic lines. This was preceded by basic structural analyses and interpretation of the&nbsp / seismic lines. according to the structural analysis and interpretation, deposition trended NW-SE and NNW-SSE as we go deepwater into the Southern Outeniqua basin. Well logs from six (6)&nbsp / of the interpreted wells indicated depositional channel fill as well as basin floor fans. This was identified in well Ga-V1 and Ga-S1 respectively. A bell and crescent shape gamma ray log&nbsp / signature was observed in well Ga-V1 indicating a fining up sequence as the channel was abandoned while an isolated massive mound-shape gamma ray log signature was observed in&nbsp / Ga-S1 indicating basin plain well-sorted sands. Core analyses and interpretation from two southern-most wells revealed three (3) facies which were derived based on Walker&lsquo / s 1978, turbidite&nbsp / facies. The observed facies were: sandstone, sand/shale and shale facies. Sequence stratigraphic characterisation of petroleum reservoirs in block 11b/12b of the Southern Outeniqua&nbsp / Basin. Cores of well Ga-V1 displayed fine-grained alternations of thin sandstone beds and shales belonging to the thin-bedded turbidite facies. This is typical of levees of the upper fan channel but&nbsp / could easily be confused with similar facies on the basin plain. According to Walker, 1978 such facies form under conditions of active fan progradation. Ga-S1 cores displayed not only classic&nbsp / turbidite facies where there was alternating sand and shale sections but showed thick uninterrupted sections of clean sands. This is typical of basin plain deposits. Only one well had&nbsp / biostratigraphic data though being very limited in content. This data revealed particular depth sections and stratigraphic sections as having medium to fast depositional rates. Such rates are&nbsp / characteristic of turbidite deposition from turbidity currents. This study as well as a complementary study by Carvajal et al., 2009 revealed that the Southern Outeniqua basin is a sand-prone&nbsp / basin with many progradational sequences in which tectonics and sediment supply rate have been significant factors (amongst others such as sea level change) in the formation of these&nbsp / deepwater sequences. In conclusion, the Southern Outeniqua basin was hereby seen as having a viable and unexplored petroleum system existing in this sand prone untested world class.</p>

Magister Scientiae - MSc / The main purpose of this study was to identify and characterize the various sand prone depositional facies in the deepwater Southern Outeniqua Basin which generally tend to form during lowstand (marine regression) conditions producing progradational facies. It made use of sequence stratigraphy and turbidite facies models to predict the probable location of deepwater reservoirs in the undrilled Southern Outeniqua Basin using data from basin margin Pletmos Basin and the deepwater Southern Outeniqua Basin. Basin margin depositional packages were correlated in time and space with deepwater packages. It was an attempt at bridging the gap between process-related studies of sedimentary rocks and the more traditional economic geology f commercial deposits of petroleum using prevailing state-of-the-art in basin analysis. It enabled the most realistic reconstructions of genetic stratigraphy and offered the greatest application in exploration. Sequence stratigraphic analysis and interpretation of seismics, well logs, cores and biostratigraphic data was carried out providing a chronostratigraphic framework of the study area within which seismic facies analysis done. Nine (9) seismic lines that span the shallow/basin margin Pletmos basin into the undrilled deepwater Southern Outeniqua basin were analysed and interpreted and the relevant seismic geometries were captured. Four (4) turbidite depositional elements were identified from the seismic lines: channel, overbank deposits, haotic deposits and basin plain (basin floor fan) deposits. These were identified from the relevant seismic geometries (geometric attributes) observed on the 2D seismic lines. Thinning attributes, unconformity attributes and seismic facies attributes were observed from the seismic lines. This was preceded by basic structural analyses and interpretation of the seismic lines. according to the structural analysis and interpretation, deposition trended NW-SE and NNW-SSE as we go deepwater into the Southern Outeniqua basin. Well logs from six (6) of the interpreted wells indicated depositional channel fill as well as basin floor fans. This was identified in well Ga-V1 and Ga-S1 respectively. A bell and crescent shape gamma ray log signature was observed in well Ga-V1 indicating a fining up sequence as the channel was abandoned while an isolated massive mound-shape gamma ray log signature was observed in Ga-S1 indicating basin plain well-sorted sands. Core analyses and interpretation from two southern-most wells revealed three (3) facies which were derived based on Walker‘s 1978, turbidite facies. The observed facies were: sandstone, sand/shale and shale facies. Sequence stratigraphic characterisation of petroleum reservoirs in block 11b/12b of the Southern Outeniqua Basin. Cores of well Ga-V1 displayed fine-grained alternations of thin sandstone beds and shales belonging to the thin-bedded turbidite facies. This is typical of levees of the upper fan channel but could easily be confused with similar facies on the basin plain. According to Walker, 1978 such facies form under conditions of active fan progradation. Ga-S1 cores displayed not only classic turbidite facies where there was alternating sand and shale sections but showed thick uninterrupted sections of clean sands. This is typical of basin plain deposits. Only one well had biostratigraphic data though being very limited in content. This data revealed particular depth sections and stratigraphic sections as having medium to fast depositional rates. Such rates are characteristic of turbidite deposition from turbidity currents. This study as well as a complementary study by Carvajal et al., 2009 revealed that the Southern Outeniqua basin is a sand-prone basin with many progradational sequences in which tectonics and sediment supply rate have been significant factors (amongst others such as sea level change) in the formation of these deepwater sequences. In conclusion, the Southern Outeniqua basin was hereby seen as having a viable and unexplored petroleum system existing in this sand prone untested world class. / South Africa