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Structure and evolution of basin and petroleum systems within a transformrelated passive margin setting : data-based insights from crust-scale 3D modelling of the Western Bredasdorp Basin, offshore South AfricaSonibare, Wasiu Adedayo 04 1900 (has links)
Thesis (PhD)--Stellenbosch University, 2015. / ENGLISH ABSTRACT: This study investigates the crustal structure, and assesses the qualitative and quantitative impacts of crust-mantle dynamics on subsidence pattern, past and present-day thermal field and petroleum
system evolution at the southern South African continental margin through the application of a
multi-disciplinary and multi-scale geo-modelling procedure involving both conceptual and
numerical approaches. The modelling procedure becomes particularly important as this margin
documents a complex interaction of extension and strike-slip tectonics during its Mesozoic
continental rifting processes. Located on the southern shelf of South Africa, the Western
Bredasdorp Basin (WBB) constitutes the focus of this study and represents the western section of
the larger Bredasdorp sub-basin, which is the westernmost of the southern offshore sub-basins. To
understand the margin with respect to its present-day structure, isostatic state and thermal field, a
combined approach of isostatic, 3D gravity and 3D thermal modelling was performed by integrating
potential field, seismic and well data. Complimenting the resulting configuration and thermal field
of the latter by measured present-day temperature, vitrinite reflectance and source potential data,
basin-scale burial and thermal history and timing of source rock maturation, petroleum generation,
expulsion, migration and accumulation were forwardly simulated using a 3D basin modelling
technique. This hierarchical modelling workflow enables geologic assumptions and their associated
uncertainties to be well constrained and better quantified, particularly in three dimensions.
At present-day, the deep crust of the WBB is characterised by a tripartite density structure (i.e. prerift
metasediments underlain by upper and lower crustal domains) depicting a strong thinning that is
restricted to a narrow E-W striking zone. The configuration of the radiogenic crystalline crust as
well as the conductivity contrasts between the deep crust and the shallow sedimentary cover
significantly control the present-day thermal field of the study area. In all respects, this present-day
configuration reflects typical characteristics of basin evolution in a strike-slip setting. For instance,
the orientations of the deep crust and fault-controlled basin-fill are spatially inconsistent, thereby
indicating different extension kinematics typical of transtensional pull-apart mechanisms. As such,
syn-rift subsidence is quite rapid and short-lived, and isostatic equilibrium is not achieved,
particularly at the Moho level.
Accompanied syn-rift rapid subsidence and a heat flow peak led to petroleum preservation in the
basin since the Early Cretaceous. Two additional post-rift thermal anomalies related to the Late
Cretaceous hotspot mechanism and Miocene margin uplift in Southern Africa succeeded the syn-rift
control on maturation. This thermal maturity of the five mature source rocks culminated in four
main generation and three main accumulation phases which characterise the total petroleum systems
of the WBB. The Campanian, Eocene and Miocene uplift scenarios episodically halted source
maturation and caused tertiary migration of previously trapped petroleum. Petroleum loss related to
the spill point of each trap configuration additionally occurs during the Late Cretaceous-Paleocene
and Oligocene-Early Miocene. The timing and extent of migration dynamics are most sensitive to
the geological scenario that combined faulting, intrusive seal bypass system and facies
heterogeneity. In fact, for models that do not incorporate facies heterogeneity, predicted past and
present-day seafloor leakage of petroleum is largely underestimated. This complex interplay of
generation and migration mechanisms has significant implications for charging of petroleum
accumulations by multiple source rocks. Due to early maturation and late stage tertiary migration,
the syn-rift source rocks particularly Mid Hauterivian and Late Hauterivian source intervals
significantly control the extent of petroleum accumulation and loss in the basin.
Lastly, the modelled 3D crustal configuration and Mezosoic to Cenozoic thermal regime of the
WBB dispute classic uniform lithospheric stretching for the southern South African continental
margin. Rather, this PhD thesis confirms that differential thinning of the lithosphere related to a
transtensional pull-apart mechanism is the most appropriate for accurately predicting the evolution
of basin and petroleum systems of the margin. Also, the presented 3D models currently represent
the most advanced insights, and thus have clear implications for assessing associated risks in basin
and prospect evaluation of the margin as well as other similar continental margins around the world. / AFRIKAANSE OPSOMMING: Hierdie studie ondersoek die korsstruktuur en evalueer die kwalitatiewe en kwantitatiewe impakte
van kors-mantel-dinamika op insinkingspatroon, die termiese veld en petroleumstels evolusie aan
die suidelike Suid-Afrikaanse kontinentale grens, in die hede en die verlede, deur die toepassing van
’n multidissiplinêre en multiskaal-geomodelleringsprosedure wat beide konseptuele en numeriese
benaderings behels. Die modelleringsprosedure veral is belangrik aangesien hierdie kontinentale
grens ’n komplekse interaksie van uitbreidings- en strekkingsparallelle tektoniek gedurende die
Mesosoïese vastelandskeurprosesse daarvan dokumenteer. Omdat dit op die suidelike platvorm van
Suid-Afrika geleë is, maak die Westelike Bredasdorp Kom (WBK) die fokus van hierdie studie uit,
en verteenwoordig dit die westelike deel van die groter Bredasdrop-subkom, wat die verste wes is
van die suidelike aflandige subkomme. Om die grens met betrekking tot sy huidige struktuur,
isostatiese staat en termiese veld te verstaan, is ’n kombinasie benadering bestaande uit isostatiese,
3D-gravitasie- en 3D- termiese modellering gebruik deur potensiëleveld-, seismiese en boorgatdata
te integreer Ondersteunend totot die gevolglike konfigurasie en termiese veld van die laasgenoemde
deur middel van hedendaagse temperatuur, soos gemeet, vitriniet-refleksiekoëffisiënt en bronpotensiaal
data, komskaal-begrawing en termiese geskiedenis en tydsberekening van
brongesteentematurasie, is petroleumgenerasie, -uitwerping, -migrasie en -akkumulasie in die
toekoms gesimuleer deur gebruik te maak van ’n 3D-kommodelleringstegniek. Hierdie hierargiese
modelleringswerkvloei maak dit moontlik om geologiese aannames en hulle geassosieerde
onsekerhede goed aan bande te lê en beter te kwantifiseer, veral in drie dimensies.
In die hede word die diep kors van die WBK gekarakteriseer deur ’n drieledige digtheidstruktuur
(met ander woorde voorrift-metasedimente onderlê deur bo- en benedekors domeine) wat dui op ’n
baie wesenlike verdunning, beperk tot ’n dun O-W-strekkingsone. Die konfigurasie van die
radiogeniese kristallyne kors, sowel as die konduktiwiteitskontraste tussen die diep kors en die vlak
sedimentêre dekking, beheer grotendeels die hedendaagse termiese veld van die studiearea. Hierdie
hedendaagse konfigurasie weerspieël in alle opsigte tipiese eienskappe van kom-evolusie in ’n
skuifskeur omgewing. Byvoorbeeld, Die oriëntasies van die diep kors en verskuiwingbeheerde
komsedimentasie byvoorbeeld is ruimtelik inkonsekwent en dui daardeur op verskillende
ekstensiekinematika, tipies van transtensionale tensiemeganisme. As sulks, is sin-rift-versakking
taamlik vinnig en kortstondig, en word isostatiese ekwilibrium nie by die Moho-vlak, in die
besonder, bereik nie.
Samehangende sin-rift vinnige versakking en hittevloeihoogtepunt het gelei tot petroleum behoud in die kom sedert die vroeë Kryt. Twee bykomende post-rift termiese anomalieë wat verband hou met
die laat Kryt-“hotspot” meganisme en die Mioseense kontinentale grensopheffing in Suidelike
Afrika het die sin-rift-beheer met maturasie opgevolg. Hierdie termiese maturiteit van die vyf
gematureerde brongesteentes het in vier hoofgenerasie- en drie hoofakkumulasie fases, wat die
totaliteit van die petroleumstelsels van die WBK karakteriseer, gekulmineer. Die Campaniese,
Eoseense en Mioseense opheffings senarios het episodies bronmaturasie gestop en tersiêre migrasie
van petroleum wat vroeër opgevang was veroorsaak. Addisioneel vind petroleumverlies gekoppel
aan die spilpunt van elke opvanggebiedkonfigurasie tydens die laat Kryt-Paleoseen en Oligoseenvroeë
Mioseen plaas. Die tydstelling en omvang van migrasiedinamika is die sensitiefste vir die
geologiese scenario wat verskuiwing, seëlomseilingstelsel en fasiesheterogeniteit kombineer.
Trouens, vir modelle wat nie fasiesheterogeniteit inkorporeer nie, is voorspellings van vroeëre en
huidige seebodemlekkasie van petroleum grotendeels onderskattings. Hierdie komplekse
wisselwerking van generasie- en migrasiemeganismes het beduidende implikasies vir die laai van
petroleumakkumulasies deur veelvoudige brongesteentes. Vanweë vroeë maturasie en laatstadiumtersiêre
migrasie, oefen die sin-rift-brongesteentes, veral middel Hauterivium- en laat Hauteriviumbronintervalle,
beduidende beheer oor die omvang van petroleumakkumulasie en -verlies in die
kom uit.
Laastens weerspreek die gemodelleerde 3D-korskonfigurasie en Mesosoïese-tot-Senosoïesetermiese
regime van die WBK ’n klassieke uniforme litosferiese rekking vir die suidelike Suid-
Afrikaanse kontinentale grens. Inteendeel, hierdie PhD-proefskrif bevestig dat ’n differensiële
verdunning van die litosfeer, gekoppel aan ’n transtensiemeganisme, die beste geskik is om ’n
akkurate voorspelling oor die evolusie van kom- en petroleumstelsels van die kontinentale grens
mee te maak. Verder, verteenwoordig die 3D-modelle, wat hier aangebied word, tans die mees
gevorderde insigte, en het hierdie modelle dus duidelike implikasies vir die assessering van
verwante risiko’s in kom- en petroleum teikene valuering van die kontinentale grens, so wel as van
ander soortgelyke kontinentale grense regoor die wêreld.
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Assessment controls on reservoir performance and the affects of granulation seam mechanics in the Bredasdorp Basin, South Africa.Schalkwyk, Hugh Je-Marco January 2006 (has links)
<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 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.</p>
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Assessment controls on reservoir performance and the affects of granulation seam mechanics in the Bredasdorp Basin, South Africa.Schalkwyk, Hugh Je-Marco January 2006 (has links)
<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 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.</p>
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Assessment controls on reservoir performance and the affects of granulation seam mechanics in the Bredasdorp Basin, South AfricaSchalkwyk, Hugh Je-Marco January 2006 (has links)
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
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Sedimentological re-interpretation of the early cretaceous oil reservoir in the Northern Bredasdorp Basin, offshore South AfricaAsiashu, Mudau January 2015 (has links)
>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.
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Petrophysical characterization of sandstones, integrated with core sedimentology and laboratory analysis in the central part of Bredasdorp basin, Block 9, offshore South AfricaPrinsloo, Roxzanne Gladys January 2014 (has links)
>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.
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Porosity and Permeability Distribution in the Deep Marine Play of the Central Bredasdorp Basin, Block 9, Offshore South AfricaOJongokpoko, Hanson Mbi January 2006 (has links)
>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.
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Pore pressure prediction and direct hydrocarbon indicator: insight from the southern pletmos basin, offshore South AfricaLasisi, Ayodele Oluwatoyin January 2014 (has links)
>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
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Reservoir quality, structural architecture, fluid evolution and their controls on reservoir performance in block 9, F-O gas field, Bredasdorp Basin, offshore South AfricaFadipe, Oluwaseun Adejuwon January 2012 (has links)
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.
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Petrophysics and fluid mechanics of selected wells in Bredasdorp Basin South AfricaIle, Anthony January 2013 (has links)
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.
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