The Nigeria economy is wholly dependent on revenue from oil. However, bitumen has been discovered in the country since 1903 and has remained untapped over the years. The need for the country to complement oil exploration with the huge bitumen deposit cannot be overemphasized. This will help to improve the country's gross domestic product (GDP) and revenue available to government. Bitumen is classifled as heavy crude with API (American petroleum Institute) number ranging between 50 and 110 and occurs in Nigeria, Canada, Saudi Arabia, Venezuela etc from which petroleum products could be derived. This dissertation looked at the Canadian experience by comparing the oil and tar sand deposit found in Canada with particular reference to Athabasca (Grosmont, Wabiskaw McMurray and Nsiku) with that in Nigeria with a view of transferring process technology from Canada to Nigeria. The Nigeria and Athabasca tar sands occur in the same type of environment. These are the deltaic, fluvial marine deposit in an incised valley with similar reservoir, chemical and physical properties. However, the Nigeria tar sand is more asphaltenic and also contains more resin and as such will yield more product volume during hydro cracking albeit more acidic. The differences in the components (viscosity, resin and asphaltenes contents, sulphur and heavy metal contents) of the tar sands is within the limit of technology adaptation. Any of the technologies used in Athabasca, Canada is adaptable to Nigeria according to the findings of this research. The techno-economics of some of the process technologies are. x-rayed using the PTAC (petroleum technology alliance Canada) technology recovery model in order to obtain their unit cost for Nigeria bitumen. The unit cost of processed bitumen adopting steam assisted gravity drainage (SAGD), in situ combustion (ISC) and cyclic steam stimulation (CSS) process technology is 40.59, 25.00 and 44.14 Canadian dollars respectively. The unit cost in Canada using the same process technology is 57.27, 25.00 and 61.33 Canadian dollars respectively. The unit cost in Nigeria is substantively lesser than in Canada. A trade off is thereafter done using life cycle costing so as to select the best process technology for the Nigeria oil/tar sands. The net present value/internal rate of return is found to be B$3,062/36.35% for steam assisted gravity drainage, B$I,570124.51 % for cyclic steam stimulation and B$3,503/39.64% for in situ combustion. Though in situ combustion returned the highest net present value and internal rate of return, it proved not to be the best option for Nigeria due to environmental concern and response time to production. The best viable option for the Nigeria tar sand was then deemed to be steam assisted gravity drainage. An integrated oil strategy coupled with cogeneration using MSAR was also seen to considerably amplify the benefits accruable from bitumen exploration; therefore, an investment in bitumen exploration in Nigeria is a wise economic decision. / Thesis (M.Ing. (Development and Management))--North-West University, Potchefstroom Campus, 2010.

The Nigeria economy is wholly dependent on revenue from oil. However, bitumen has been discovered in the country since 1903 and has remained untapped over the years. The need for the country to complement oil exploration with the huge bitumen deposit cannot be overemphasized. This will help to improve the country's gross domestic product (GDP) and revenue available to government. Bitumen is classifled as heavy crude with API (American petroleum Institute) number ranging between 50 and 110 and occurs in Nigeria, Canada, Saudi Arabia, Venezuela etc from which petroleum products could be derived. This dissertation looked at the Canadian experience by comparing the oil and tar sand deposit found in Canada with particular reference to Athabasca (Grosmont, Wabiskaw McMurray and Nsiku) with that in Nigeria with a view of transferring process technology from Canada to Nigeria. The Nigeria and Athabasca tar sands occur in the same type of environment. These are the deltaic, fluvial marine deposit in an incised valley with similar reservoir, chemical and physical properties. However, the Nigeria tar sand is more asphaltenic and also contains more resin and as such will yield more product volume during hydro cracking albeit more acidic. The differences in the components (viscosity, resin and asphaltenes contents, sulphur and heavy metal contents) of the tar sands is within the limit of technology adaptation. Any of the technologies used in Athabasca, Canada is adaptable to Nigeria according to the findings of this research. The techno-economics of some of the process technologies are. x-rayed using the PTAC (petroleum technology alliance Canada) technology recovery model in order to obtain their unit cost for Nigeria bitumen. The unit cost of processed bitumen adopting steam assisted gravity drainage (SAGD), in situ combustion (ISC) and cyclic steam stimulation (CSS) process technology is 40.59, 25.00 and 44.14 Canadian dollars respectively. The unit cost in Canada using the same process technology is 57.27, 25.00 and 61.33 Canadian dollars respectively. The unit cost in Nigeria is substantively lesser than in Canada. A trade off is thereafter done using life cycle costing so as to select the best process technology for the Nigeria oil/tar sands. The net present value/internal rate of return is found to be B$3,062/36.35% for steam assisted gravity drainage, B$I,570124.51 % for cyclic steam stimulation and B$3,503/39.64% for in situ combustion. Though in situ combustion returned the highest net present value and internal rate of return, it proved not to be the best option for Nigeria due to environmental concern and response time to production. The best viable option for the Nigeria tar sand was then deemed to be steam assisted gravity drainage. An integrated oil strategy coupled with cogeneration using MSAR was also seen to considerably amplify the benefits accruable from bitumen exploration; therefore, an investment in bitumen exploration in Nigeria is a wise economic decision. / Thesis (M.Ing. (Development and Management))--North-West University, Potchefstroom Campus, 2010.

Made available in DSpace on 2014-12-17T14:08:54Z (GMT). No. of bitstreams: 1 HumbertoSC_DISSERT.pdf: 7792135 bytes, checksum: 5204c60825f60e9f74c5f24e46e8aa4e (MD5) Previous issue date: 2013-07-29 / Nearly 3 x 1011 m3 of medium and light oils will remain in reservoirs worldwide after conventional recovery methods have been exhausted and much of this volume would be recovered by Enhanced Oil Recovery (EOR) methods. The in-situ combustion (ISC) is an EOR method in which an oxygen-containing gas is injected into a reservoir where it reacts with the crude oil to create a high-temperature combustion front that is propagated through the reservoir. The High Pressure Air Injection (HPAI) method is a particular denomination of the air injection process applied in light oil reservoirs, for which the combustion reactions are dominant between 150 and 300?C and the generation of flue gas is the main factor to the oil displacement. A simulation model of a homogeneous reservoir was built to study, which was initially undergone to primary production, for 3 years, next by a waterflooding process for 21 more years. At this point, with the mature condition established into the reservoir, three variations of this model were selected, according to the recovery factors (RF) reached, for study the in-situ combustion (HPAI) technique. Next to this, a sensitivity analysis on the RF of characteristic operational parameters of the method was carried out: air injection rate per well, oxygen concentration into the injected gas, patterns of air injection and wells perforations configuration. This analysis, for 10 more years of production time, was performed with assistance of the central composite design. The reservoir behavior and the impacts of chemical reactions parameters and of reservoir particularities on the RF were also evaluated. An economic analysis and a study to maximize the RF of the process were also carried out. The simulation runs were performed in the simulator of thermal processes in reservoirs STARS (Steam, Thermal, and Advanced Processes Reservoir Simulator) from CMG (Computer Modelling Group). The results showed the incremental RF were small and the net present value (NPV) is affected by high initial investments to compress the air. It was noticed that the adoption of high oxygen concentration into the injected gas and of the five spot pattern tends to improve the RF, and the wells perforations configuration has more influence with the increase of the oil thickness. Simulated cases relating to the reservoir particularities showed that smaller residual oil saturations to gas lead to greater RF and the presence of heterogeneities results in important variations on the RF and on the production curves / Aproximadamente 3 x 1011 m3 de ?leos m?dios e leves restar?o nos reservat?rios ao redor do mundo ap?s a aplica??o dos m?todos convencionais de recupera??o e grande parte desse volume seria recuper?vel com o uso de m?todos especiais. A combust?o in-situ (CIS) ? um m?todo de recupera??o avan?ada de petr?leo no qual um g?s que cont?m oxig?nio ? injetado no reservat?rio onde reage com o ?leo cru para criar uma frente de combust?o de alta temperatura que se propaga pelo reservat?rio. O m?todo HPAI (High Pressure Air Injection) ? uma denomina??o particular do processo de inje??o de ar aplicado em reservat?rios de ?leos leves, onde as rea??es de combust?o s?o dominantes entre 150 e 300?C e a gera??o de flue gas ? o principal fator de deslocamento do ?leo. Um modelo de simula??o de fluxo de um reservat?rio homog?neo foi constru?do para o estudo, o qual foi inicialmente submetido ? produ??o prim?ria, por 3 anos, e em seguida, ao processo de inje??o de ?gua por mais 21 anos. Nesse ponto, com a condi??o madura estabelecida no reservat?rio, foram selecionadas tr?s varia??es desse modelo, de acordo com o fator de recupera??o (FR) obtido, para o estudo da t?cnica de combust?o in-situ (HPAI). Em seguida realizou-se uma an?lise de sensibilidade sobre o FR de par?metros operacionais pr?prios do m?todo: vaz?o de inje??o de ar por po?o, concentra??o de oxig?nio no g?s injetado, esquema de inje??o de ar e configura??o dos canhoneados dos po?os. Essa an?lise, para um per?odo adicional de at? 10 anos produ??o, foi efetuada com o aux?lio da t?cnica de planejamento composto central. O comportamento do reservat?rio e os impactos de par?metros envolvendo as rea??es qu?micas e de particularidades de reservat?rio sobre o FR tamb?m foram avaliados. Adicionalmente foram elaborados uma an?lise econ?mica e um estudo de maximiza??o do FR do processo. As simula??es foram realizadas com o simulador de processos t?rmicos em reservat?rios STARS (Steam, Thermal and Advanced Process Reservoir Simulation) da CMG (Computer Modelling Group). Os resultados mostraram que os FR incrementais foram baixos e que o valor presente l?quido (VPL) ? impactado negativamente pelos elevados investimentos iniciais para compress?o do ar. Observou-se que a ado??o de maiores concentra??es de oxig?nio no g?s injetado e do esquema de inje??o de ar tipo five spot tende a favorecer o FR, e que a configura??o dos canhoneados dos po?os apresenta influ?ncia crescente com o aumento da espessura porosa com ?leo do reservat?rio. Casos simulados referentes ?s particularidades de reservat?rio indicaram que menores satura??es residuais de ?leo ao g?s levam a FR maiores e que a exist?ncia de heterogeneidades resulta em varia??es consider?veis nos FR e nas curvas de produ??o