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Collaborating Authors
Petroleum Source Rock Potential of the Upper Benue Trough, Nigeria: Implications for Hydrocarbon Exploration
Raji, Jamiudeen Kayode (Department of Petroleum Engineering and Geosciences, Petroleum Training Institute, Effurun, Delta State) | Adebowale, Ademola Olabisi (Department of Petroleum Engineering and Geosciences, Petroleum Training Institute, Effurun, Delta State)
Abstract Forty six (46) shale samples were collected from borehole, quarry and outcrop in the Northern Benue Trough which consists of Gongola and Yola Basins respectively. The Gongola Basin comprises Bima Formation, the Yolde Formation, Pindiga/Gongila Formation and capped with Gombe Formation whereas the Yola Bain consists of Bima Formation, Yolde Formation, Dukul/Jessu/Numanha Formation and capped with Lamja Formation. The samples were subjected to vitrinite reflectance, Rock Eval pyrolysis and infrared spectroscopy in order to evaluate their organic richness, thermal maturity and petroleum generating potential. The total organic carbon (TOC) values of the Gongola Basin are between 0.20 and 2.46 wt. % averaging 0.70 wt. % while that of Yola Basin range from 0.11 to 12.9 wt. % averaging 1.50 wt. %. The mean random vitrinite reflectance (Rom) values in the Gongola Basin range from 0.48% in the Gombe Formation to 0.65% in the Pindiga Formation and 0.67% in the Gongila Formation. Also, the reflectance values in the Yola Basin increase with stratigraphic age ranging from 0.63 to 0.80% in the Dukul and Yolde Formations respectively. The thermal maturity of the organic matter (Tmax) values from the pyrolysis of shales in the Gongola Basin is between 420 and 440°C while that of Yola Basin range from 435 to 445°C. The plot of hydrogen index (HI) vs Tmax for classification of kerogen in the Gongila and Pindiga Formations reveals prevalence of Type III kerogen while that of Dukul and Yolde Formations shows Type II – III kerogen. The results obtained suggest that Gongola Basin source rocks are fair and thermally immature to marginally mature and have potential to generate gas in the deeply buried section whereas the Yola Basin source rock are between fair to good and thermally mature with potential to generate oil and gas in the deeper section.
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (1.00)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.58)
Over the past decade, a new generation of acoustic logging tools has been developed. These new tools are specifically designed to measure formation shear velocity in all types of rocks-information that is not always available with a conventional acoustic tool. Knowledge of the formation shear velocity can improve well evaluation, particularly by enhancing our understanding of the mechanical properties of formations of interest. Acoustic sources create a pressure wave in the borehole fluid. In a conventional tool, this pressure wave expands uniformly in all directions away from the source. Consequently, movement that is symmetric around the borehole axis is induced in the formation. The acoustic sources in the new tools also generate pressure waves in the borehole fluids, but the waves are not symmetric around the borehole axis. These asymmetric pressure waves result in acoustic propagation along the borehole that differs significantly from the propagation induced by a conventional acoustic source. The properties of the modes produced by these sources can be used to measure formation shear velocity. A conventional acoustic-logging source is a monopole transducer that can be numerically modeled as a single point source. New sources that have been successfully developed into logging tools include dipoles and quadrupoles. Numerical modeling of these sources requires a more complex representation of the source than does the monopole tool. As a class, these new acoustic transducers can be called multipoles.
- Europe (0.94)
- North America > United States > Texas (0.15)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.94)
- Geophysics > Seismic Surveying > Seismic Processing (0.80)
Theoretical investigations on the performance of such multipole logging tools in elastic formations have been performed by several authors. Recent theoretical and experimental studies, and fieldwork In this paper, we address the problem of multipole logging have demonstrated the interest of using multipole sources, in a (multilayered) formation.
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.31)
Abstract The majority of oil fields in Africa and the Middle East were discovered in the 1950's. If we take into account the rate of development of these fields, we find that many of them are at the point or just about where secondary recovery or pressure maintenance becomes necessary. For that purpose, water injection is by far the most popular process. At this point we then face a major problem: availability of water. In that part of the world (Africa and the Middle East), the only sources of water available are sea water and, in most of the cases, deep brackish water, which are incompatible, from the standpoint of chemical composition, with formation water. This incompatibility might lead to disastrous scale formation that would properly kill wells and even fields. This problem will be more acute in the case of pattern injection compared with peripheral injection. peripheral injection. In order to proceed with water injection, we are left with two alternatives:water treatment before injection and chemical inhibition of scale formation. Neither of these alternatives has been fully recognized as an effective and feasible way under prevailing economics to run a trouble-free water injection program with incompatible waters. This paper is directed toward the engineers who may face the task of designing a water injection program where the only water source available is program where the only water source available is incompatible with formation water. A research work currently is underway to develop a proper way to evaluate scale inhibitors under actual field conditions, in order to solve the scale formation problem around the wellbore, in the production string, and in the surface installations. production string, and in the surface installations. In the meantime, work is underway to set up a pilot for water treatment before injection. WATER INJECTION-AN OVERVIEW Water injection is by far the most popular secondary recovery and pressure maintenance method. Its popularity did build up in the United States and Canada, mainly because of the availability of a water source almost everywhere. Many factors should be considered to determine the suitability of a given reservoir to waterflooding or pressure maintenance. These factors are important because they influence the economics of a given project. Some of these factors would be reservoir characteristics: rocks properties (permeability, porosity), depth, fluid saturation, etc. Factors other than reservoir characteristics also will have a great influence. In this particular case we are interested in, another factor is the availability of water. When the suitability of a given project is determined, the next important question to be answered is when a given project should be initiated. It ha been recognized that the only way to determine the optimum time to start a waterflood or a pressure maintenance program is to compute recovery, rate, investment, and income for several times of initiation and optimize on the basis of economic criteria that are specific to each company. AVAILABILITY OF WATER Most of the oil and gas fields in Algeria are located in the Sahara Desert. Therefore, the availability of a water source in an arid zone becomes an obvious problem, while the need for water injection is obvious for a certain number of reservoirs. A pressure maintenance program was initiated in 1966 for the Zarzaitine Field near the Lybian border in the southeastern portion of the Illizi Basin in Algeria. The reservoir under consideration is at about 1450 m subsea, with a maximum thickness of about 70 m. It is a saturated reservoir with a gas cap. The original producing mechanism was a combination of solution gas drive, gas-cap expansion, and partial water drive.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Africa > Middle East > Algeria > Illizi Province > Illizi Basin > Zarzaitine Field (0.99)
- North America > United States (0.89)
- North America > Canada (0.89)
Key Factors of Tight Oil Accumulation of Permian Lucaogou Formation in the Jimsar Sag of Junggar Basin, Northwestern China
Ding, Xiujian (School of Geosciences in China University of Petroleum) | Zha, Ming (School of Geosciences in China University of Petroleum) | Gao, Changhai (School of Geosciences in China University of Petroleum) | Qu, Jiangxiu (School of Geosciences in China University of Petroleum) | Su, Yang (School of Geosciences in China University of Petroleum) | Lian, Huan (School of Geosciences in China University of Petroleum)
Summary The Permian Lucaogou Formation is the primary exploratory stratum of tight oil reservoirs in the Jimsar Sag of Junggar basin, Northwestern China. The Lucaogou organic-rich sediments composed of grayish mudstones and dolomitic mudstones are world class source rocks. Lucaogou source rocks exhibit a wide range in TOC contents, laterally from 0.03 wt.% to 19.77 wt.%, and the hydrocarbon generation index (Si+S2) is in the range of 0.11-79.4 mg/g. The source rocks are dominated by Type I and II kerogen, considered to be oil-prone. The Lucaogou source rocks interbed with the fine-grained dolomitic reservoirs, characterized by integrative source rock and reservoir. Apart from a small amount of micron-scale and millimeter-scale pores and dissolved pores with relatively large throats, the tight reservoir rocks contain a large amount of nano-scale pores and microfractures which can be observed with SEM. Fracture-pore, intergranular and dissolution pore and intercrystalline pore dominate the nanoscale pores and usually have a diameter of 100-750 nm. "Sweet spots", defined as the tight oil reservoirs interval with porosity of more than 6%, are the main pay zones and key points of exploration and development in Jimsar sag. The world class source rocks and dolomitic tight reservoir of Lucaogou Formation are widely distributed and form an optimal source-reservoir-caprock combination through space and time in Jimsar sag. Tight oil entered into the adjacent reservoir from source rocks without long distance migration, characterized by continuous distribution in the center or along the slopes of Jimsar Sag.
- North America > United States > Texas (1.00)
- Asia > China > Xinjiang Uyghur Autonomous Region (0.67)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.93)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
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