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Africa (Sub-Sahara) Mazarine Energy has started a two-well drilling campaign in the Zaafrane permit in central Tunisia. The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific Australia Pacific LNG has received its first gas from coal seam gas fields in the Surat basin. The gas is being carried to its liquefied natural gas (LNG) facility on Curtis Island, near Gladstone, Queensland, by a 530-km high-pressure gas pipeline, which was recently commissioned. With the arrival of gas, Australia Pacific can begin commissioning power generator facilities on the island. The company expects to deliver its first LNG in the middle of the year.
Africa (Sub-Sahara) Eni reported that the Laarich East-1 oil well in Tunisia has a delivery capacity of approximately 2,000 B/D. Spudded in June, the well discovered hydrocarbons in Silurian and Ordovician sandstones while reaching a final depth of 13,487 ft. The well has now been connected to production. The company continues to drill Tunisian exploration prospects that have been identified on 3D seismic surveys. Eni owns a 50% stake in the Makhrouga-Laarich-Debbech license, where the Laarich East-1 well is located. State company Enterprise Tunisienne d'Activités Pétrolières holds the remaining stake. Shell's new natural gas discoveries in Egypt are estimated in initial quantities at about 500 Bcf with more reserves possible, said Aidan Murphy, chairman and managing director of Shell Egypt.
Africa (Sub-Sahara) Mazarine Energy has started a two-well drilling campaign in the Zaafrane permit in central Tunisia. The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific China National Offshore Oil Company (CNOOC) has made a natural gas discovery at its deepwater Lingshui 25-1 well, northeast of Ledong sag in the South China Sea's Qiongdongnan basin, where the average water depth is 980 m. The well was drilled to a depth of 4000 m and encountered 73 m of oil and gas pay. During a test, the well produced approximately 35 MMcf/D of natural gas and 395 BOPD. CNOOC holds full operated interest in the license.
Fedorovich, M. O. (A.A. Trofimuk Institute of Petroleum Geology and Geophysics, Siberian Branch of RAS) | Kosmacheva, A. Yu. (A.A. Trofimuk Institute of Petroleum Geology and Geophysics, Siberian Branch of RAS) | Pospeeva, N. V. (Siberian Research Institute of Geology, Geophysics and Mineral Resources)
The PDF file of this paper is in Russian.
The paper is aimed at the one-dimensional petroleum system modeling in a well section of the Tolonskoye gas-condensate field. Tectonically, it is confined to the Khapchagai megalithic bank located in the central part of the Vilyui hemisyneclise. The modeling identifies burial and thermal history of the sediments in the Paleozoic, Mesozoic and Cenozoic, quantitive evaluation of generation power and oil-window- and gas-window-entry time of the source rocks. According to the present research, the Kuonam source rock reached up to the oil window 449 Ma in the Katian age and gas window 410 Ma in the Pragian age. The Permian source rock top reached up to the oil window 249 Ma in the Olenekian age. The Permian source rock middle did to the gas window 258 Ma in the Wuchiapingian age. The Kuonam source rock had already been beyond the oil and gas windows by ending the sedimentation of the Nedzhelin and Monom seal rocks for the Upper Permian and Lower Triassic reservoirs. There was consequently no appropriate environment for the hydrocarbon accumulations generated by marine organic matter to be preserved. The Permian source rock top and middle are found to be in the oil and gas windows at the present time, respectively. The hydrocarbon accumulations principally generated by terrestrial organic matter can therefore be in the Upper Permian and Lower Triassic reservoirs. Maximum temperature values and rapid change in organic matter maturity in the Late Permian and Early Triassic imply trap rocks in the sediments. Generation power of the Kuonam source rock and Permian source rock bottom is completely exhausted. The Permian source rock top, by comparison, is of significant generation capability. The generation balance of the source rocks is 18.942 BT of hydrocarbons (hydrocarbon equivalent), with the Permian source rock contribution being essential. The remaining source rock potential is 5.187 BT of hydrocarbons (hydrocarbon equivalent). Complying with the initial commercial reserves of the Tolonskoye field the reservoir balance is up to 0.7 % in relation to the generation balance.
В статье рассмотрено одномерное моделирование нефтегазоносных систем в разрезе скважины Толонского газоконденсатного месторождения. Месторождение в тектоническом плане приуроченного к Хапчагайскому мегавалу, который осложняет центральную часть Вилюйской гемисинеклизы. Моделирование выполнялось с целью восстановления истории погружения и тепловой истории осадочных комплексов в палеозойское, мезозойское и кайнозойское время, количественной оценки генерационного потенциала нефтегазоматеринских толщ и определения времени их вхождения в главные зоны нефте- и газообразования. Установлено, что нефтегазоматеринские отложения куонамской формации вошли в главную зону нефтеобразования 449 млн лет назад в катийское время, в главную зону интенсивного газообразования – 410 млн лет назад в пражское время. Нефтегазоматеринские отложения перми кровлей вошли в главную зону нефтеобразования 249 млн лет назад в оленекское время, центральная часть нефтегазоматеринских отложений перми погрузилась в главную зону интенсивного газообразования 258 млн лет назад в вятское время. На конец формирования основных флюидоупоров, неджелинской и мономской свит, для залежей верхней перми и нижнего триаса нефтегазоматеринские отложения куонамской формации уже вышли из главных зон нефтеобразования и интенсивного газообразования, и залежи углеводородов, генерированные аквагенным органическим веществом, не сохранились. В настоящее время верхняя и центральная части нефтегазоматеринских отложений перми находятся в главных зонах нефтеобразования и интенсивного газообразования, и залежи углеводородов, генерированные преимущественно террагенным органическим веществом, могли накапливаться в резервуарах верхней перми и нижнего триаса. Максимальные температуры и скачок катагенетической преобразованности органического вещества, приуроченные к границе перми и триаса, свидетельствуют о наличии трапповых тел в разрезе осадочного бассейна. Нефтегазоматеринские отложения куонамской формации и породы в основании нефтегазоматеринских отложений перми полностью исчерпали свой нефтегазогенерационный потенциал, тогда как породы в кровле нефтегазоматеринских отложений перми обладают значительными генерационными возможностями. Общее количество генерированных углеводородов составляет 18,942 млрд т условных углеводородов, подавляющая часть которых образована породами нефтегазоматеринских отложений перми. Нереализованный углеводородный потенциал нефтегазоматеринских отложений перми составляет 5,187 млрд т условных углеводородов. Количество аккумулированных углеводородов в ловушках достигает 0,7 % генерированных, что соответствует начальным запасам углеводородов промышленных категорий в пределах Толонского месторождения.
In underexplored sedimentary basins such as the Canning Basin, understanding the geochemical property distribution is critical for successful exploration of unconventional hydrocarbon resources. This study utilizes an integrated approach to characterize the organic rich sections of the Ordovician Goldwyer Formation, in terms of their potential for shale oil and gas, on the Broome Platform of the Canning Basin. Core and cuttings samples from a large number of wells were analysed by pyrolysis of the organic matter (Rock-Eval 6 and kinetic studies), while additional geochemical data were collated from the Western Australia Department of Mines and Petroleum (WAPIMS) online database. A Machine Learning method was used to predict continuous geochemical logs in wells with limited or no geochemical based on available information from other wells with good downhole geochemical data and logs within in the Goldwyer Formation. The optimised geochemical logs in all wells were then used to create 3D petrophysical property models to predict the geochemical property distribution of this interval across the study area using the Kriging method in Petrel (Schlumberger software).
Burial and thermal history models were constructed in Petromod (Schlumberger software) for five selected well locations to assess the evolution through time of the kerogen maturity and transformation in the Goldwyer Formation. The pyrolysis and kinetic results indicate that the Goldwyer III shale unit shows fair to good hydrocarbon generative potential across the study area and is mostly within the early to peak mature stage generation at present day.
The average geochemical property distribution maps showed that the distribution of kerogen type (HI), total organic carbon (TOC), free hydrocarbons (S1) and yield potential (S2) are higher in the central to south-eastern part of the study area, while relatively lower values occur in the north-western part. The burial history models indicate that kerogen transformation in the Goldwyer III shale unit increases gradually from the north-western part of the study area to the south-eastern area where the kerogen transformation is highest. However, the maturation history is complicated because the region has experienced at least two episodes of burial with exposure to higher temperatures and pressures.
The best organic rich shales in the Goldwyer III unit for shale oil and gas occur in the central to the south-eastern part of the study area. This conclusion is based on an integrated study of their organic geochemical properties, kerogen transformation kinetics and thermal maturity. The timing of the generative episodes relative to trap formation remains an issue for successful conventional petroleum exploration. However, this is not such a major impediment to economic production for unconventional prospects.
Piane, Claudio Delle (CSIRO Energy, Perth, Australia) | Clennell, Ben (CSIRO Energy, Perth, Australia) | Josh, Matthew (CSIRO Energy, Perth, Australia) | Dewhurst, Dave (CSIRO Energy, Perth, Australia)
Recovery of hydrocarbons from organic-rich shales has played a significant role in changing the distribution of reserves worldwide and has also impacted on carbon dioxide emissions where extracted gas has been used to replace coal to power electricity grids. Such extraction is predicated on a good understanding of local and regional geological history as well as close examination of the rocks involved from seismic to nano-scale. This study looks at the impact of thermal maturity on the organic and diagenetic mineral fabrics observed in gas shales from different parts of the world, highlighting similarities and differences in their impacts on rock properties. Organic fabrics can present as pore filling migrated bitumen visualized in scanning and transmission elctron microsopy and the degree of thermal maturity directly impacts for example on the electrical properties, shown by contrasting examples from the Marcellus (ultra-high maturity) and Utica (moderately high maturity) shales; the former has extremely low resitivity while the latter extremely high. Dielectric properties are shown to be useful for rock typing in the Utica shale where standard resistivity logs are off the scale as the material is so resistive. Such properties have also been shown to be useful for estimating water saturation in the Roseneath-Epsilon-Murteree Formations of the Cooper Basin. Mineral diagenesis and its timing are also shown to be important for quartz cementation and pore structure modification in the Marcellus, Bongabinni and Goldwyer formations, with the latter two contrasted in terms of elastic and strength properties. Overall, micro-structural, laboratory and wireline log studies combined have given significant insights into the interplay between organic and diagenetic fabrics and resultant rock properties.
Mendez, Jose Nicanor (China University of Petroleum, Eastern) | Jin, Qiang (China University of Petroleum, Eastern) | Gonzalez, Maria (Emerson E&P Software) | Zhang, Xudong (China University of Petroleum, Eastern)
This study outlines a probabilistic model based on artificial neural networks applied to the very deep karsted carbonates of the Ordovician Yingshan Formation, which represent significanct reservoirs within a region of the Tahe oilfield, Tarim Basin, China. The complexity of rock type prediction and distribution of paleokarst fillings hosted in cavities, drives the need to apply new techniques for identifying more plays. This investigation focuses on a karsted interval located between the reflections of unconformities T74 and 76. The analysis was conducted using acoustic impedance (P-wave) and amplitude seismic attributes, processed from a 32-bit seismic dataset (Poststack). The methodology also includes conventional wireline logs from 28 wells adjusted to lithological descriptions of cores. Democratic Neural Networks Association (DNNA) is the proposed method for rock type prediction in karsted carbonates that simultaneity utilizes 3-D seismic data and well data. Based on sedimentological descriptions, the karst facies are classified in six types of lithofacies: mixed siliciclastic and carbonate (e.g., calcarenite and conglomerate), limestone, very fine-grained sandstone, mudstone, breccia, and unfilled. According to identified lithofacies, a clustering analysis is performed using the followings logs: Gamma Ray (GR), Deep Resistivity (RD), Neutron (CNL), Density (DEN), Sonic (AC), Potassium (K) and Thorium (TH) from Spectral Gamma Ray. Subsequently, the outputs are simplified for selecting the model most representative of lithofacies. Once adjusted data in commercial package, a training set and stabilization geometry involving seismic attributes constrained by interpreted seismic horizons are processed. The extracted seismic traces along borehole trajectory after processing demonstrate a good match with analyzed data, where the predicted maximum probability and class probability tracks vary with respect to lithofacies. Making time slices on the computed volume are observed to estimate effectively the probability of karst facies away from the wells. The outcome of this workflow is a probabilistic facies volume that provides appropiate description of clastic rocks that cover paleokarst fillings essentially in the run-off subzone. The model indicates that mudstone facies are the most prevailing and better proportions of siltstones or sandstones facies are distributed to southeast of area. This study concludes that in determining clastic lithofacies distribution, employing several neural networks running in parallel that simultaneously learn from the same dataset through different strategies is an effective tool. To date, there has not been any study on rock type prediction using DNNA in karsted carbonates. The results represent a significant contribution to the collection of geosciences on characterizing this type of reservoir.
Karst reservoirs in the Tarim Basin, northwestern China, were formed by subaerial exposure and karstification from the Ordovician formation and represent the main plays. Predicting the storage capacity and quantifying permeability heterogeneities are challenging while important for field development planning. In this paper we present a hierarchical approach to modeling karst and fractures with geoscience and engineering data for selecting locations of new wells and for the reservoir simulation.
Karst and fractures at multiple scales contribute significantly to reservoir volumes in place and well productivity. Fracture-karst units in wells were determined using log-based electrofacies validated against core data, image logs and drilling data to quantify different karst features and fracture patterns hosted in units. A 3-D architecture model of karst system was constructed with extracted karst features at the seismic-scale based on multi-attribute seismic facies analysis. The karst network model was generated with karst-fracture units at wells, inverted seismic impedance volume, and 3-D karst architecture model. Porosity estimates of the karst system were conditioned with log data, mud loss data, seismic impedance volume and karst network model. Karst horizontal and vertical conduits were modeled and their permeabilities were empirically derived. Based on fracture length relative to the seismic resolution, fractures were modeled at two scales. Diffuse fractures at a small scale were modeled stochastically conditioned with image log data and the karst fracture unit model. A discrete fracture network (DFN) model at a large scale was deterministically built by meshing fracture lineaments automatically tracked from the curvature enhanced attribute. The DFN model was embedded into a geocellular grid model in which geometries of the large fractures were maintained explicitly. The calculation of effective horizontal and vertical permeabilities of the fracture system was scale dependent and decoupled. Fracture geometric parameters and permeabilities were calibrated against well test data. Streamline simulation was performed in the static model to calibrate spatial fracture densities. After two-step conditioning, fracture models were updated and then upscaled. Flow properties of karst and fractures from the wellbore to the seismic scales were combined based on their impacts on fluid flow.
Integration of karst network model and history match of water cut and bottom hole pressure using streamline simulation helped the oil/water contact (OWC) assessment and allowed the identification of dynamic compartments. Combing karst networks, dynamic compartments and modeled geological scenarios allowed targeting potential highly productive zones where new well locations could be selected.
The case study demonstrated that the hierarchical approach to karst and fracture modeling and calibration allowed building a realistic reservoir model and better understanding of the reservoir complexity.
Shell's new natural gas discoveries in Egypt are estimated in initial quantities at about 500 Bcf with more reserves possible, said Aidan Murphy, chairman and managing director of Shell Egypt. The discoveries, in a concession area of north Alam El-Shawish in the country's western desert, could yield 10% to 15% of the total production of Badr el-Din Petroleum Company, the 50/50 joint venture of Shell and Egyptian General Petroleum Corporation that is expected to manage the operations. Eni reported that the Laarich East-1 oil well in Tunisia has a delivery capacity of approximately 2,000 B/D. Spudded in June, the well discovered hydrocarbons in Silurian and Ordovician sandstones while reaching a final depth of 13,487 ft. The well has now been connected to production.
Results of the Integrated CCS for Kansas pre-feasibility study indicate that large-scale CO2 capture, transportation and storage in saline aquifers in Kansas is both technically and economically feasible and deserving of further study. Based on the technical work on multiple geologic sites, there appear to be up to four sites within the North Hugoton Storage Complex (NHSC) in Southwest Kansas where >50 million tons CO2 could be injected over a 25- to 30-year period and safely stored in a set of stacked saline aquifers at ideal depths of 5200-6400 ft. The saline aquifers (Mississippian Osage, Ordovician Viola, and Cambrian-Ordovician) are overlain by oil reservoirs that are candidates for CO2 Enhanced Oil recovery (EOR). Of the four possible sites in the NHSC, the Patterson site was chosen as the primary site for a CarbonSAFE Phase II project. Patterson was chosen because the operator of the overlying fields, Berexco, was a long-term research partner of the Kansas Geological Survey (KGS), having participated in several DOE-funded studies with the KGS. Patterson has EOR opportunities in overlying reservoirs and most of the prospective injection site is already unitized.
Capture, compression and transportation of large volumes of CO2 is economic in the region, particularly since the extension and expansion of Federal 45Q tax credits in February 2018 that provide $35/ton for CO2 stored during EOR and $50/ton if stored in a saline reservoir and can be captured for a 12-year period. Without these credits, saline aquifer storage is not economically viable. The most economic scenario involves CO2 aggregated from multiple ethanol plants via small-diameter pipelines that tie into a main trunk line for delivery to market. CO2 EOR likely needs to be part of the system to provide economy of scale and, potentially, additional subsidy for saline aquifer injection through CO2 sales. High capture costs at the two power plants and refinery in this study make them non-economic options without further subsidy that may arise from a large regional pipeline system.
Legal, regulatory, public policy aspects of a project of the scale envisioned will require significant changes at the State level. In particular, legislation that would regulate capture, transportation, injection and storage as a public utility would be required along with allowances for eminent domain to be used for pipeline right-of-way and pooling of pore space. Streamlining the U.S. EPA UIC Class VI well permit process and/or establishing State primacy would further support development of commercial-scale CCS. Effective public outreach is critical for support of State regulatory changes, and for public acceptance, particularly in light of possibility for induced seismicity due to injection in certain areas and mixed public opinions about pipeline construction.