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Since the industrial revolution, the oil and gas industry has played an important role in the economic transformation of the world, fueling the need for heat, light and mobility of the world’s population. Today, the oil and gas industry has the opportunity to redefine its boundaries through digitalisation, after a period of falling crude prices disrupted exploration and production activities, and ineffective mature field development challenges that are currently facing most oil and gas companies in Indonesia. The recent downturn in the oil and gas industry has led to massive layoffs. Digital industrial revolution is slowly changing how upstream businesses operate. Increasing public awareness of climate change has fuelled the urgency to shift to cleaner alternative energy.
Africa (Sub-Sahara) Oil was discovered at the Ekales-1 wildcat well located in northern Kenya. The well has a potential net oil pay in the Auwerwer and Upper Lokone sandstone reservoirs of between 197 ft and 322 ft. Tullow (50%) is the operator in partnership with Africa Oil (50%). Drillstem tests on the Pweza-3 well offshore Tanzania flowed at a maximum rate of 67 MMscf/D of gas. The tests confirmed the excellent properties of the Tertiary-section reservoir. BG Group (60%) is the operator in partnership with Ophir Energy (40%). Asia Pacific China National Offshore Oil Corporation issued a tender to invite foreign firms to bid for oil and gas blocks in the east and south China Sea.
Africa (Sub-Sahara) The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%), A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%).
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery.
Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m.
Apranda, Yoseph Robby (Institut Teknologi Bandung) | Riadi, Ridha Santika (Pertamina Hulu Sanga-Sanga) | Nugraha, Teguh (Pertamina Hulu Sanga-Sanga) | Permana, Robhy Cahya (Pertamina Hulu Sanga-Sanga) | Putranto, Asnanto Multa (Pertamina Hulu Sanga-Sanga) | Noerad, Dardji (Institut Teknologi Bandung)
The Sanga-Sanga working area consists of brown fields that have been produced for nearly 50 years. The production is declining rapidly from anticlinal trap fields. Finding new resources is a must in order to extend the production life. Therefore, the exploration requires getting deeper targeting reservoirs associated with hard overpressure zones.
The methodology used to identify and recognize the potency of hard overpressure zone is the integration of geology, geophysics, and geochemistry data. Normal compaction trend and pore pressure analyses were performed to determine top of overpressure zones. The geochemical data from biomarker provide calculated vitrinite reflectance (Rc) to complement vitrinite reflectance (Ro) when evaluating relationship between hydrocarbon origin and overpressure generation. Finally, the seismic integrates all the data in structural reconstruction framework.
Pore pressure analysis showed 9 wells have overpressure zones. The overpressure occurrence can be grouped based on anticlinal lineaments. The Badak-Nilam lineament is characterized by a sharp change in overpressure to hard overpressure zone, distal facies, relatively normal deposition and showing higher pressure gradient. The Semberah and Lampake-Mutiara lineament are characterized by long transition zone, proximal facies, strongly uplifted and folded, and showing lower pressure gradient. Ro and Rc data showed that there are two periods of hydrocarbon charging into the reservoir, prior to and after the hard overpressure zone occurred. Vertical effective stress, dynamic mechanism, and the timing hydrocarbon generation-migration and overpressure generation hole significant role to accumulation.
The evaluation of hard overpressure zone play requires the integration of geology, geophysics and geochemistry to get the understanding of the timing sequence between hydrocarbon generation-migration and overpressure generation. Calculated vitrinite reflectance data from biomarker gave an advantage to this timing relationship that could lead to the exploration of the hidden resources in the hard overpressure zone becomes more feasible.
The brain of a waterflood project is a geological framework that defines reservoir continuity relative to its transmit fluids as well as restrict fluid movement. The lack of geological knowledge results in the misleading interpretation and understanding of the reservoir behavior. This paper presents an integrated geological aspect, concept and approach to design an effective well pattern and well spacing in waterflooding. This method is proven to improve sweep efficiency and lead us to make an EOR planning in our field. T Field is one of the mature fields where a successful waterflood project has been implemented in Indonesia
Detailed core description with sedimentary structure analysis, paleocurrent analysis in FMI data and various property maps were conducted to identify the relationship between injection and production well. It also gives the information about movement of injected water. The sediment transport suggests some directional anisotropy in permeability. The distribution of geological heterogeneities and their influence on fluid flow characteristics were determined by generating maps and cross sections based on integration of log, core & petrographic data and qualitative information from production data. Parameters mapped included the distribution of porosity, log derived geometric mean permeability, clay content, and Dykstra-Parsons coefficients of permeability variations.
The results of this study showed a good correlation of facies distribution and sedimentation direction with flow of water movement behavior. The direction indicated relatively west to east sediment transport being perpendicular to the structure. It was also matched with tracer survey analysis and simulation model. In our success story, we applied the staggered line of full scale waterflood pattern to maximize the areal sweep efficiency and improve 5-7% recovery factor of total OOIP. This information also strongly supports the building of reliable static and dynamic model.
We proved that an integrated geological approach, including a good understanding of facies and sedimentation characteristics of reservoir will lead us to build successful waterflood and EOR project in the future.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Oil was discovered at the Ekales-1 wildcat well located in northern Kenya. The well has a potential net oil pay in the Auwerwer and Upper Lokone sandstone reservoirs of between 197 ft and 322 ft. Tullow (50%) is the operator in partnership with Africa Oil (50%). Drillstem tests on the Pweza-3 well offshore Tanzania flowed at a maximum rate of 67 MMscf/D of gas. The tests confirmed the excellent properties of the Tertiary-section reservoir.
Numerous carbonate reservoir discoveries were made in Indonesia (
The process involves multiple cycles—from formation evaluation (e.g., geomechanics analysis, design of an effective fracturing method, and production forecasting) through the economic impact to the operator. During the early phase of this integrated study, the uncertainties of all static and dynamic parameters (i.e., geological complexity, rock physics, and stress profile) were considered for fracturing design. Production performances from multiple fracturing stimulation scenarios were then modeled and compared to select the plan that optimizes production for the Berai Formation.
Results demonstrated an effective multidiscipline approach toward a comprehensive strategy to meet the ultimate objective in optimizing production. This project leveraged formation evaluation and fracturing design to deliver integrated solutions from exploration to accurate production forecast. The well stimulations were performed by carefully selecting fluid characteristics based on geological-petrophysical properties, pressure, and stress profiles within the area. Results yielded excellent production gains—for the best case, up to 50% with an average of 40% in comparison with initial production by using an acid that provides optimum fracture geometry and permeability.
This opportunity demonstrated the importance of understanding formation behavior and the parameters that aid the selection of an appropriate fracturing design for a low porosity/permeability carbonate reservoir.