This study examines which is the margin of usability for Artificial Intelligence (AI) algorithms related to the rock properties distribution in static modeling. This novel method shows a forward modeling approach using neural networks and genetic algorithms to optimize correlation patterns among seismic traces of stack volumes and well rock properties. Once a set of nonlinear functions is optimized in the well locations, to correlate seismic traces and rock properties, spatial response is estimated using the seismic volume. This seismic characterization process is directly dependent on the error minimization during the structural seismic interpretation process, as well as, honoring the structural complexity while modeling. Previous points are key elements to obtain an adequate correlation between well data and seismic traces. The joint mechanism of neural networks and genetic algorithms globally optimize the nonlinear functions and its parameters to minimize the cost function. Estimated objective function correlates well rock properties with seismic stack data. This mechanism is applied to real data, within a high structural complexity and several wells. As an output, calibrated petrophysical time volumes in the interval of interest are obtained. Properties are used initially to generate a geological facies model. Subsequently, facies and seismic properties are used for the three-dimensional distribution of petrophysical properties such as: rock type, porosity, clay volume and permeability. Therefore, artificial intelligence algorithms can be widely exploited for uncertainty reduction within the rock property spatial estimation.
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.
This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico. The lower tertiary formation found in the pre-salt layers of the Gulf of Mexico has become a proving ground for extending what is possible when completing multistage fracturing in ultradeepwater wells.
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. Twenty-five offshore blocks will be offered, including 17 in the South China Sea, three in the East China Sea, and five in the Yellow and Bohai seas.
Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
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.
Africa (Sub-Sahara) Vaalco Energy started oil production from the Etame 12-H development well offshore Gabon. The well was drilled to a measured depth of approximately 3450 m and was targeting the recently discovered lower lobe of the Gamba reservoir. It was brought on line at a rate of 2,000 BOPD with no indication of hydrogen sulfide. Vaalco (28.07%) is the operator with partners Addax Petroleum (31.63%), Sasol (27.75%), Asia Pacific KrisEnergy started drilling the Rossukon-2 exploration well on Block G6/48 in the Gulf of Thailand, using the Key Gibraltar jackup rig. The well will reach a total depth at 5,462 ft and will test Early Miocene stacked fluvial sandstones on a broad structural high. The well will also appraise the Rossukon-1 reservoir, which produced 850 BOPD during tests.
Eni started production from the Perla giant gas field located in the Gulf of Venezuela, 50 km offshore. Consisting of Mio-Oligocene carbonates with excellent characteristics, the reservoir is approximately 3000 m below sea level and lies at a water depth of 60 m. The best wells are estimated to produce more than 150 MMscf/D of gas each. The development plan includes 21 producing wells and four light offshore platforms linked by a 30-in. The field is operated by Cardón IV, a company jointly owned by Eni (50%) and Repsol (50%).
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Permeability values of rocks range over many factors of 10; therefore, permeability is plotted on a logarithmic scale. Values commonly encountered in petroleum reservoirs range from a fraction of a millidarcy to several darcies. This page discusses factors affecting permeability associated with different rock types. The log10(k)-Φ plot of Fig.1 shows four data sets from sands and sandstones, illustrating the reduction in permeability and porosity that occurs as pore dimensions are reduced with compaction and alteration of minerals (diagenesis). Porosity is reduced from a maximum of 52% in newly deposited sandstones to as low as 1% in consolidated sandstones.