Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
Abouzaid, Ahmed (Baker Hughes) | Thern, Holger (Baker Hughes) | Said, Mohamed (Baker Hughes) | ElSaqqa, Mohammad (Khalda Petroleum Company) | Elbastawesy, Mohamed (Khalda Petroleum Company) | Ghozlan, Sherin (Khalda Petroleum Company)
The evaluation of logging data in shaly sand reservoirs can be a challenging task, particularly in the presence of accessory minerals such as glauconite. Accessory minerals affect the measurements of conventional logging tools, thus, introducing large uncertainties for estimated petrophysical properties and reservoir characterization. The application of traditional Gamma Ray and Density-Neutron crossover methods can become unreliable even for the simple objective of differentiating reservoir from non-reservoir zones.
This was the situation for many years in the glauconite-rich Upper Bahariya formation, Western Desert, Egypt. Formation evaluation was challenging and the results often questionable. Adding Nuclear Magnetic Resonance (NMR) Logging While Drilling (LWD) data in three wells changed the situation radically. The NMR data unambiguously indicate pay zones and simplify the interpretation for accurate porosity and fluid saturation dramatically. Key to success is NMR total porosity being unaffected by the presence of accessory minerals. NMR moveable fluid directly points to the pay zones in the reservoir, while clay-bound and capillary-bound water volumes reflect variations in rock quality and lithology.
Although the NMR total porosity is lithology independent, the presence of glauconite affects the NMR T2 distribution by shifting the water T2 response to shorter T2 times. This requires an adjustment of the T2 cutoff position for separating bound water from movable hydrocarbons. A varying T2 cutoff was computed by comparing NMR bound water to resistivity-based water saturation. The calibrated T2 cutoff exhibits an increase with depth indicating a decreasing amount of glauconite with depth throughout the Upper Bahariya formation. Based on these volumetrics, an improved NMR permeability log was calculated, now accurately delineating variations in rock quality throughout the different pay zones. In addition, viscosity was estimated from the oil NMR signal. The estimated values match the expected values very well and illustrate the potential of NMR to indicate viscosity variations.
Many of these results are available today already in real-time by transmitting NMR T2 distributions to surface while drilling. Besides the application for formation evaluation, the data can be used to initiate optimized side-tracking and completion decisions directly after finishing the drilling operations.
Egypt's Western Desert contains a series of basins underlain by organic-rich shales that provide the source for conventional hydrocarbon. The primary objectives for exploring the gas-rich shale plays and unconventional reservoirs in the Western Desert were to evaluate the Middle Jurassic Khatatba source rock reservoir qualities, demonstrate the availability of reserves, and identify optimal technology to maximize productivity of unconventional low-permeability reservoirs, stimulation, and testing strategies.
In 2014, a vertical exploratory data well was drilled and completed in the appraisal program before the completion of horizontals in this formation. Logs, core testing, and analysis service data were performed on or collected from this well. A stimulation model was built, which integrated petrophysical and geomechanical data. This model was used to aid the completion and stimulation design, including fracturing fluids and proppant selections. One-stage hydraulic fracturing was implemented, and the well was then flowed back and produced.
The Khatatba Shale was systematically studied in this work. Various methods were used to understand this source rock. A geological study identified the lithostratigraphic section of the Khatatba Shale formations by collecting core samples. Core tests measured total organic carbon (TOC), brittleness, and sensitivity to fluid. These understandings helped reduce uncertainty during hydraulic fracturing operations. A successful hydraulic fracturing treatment was performed for this formation, which showed that low-viscosity fracture fluid can be used as the treatment fluid to carry proppant into the formation. During fracturing, near-wellbore (NWB) multiple fractures can be an issue. From an operational point of view, there might be options better than performing high-rate fracturing treatments. The lessons learned from this work and presented in this paper helped define completion and stimulation technologies for horizontal wells.
This paper presents hydraulic fracturing treatment of the first shale gas well in Egypt for the Khatatba formation. Lessons learned about geochemical, rock mechanical, and petrophysical properties of this shale formation and their effects on hydraulic fracturing and production formed the basis for subsequent development of various shale plays in Egypt and worldwide.
Bacenetti, R. (Eni SpA Upstream and Technical Services) | Buia, M. (Eni SpA Upstream and Technical Services) | Doniselli, F. (Eni SpA Upstream and Technical Services) | Serafini, G. (Eni SpA Upstream and Technical Services)
Even in a very mature field, if poor seismic imaging does not support well results, it can be very difficult to get a full understanding of the subsurface and a comprehensive picture of the targets. In the case history presented hereinafter, we show that by the use of an integrated approach, based on the customization of the reprocessing sequence and the depth imaging workflow, it was possible to improve the structural imaging of the deeper formations and to mitigate the geophysical risk for exploration and development activity. Through the application of pre-stack depth migration (PSDM), fed by a detailed anisotropic velocity model and a properly preconditioned input dataset, the stratigraphic picture within the Mesozoic sequences became more interpretable, where the vintage seismic volume was not able to explain the results of some recent wells: the application of cutting edge imaging technologies allowed an alternative mapping of the seismic facies penetrated by the wells and to perform accordingly a stratigraphic interpretation aimed at de-risking the subsequent exploration activity.
A review of the available data of the Obaiyed field was carried out by Bapetco as part of the 2002 FDP update and the last review of Oct.2004. The Obaiyed field is a complex field, characterized by large uncertainties in permeability distribution and accordingly connected GIIP. The objective was to produce an integrated diagenetic and sedimentological model that can be utilized in 3D reservoir modelling. The study has resulted in a comprehensive 3D model of an estuarine, incised valley depositional system. Geological, Petrographical, sedimentological and Reservoir Engineering data have been integrated to create model realizations reflecting extreme scenarios of the permeability distribution within the field in an attempt to define their connectivity. The majority of the sandstone were deposited as bars within the estuary. The occasional higher permeability layers correspond to petrographic differences in the sandstones that relate to depositional sub-environment. Rock samples have been taken from the Paleozoic/Mesozoic in order to assess the diagenetic history, its impact on reservoir quality, and potential petrographic criteria by using the following analyses:
• Rock composition, Thin section petrography, SEM-analysis, XRD;
• Clay Mineralogy and Illite crystalinity;
• Age dating and Age of diagenesis: K/Ar-dating of Illite/Kaolinite concentrates.
The permeability and saturation distribution are a function of the diagenetic history of the field, causing the Paleozoic sandstones, which underlie the Mesozoic Lower Safa, to have a markedly lower permeability and generally lower saturation.
The Obaiyed gas/condensate field presents the challenging combination of a complex subsurface and a short timeframe to fully develop the field and to deliver committed daily quantities. The field was discovered in 1992, subsequently 4 appraisal wells were drilled between 1994 and 1996. After issuing the initial FDP in 1996 a development campaign was started in 1997, first gas was produced in 1999.
After drilling 28 wells in the area subsurface uncertainties have been reduced significantly, the current updated FDP focuses on the development of reserves locked in the tight parts of the field as a means to maximize profitability of the field. Currently over 50% of the in-place gas is locked in tight gas sandstones in the Obaiyed field.
In order to rule out other causes of poor productivity, the formation damage is the mechanism responsible for poor productivity. As this can only be done by ensuring no damage during drilling
Over the next two years, drilling activity in Bapetco will be increased, mainly because of the upcoming drilling campaign to develop the NEAG field In Abu El Gharadig Area and Obaiyed Area. Initial development plan will comprise drilling of 8-10 development wells in both Areas.