The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
- Data Science & Engineering Analytics
The SPE has split the former "Management & Information" technical discipline into two new technical discplines:
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Supermajor Shell has struck light oil with its Graff-1 exploration well offshore Namibia, according to the country's national oil company, a partner in the probe. The National Petroleum Corporation of Namibia (Namcor) confirmed the discovery. Partners in the Orange Basin well included Shell Namibia Upstream and QatarEnergy. The probe was located about 270 km away from Oranjemund, and was drilled to a total depth of 5376 m in water depths of 2000 m. The drilling operations on Graff-1 utilizing the Valaris DS-10 drillship began in early December 2021 and were completed in early February.
Abstract Here we present a regional study of the offshore/onshore Namibia using gravity and magnetic data aiming to bring a new light on the structural configuration of the major Namibian basins. This has been achieved by integrating all the available wells, vintage seismic images and public domain information. We produced lineament maps at different scales with the aid of gravity and magnetic data enhancements in the attempt of differentiating between regional and local features. In general, volcanic centres and dikes are well recognized as well as two main structural trends: one oriented NW-SE being more prevalent in the offshore, near-onshore and in the Nama basin; the second oriented SW-NE more pronounced in the Owango basin and the Damara Belt. Satellite derived gravity is also used to delineate the transition zone between continental and oceanic crust (COB). Results are compared with information from seismic and well data to locate the COB on the achieved structural map. Magnetics was also used to estimate the depth to basement all over the studied area. Major basins and structural elements such as the SW-NE uplift in the Owango basin, a series of sub-basins with a significant depth in the Damara fold belt and the Nama basin, offshore basins and sub-basins plus structural highs were identified and mapped. 2.5D Gravity and Magnetic modeling over key areas was used to validate the structural interpretation. These models integrate interpreted seismic profiles, densities from stacking velocities, wells, refraction seismic interpretations and public domain data. We found thick piles of sediments could be present below the SDRs in the Walvis and Luderitz basins. While we found the SDRs probably be at direct contact with the continental crust in the Orange basin, generating an important magnetic anomaly, therefore no important sediment accumulation can be inferred below the SDRs in this basin. We also found the Owambo basin in the onshore dipping northward with important dike intrusions in the middle. The Nama basin is characterised by a high magnetised crust with a higher magnetised intrusion generating the large magnetic anomaly at its western end. Introduction Recently, exploration in new venture areas is relying more and more on integrated studies with all the available public domain information, low cost geological and geophysical data. More often the need of analyzing large areas of a regional extent to rapidly evaluate the petroleum potentials is requiring fast tools and large datasets. Gravity and magnetic data have the advantage of continuously cover large areas at a fraction of the costs of conventional seismic or geological field work. This type of data is more than sufficient for determining structural configuration, basement depth and geometry, COB, evaluate sediment thickness and lithologies at regional and basin scale. Here a regional interpretation of the onshore/offshore Namibia with focus on specific basins was undertaken, mainly using low cost GravMag data and public domain information.
Abstract The continual increase in exploration drilling in southern Africa has translated into a number of remote deepwater campaigns, the most recent ones being in Namibia. One particular three-well campaign was exceptionally challenging as there was no near offset-well data available. The challenges were especially acute in the riserless tophole section. The well designs called for top of cement (TOC) at seabed for the surface casing. This was of the utmost importance for adequate structural and axial support for the blowout preventers (BOP) and subsequent casing strings. The very low fracture gradient near the seabed was the main challenge as the formations would not support the hydrostatic pressure of the cement column. On the first well, total losses were encountered prior to and during the entire cementing operation. As a result, no cement returns were observed at seabed, contrary to what was expected from hydraulic simulations and volume calculations and required to meet the job objective. To achieve objectives required for the success of the subsequent two wells, all aspects of drilling and cementing operations were reviewed based on the findings of the first well. Mud weight and casing setting depth were critically challenged, with other parameters adjusted. Cement formulation and density were optimized to reduce hydrostatic and hydrodynamic pressures and to increase the chance of success. The cement slurry was changed to a bimodal lightweight system with better fluid- and set-cement properties. Lost circulation fiber technology was also incorporated in the spacer preflush and in the cement slurry to mitigate any losses during placement. Alignment of service company and operator objectives and optimization of drilling and cementing parameters were critical for the successful cementation of these challenging tophole sections. Continuous improvements resulted in the second well being effectively cemented to seabed, even though intermittent losses were observed. After further optimization, the third well was cemented to seabed with full returns. Reaching the target TOC eliminated the need for a top-up job, saving valuable rig-time.
ABSTRACT The sedimentary basins of the South Atlantic have developed into one of the most active regions for petroleum exploration in the whole world. The increase of interest in the oil industry has resulted from the numerous recent giant to supergiant oil and gas discoveries along both the eastern and western continental margins of the South Atlantic in deep and ultradeep waters. The use of the petroleum system concept in the South Atlantic marginal basins provides an effective means of classifying and characterizing the diversity of the oil and gas systems, as well as, a means to aid in the selection of appropriate exploration analogs. The South Atlantic marginal basins also provide some of the best examples of how petroleum systems evolved through time with respect to both their levels of certainty and their areal and stratigraphic limits. An examination of the Orange and Santos basins, in Namibia and Brazil, respectively, provides examples of almost perfect analogs in terms of petroleum system. For example, lacustrine and marine source rocks, similar oil type, almost identical reservoir deposition environments, traps associated with basement highs and vertical migration pathways dominate in each of the basins, with normal faults networks providing the effective carrier. However, there are clear differences when Aptian salt layers are present in the Santos basin and absent in the Namibian basins. Also, differences are observed when thermal evolution is considered. Although no Aptian salt section is present in Namibian basins, and thermal maturity appears to be much higher in the Namibian coast, both basins share almost identical elements and processes of the petroleum system concept. In summary, the aim of this paper is to show how the petroleum system modeling, supported by geochemistry, allows a correlation between counterpart basins across the South Atlantic realm. DISCUSSION The evolution of the South Atlantic sedimentary basins provided the general conditions for the establishment of various petroleum systems. The formation of source rocks, reservoirs and traps are directly related and connected to the phases of the evolution of the passive continental margins (Figure 1): pre-rift, syn-rift, transitional and thermal sag (drift) sequences (Mello, 1988, Mello et al, 1991 and Katz and Mello, 2000).
Abstract: The unlicensed northern part of the Orange Basin covers almost 21000 km2 and falls between the median line dividing Namibian and South African territory, and the 30 deg south latitude line. Sediments range in age from the late Jurassic to Hauterivian synrift graben fill, to drift sediments dating from the early Cretaceous to the present. The area is covered by over 8000 km of 2D seismic data, ranging in vintage from 1975 to 1999. Only 3 wells have been drilled in the area to date. One targeted possible lacustrine sandstones in the synrift, but intersected coarse, proximal sediments. A second, towards the south, targeted the western part of a structural play on either side of an extensional fault, but encountered only poor gas shows in mostly water-wet sandstones. The third intersected gas charged fluvial sandstones in the early to mid-Cretaceous. Numerous play types are present in the area. Rift plays are represented by possible lacustrine sandstones, trapping oil from organic rich claystones as encountered in the A-J graben to the south. The other major play is represented by synrift sediments pinching out against basement to the west of the hinge line. Drift plays include the early Cretaceous Aeolian sandstone play, the Albian incised valley play, structural plays in younger shelf sediments and deeper water plays comprising roll-over anticlines in growth fault zones and turbiditic fans. INTRODUCTION The Orange Basin, off the southwestern coast of Africa, is classified as a passive volcanic margin basin. Clastic sediment, sourced from the continent to the east, has been deposited in the basin by the Orange and Oliphants River systems and their ancestral equivalents. The sediment pile reaches over 7km thick in places. This poster discusses the northern most part of the Orange Basin within South African territory. The area shown in Figure 1 covers almost 21 000 km and falls between the median line dividing Namibia and South African, and the 30 deg south latitude line. Sediments range in age from synrift graben fill, tentatively dated from late Jurassic to Hauterivian, to drift sediments dating from early Cretaceous to the present. The area is covered by over 8 000 km of 2D seismic data, ranging in vintage from 1975 to 1999, as shown in Figure 1. Water depths are less than 200m over most of the area, with only the far western section lying in water up to 600 m deep. Exploration to date Only 3 wells have been drilled in the area. Well positions are shown in the figure above.Borehole A-O1 in the north, targeted prognosed lacustrine sandstones in the synrift graben sediments. Three distinct seismic packages occur within the graben. The well was drilled to a depth of 4 605 mbKB and intersected proximal fluvial sandstones, volcaniclastics, shales and silts of mostly fluvial origin, and dolerites. Thin, unoxidised lacustrine shales occur as interbeds only, indicating that the well intersected a relatively proximal facies in the graben.
Abstract General Elastic Inversion is a specific inversion process that is designed to combine both ?Vp (pseudo compressional interval velocity) and ?Vs (pseudo shear interval velocity) volumes in a straightforward and meaningful way to emphasize pore fluid type. The calibrated results are simple and values nonarbitrary. Good data seismic quality and high fold are preferred, and a good quality dipole sonic curve from an area well can be used for calibration but is not required. In essence the process has 2 steps and proper execution of both is required to get good results. The first step is generation of the ?Vs and ?Vp volumes and the second step is the combination and re-projection of the ?Vp and ?Vs volumes. A critical step is generation of the ?Vs volume which must be done in the pre-stack domain. The objective is to estimate converted-wave shear amplitude at different offset angles. On problem is that some methods result in only a linear transform of the P-wave amplitudes which will not produce a separation of gas and water cases in the P and S crossplot domain. We present a rigorous 'full Zoeppritz' solution involving ray-tracing that provides meaningful, nonlinear calculation of what the converted shear-wave amplitudes by offset would have been had they been recorded. In essence, the S wave AVO is modeled. Secondly the P and S reflectivity volumes are inverted, scaled to pseudo-velocity, and then calibrated to well control. The resulting ?Vp and ?Vs volumes are combined and reprojected to produce a 'fluid' volume and a 'porosity' volume. The process is simple enough in concept that we propose it as a general solution to Elastic Inversion. Like the Fluid Factor (Smith and Gidlow, 1987) and Rp-Rs (Castagna and Smith, 1994) methods it combines both volumes by summation of Vp and Vs. Examples are from the giant Ibhubesi gas fields offshore the Republic of South Africa in the Orange River Basin,Fig. 1, Location of Ibhubesi Gas Field, offshore the West Coast of the Republic of South Africa. (Available in full paper) however this method has been used in other area, both land and marine, with excellent predictive results. Introduction to the Inverse Problem What is Inversion? The name implies it is an inverse method, that is-one that has multiple possible solutions. This is the opposite of the forward method, where the conditions and experiment are known and the results are measured and repeatable. The results are always the same and the experiment may be repeated. With the inverse method (and more specifically the 'Inversion' used here,), the results and experiment are known and we are asked to solve for the original conditions. While it is true that there are multiple solutions, that is different geologic conditions may give rise to the same measurement, usually the practical possibilities may be narrowed. Most geological problems are in fact inverse procedures and understanding this relationship is both simple and profound, as non-uniqueness imposed by the inverse method is the fundamental reason for risk and uncertainty in Geology and Geophysics.