When key geological scenario uncertainties, captured in multiple conceptual models, are combined with continuous parameters, the evaluation of a representative sample set quickly becomes unmanageable, laborious and too time consuming to execute. A workflow is presented that enables users to easily model conceptual as well as parametric uncertainties of the reservoir without the necessity of any complex scripting. The chain of models for all concepts is presented in one view, to provide overview of the key differences between concepts used. An ensemble of geologically sound samples can be created taking into account parameter dependencies and probabilities of concepts. The chain of models per concept can easily be (re)executed.
A case study is presented that consists of multiple concepts based on different hierarchical stratigraphic models in combination with different fault models, each of which with its own fluid- (defined contacts per compartment), grid- (sub-layering and areal resolution) and rock property models. Volumetric calculations are run on an ensemble to get static model observables like GRV, Pore Volume, Oil-In-Place, etc., reported by multiple sub-regions of the model in combination with a lease boundary. (When coupled with dynamic simulation, observables like ultimate recovery, break-through timing, etc. could also be obtained). As thousands of realizations were run concurrently, run time was reduced from weeks to hours. Results reveal the distribution and dependency of observables like GRV on top-structure-depth uncertainty and contact-level uncertainty. For in-place volumes the full suite of concepts and other parametric uncertainties including the stochastic uncertainties (i.e. seed) is analyzed. This also enables the identification of the key uncertainties that impact equity the most, which can be of great commercial value during equity negotiations. This workflow demonstrates how, with the power of Cloud computing, rigorous evaluation of multiple concepts combined with many parametric uncertainties has been achieved within practical turn-around times. As such it overcomes the prohibitive hurdles of the past that often have led to simplifications necessary to save time and effort. The result is better decision quality in resource development decisions.
Africa (Sub-Sahara) Eni discovered up to 250 million bbl of light oil in the Ndungu exploration prospect in Block 15/06 offshore Angola. A well in 1076 m of water reached TD of 4050 m and proved a single oil column of approximately 65 m with 45 m of net pay of 35 API oil. Well results indicate production capacity in excess of 10,000 B/D. Eni operates Block 15/06 with 36.8421% Joint venture partners are Sonangol P&P (36.8421%) and SSI Fifteen (26.3158%). Eni discovered gas and condensate on the Akoma prospect in CTP-Block 4 offshore Ghana. The Akoma-1X exploration well was drilled in 350 m of water approximately 50 km offshore and 12 km northwest of the FPSO John Agyekum Kufuor.
The green light for Santos Energy’s drilling program in the McArthur Basin comes after a moratorium on hydraulic fracturing in the Northern Territory was lifted in 2018. After drilling the Dorado-2 appraisal well, operator Santos Energy now expects a big increase in gas resources from predrill estimates, adding to one of the largest oil resources ever found on Australia’s North West Shelf. The complete paper proposes an azimuthal plane-wave-destruction (AzPWD) seismic-diffraction-imaging work flow to efficiently emphasize small-scale features associated with subsurface discontinuities such as faults, channel edges, and fracture swarms. This paper contrasts the detailed perforating and flowback plan with the results of the operation where a number of planned, and some unplanned, contingencies were faced. A hybrid downhole microseismic and microdeformation array was deployed to monitor fracture stimulation of a vertical coal-seam-gas (CSG) exploration well in the Gloucester Basin in New South Wales, Australia, to provide more-accurate insight into overall fracture height.
Findings from Kayrros suggest the average Permian well is both less productive and more expensive than reflected in public data. The projects are designed to reduce technical risks in enhanced oil recovery and expand application of EOR methods in conventional and unconventional reservoirs. Twelve organizations—universities and private technology companies—will conduct research and development on emerging shale plays and technologies covering everything from digital pressure-sensing to smart microchip proppant. The evolution of hydraulic fracturing is a long and circuitous one that deserves examination. Engineering and completions leaders from Liberty Oilfield Services did just that, authoring a paper that encapsulates the high points in the development of the groundbreaking completions practice.
Researchers from the Federal Reserve Bank of Dallas quantified the economic impact of the US shale revolution for the first half of this decade. Production from the Hibernia platform was shut down again on 17 August after its second oil spill in a month, while Husky Energy began to ramp up output from the White Rose field following the largest-ever spill off Canada’s easternmost province. Anchored by the Khaleesi-Mormont and Samurai fields, the King’s Quay FPS will receive and process up to 80,000 B/D of crude oil. Despite reports to the contrary, Permian well productivity remains healthy, with average new production per well in the basin matching all-time highs, Rystad says. Researchers mapped 251 faults in the North Texas home of the Barnett Shale, the birthplace of the shale revolution, finding that wastewater injection there “significantly increases the likelihood for faults to slip.”
Production from the Hibernia platform was shut down again on 17 August after its second oil spill in a month, while Husky Energy began to ramp up output from the White Rose field following the largest-ever spill off Canada’s easternmost province. Anchored by the Khaleesi-Mormont and Samurai fields, the King’s Quay FPS will receive and process up to 80,000 B/D of crude oil. Marathon Oil says its shale fields are producing more oil and gas with less hands-on work from company personnel thanks to a growing arsenal of digital technologies and workflows. Expected to start up in mid-2022, Liza Phase 2 will produce up to 220,000 B/D of oil. Hydrocarbon processing and treating systems often require large and elaborate surface facilities.
Africa (Sub-Sahara) Sahara Group discovered hydrocarbons in three wells drilled in Block OPL 274, located onshore in Nigeria's Edo State. Olugei-1 was drilled to a measured depth of 4537 m and encountered five hydrocarbon zones, with 33 m of net pay. Oki-Oziengbe South 4 was drilled to a measured depth of 3816 m and encountered 64.3 m of net pay in 13 hydrocarbon-bearing zones. Oki-Oziengbe South 5 was drilled to a measured depth of 3923 m and encountered 91 m of net pay in 19 reservoirs. Sahara Group (100%) is the operator. Asia Pacific Sino Gas & Energy Holdings (SGE) flowed gas (coalbed methane) from its first horizontal well in the Linxing production sharing contract (PSC) in China's Shanxi province.
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.
Others, such as subsea power-distribution systems, are still in the product development stage. Many of the emerging products are well-proven surface components modified for subsea application. As in any integrated system, a shortcoming in any one of the links will impair the performance of the whole. Successful implementation requires all the skill sets to work seamlessly and with greater than ever attention to QA/QC in components manufacturing, installation, and system integration. A clear understanding of the process and all its parameters is the first step toward a successful design. As in surface facilities, knowledge of the produced fluid properties, rheology, and flow characteristics are critical. Luckily, whether the process is carried out on the surface or a thousand meters subsea, the process is the same. However, effects of the environmental conditions may be more dramatic and detrimental. Fluids with high foaming tendency will complicate the design and may require mechanical or chemical solutions. For subsea applications, a passive mechanical foam-breaking device (such as a low-shear inlet momentum breaker) is preferred over the more costly to install and operate chemical injection systems. For three-phase separation, the more complex oil/water emulsion/dispersion chemistry will come into play, along with the viscosities of the oil and water and changes in water cut with time.
When combined with relatively mature subsea production technologies (see subsea chapter on well systems, manifold, pipeline, power and control umbilical, and so on), it can reduce development cost, enhance reservoir productivity, and improve subsea system reliability and operability. Over the period from 1970 to 2000, millions of dollars have been spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry has not rushed to deploy the technology on a commercial basis. However, as the industry moves into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, making small fields economically viable and large fields even more profitable. Subsea processing refers to the separation of produced ...