Deepwater reservoirs often consist of highly laminated sand-shale sequences, where the formation layers are too thin to be resolved by conventional logging tools. To better estimate net sand and hydrocarbon volume in place, one may need to leverage the high resolutions offered by borehole image logs. Traditionally, explicit sand counting in thin beds has been done by applying a user-specified cutoff on a 1D resistivity curve extracted from electrical borehole images. These workflows require multiple preprocessing steps and log calibration, and the results are often highly sensitive to the cutoff selection, especially in high-salinity environments.
This paper presents a new method that estimates sand fractions directly from electrical borehole images without extracting an image resistivity curve or applying any preselected cutoffs. The processing is based on an artificial neural network, which takes the 2D borehole image array as input, and predicts sand fractions with the measurements from all button electrodes. A cumulative sand count can be computed after processing the borehole image logs along an entire well by summing up the estimated net sands. The neural network is trained and tested on a large dataset from wells in a deepwater reservoir with various degrees of laminations, and validated with sand fractions identified from core photos. Upon testing, a good match has been observed between the prediction and the target output. The results were also compared against another sand-counting method based on texture analysis, and showed advantages of yielding unbiased estimations and a lower margin of error.
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.
Rizzato, Paolo (Eni S.p.A.) | Castano, Daniele (Eni S.p.A.) | Moghadasi, Leili (Eni S.p.A.) | Renna, Dario (Eni S.p.A.) | Pisicchio, Patrizia (Eni S.p.A.) | Bartosek, Martin (Eni S.p.A.) | Suhardiman, Yohan (Eni Australia Ltd.) | Maxwell, Andrew (Eni Australia Ltd.)
This paper describes the results of an integrated reservoir study aimed at producing hydrocarbons through a sustainable development from a green High Temperature (HT) giant CO2-rich gas field in the Australian offshore. The development concept addressed the complex challenge of exploiting resources while minimizing the carbon impact.
In order to characterize the reservoir in the most detailed way and to describe the fluids behaviour, a 1.8 million active cells compositional model has been built. An analytical aquifer has been coupled in order to represent the boundary conditions of the area.
The faults system, interpreted on seismic data by geophysicists, has been included in the simulation model. The selected development plan includes the re-injection of the produced CO2 into the aquifer of the reservoir itself. The supercritical CO2-brine relative permeability curves at reservoir conditions have been provided by Eni laboratories, where the experiments were performed.
Therefore, a detailed model has been built with the purpose of: Defining producing well and CO2 injector well locations, numbers and phasing to evaluate expected CO2 injectivity and CO2 breakthrough issues; Optimizing the development concept through a risk analysis approach; Estimating the CO2-rich gas injectivity and storage capacity in the saline aquifer of the reservoir; Predicting the behavior of the CO2-rich gas after re-injection (breakthrough timing and plume migration); Maximizing the CO2 sequestration in the reservoir.
Defining producing well and CO2 injector well locations, numbers and phasing to evaluate expected CO2 injectivity and CO2 breakthrough issues;
Optimizing the development concept through a risk analysis approach;
Estimating the CO2-rich gas injectivity and storage capacity in the saline aquifer of the reservoir;
Predicting the behavior of the CO2-rich gas after re-injection (breakthrough timing and plume migration);
Maximizing the CO2 sequestration in the reservoir.
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.
The Japanese operator will submit a development plan to the Indonesian government within the next few weeks, with FID for the $20-billion project coming around 2022. The long-awaited Ichthys LNG Project off Western Australia has finally started gas production. LNG liquefaction is expected in a few weeks.
Upon completion, the FPSO will be the first permanently fiber rope-moored offshore facility in the Mediterranean, processing the reservoir fluids and export sales gas from the Karish and Tanin gas fields offshore Israel. At nearly 3,000 tonnes, the company said its lift of an FPSO module was one of the heaviest land-based crane lifts ever performed. ALE was contracted to lift six modules for Total’s FPSO module integration project in Nigeria. The Neptune-operated project is on track to start drilling later this year, with first oil scheduled for the end of 2020. The Norwegian North Sea field is expected to produce 30,000 BOE/D at its peak.