Improved reservoir knowledge is key to extracting additional value from existing oil and gas assets. However, given the uncertainty in the subsurface, it is always a question if our current development strategy is the most robust choice, or if there are alternatives that can further increase the value of our field. This paper presents a novel solution that enables the asset team to answer these questions in a new way. Furthermore, the solution helps teams quickly identify and screen new opportunities that ultimately increase both subsurface understanding and the value of the field. The solution combines a quasi- Newton gradient based numerical optimization scheme with a stochastic simplex approximate gradient (StoSAG) algorithm. Because the algorithm is non-intrusive with respect to the fluid flow simulator, we can directly apply the solution on any flow optimization problem without the need to access the simulator source code. The solution is implemented using a microservice architecture that allows for efficient scaling and deployment either on cloud-based or internal systems. We demonstrate the proposed solution on a field containing 11 oil producers and 7 water injectors by optimizing the water injection and oil production rates. The machine learning algorithm allows us to quickly explore different drainage strategies, given the current understanding and associated uncertainties of the reservoir.
Specifically, the software solution suggests that 6 of the 18 pre-defined well targets are high risk and/or of little value. Running a second development scenario where we do not drill these six wells reduces the investment cost of this field by 163 MUSD and increases the expected net present value per well of the field by 48 percent. Compared with the reactive control drainage strategy approach, we increase the expected net present value of the field by 9.0 %, while simultaneously lowering the associated risk.
The Vega subsea field in Norway has been producing successfully using a continuous Mono Ethylene Glycol (MEG) injection, topped up with corrosion inhibition means. A topside reclamation process allows reuse of MEG, however, limits the possibilities to produce saline water. In order to manage wells producing saline formation water and to increase ultimate recovery, a new flow assurance and integrity philosophy without continuous MEG injection is considered. This paper describes the options on hydrate as well as integrity management and the modifications both on the subsea and topside facilities required to enable an operational philosophy change. This change of the operational philosophy appears feasible, using either timely depressurization or Low Dosage Hydrate Inhibitors (LDHI) as well as a film building corrosion inhibitor in the system.
One of the most important environmental issues of openpit mining is the closure of mine pit lakes. This article from Mining Engineering provides an account by Gerry Stephenson, who was chief mining engineer of Canmore Mines and was instrumental in the reclamation of Canmore Creek Mine pit lakes. With oil and gas facing a talent gap in the wake of the Great Crew Change, the industry finds itself competing for young talent looking for innovative, purpose-driven work. How can energy foster the culture of innovation needed to attract the new workforce, and how does it sell that culture? The updated document offers an introductory overview of the broad topics of oil spill preparedness and response and provides signposting and hyperlinks to a full range of materials from IPIECA and the International Association of Oil and Gas Producers. This paper details the methodology adopted to monitor gas-pipeline leakages using distributed fiber-optic sensing, using an optical fiber as a linear sensor to provide valuable measurement information from all along the fiber itself. It is “one of the world’s largest greenhouse gas mitigation projects ever undertaken by industry,” Chevron said in a news release.
The decision comes a year after Neptune stopped production from the North Sea gas field, and 4 months after it submitted decommissioning plans to the UK authorities. 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. Norwegian authorities approved development plans for Duva and Gjøa P1, both of which are expected to produce first oil in late 2020. The fields will each tie back to the Gjøa platform on the Norwegian Continental Shelf.
In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel. The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. The subsea tieback is expected to start up in 2021. The Neptune-operated project is on track to start drilling later this year, with first oil scheduled for the end of 2020.
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.
In a $60 to $70 oil environment, the subsea market is poised to grow around 7% annually up to 2025. But a significant portion of this activity is at risk if the price of Brent crude falls to $50 per barrel. The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
The entrepreneurial ecosystem and the oil and gas industry are not a perfect match, but the industry has made strides in recent years to attract the startups developing innovative technologies that could usher it into a new era. How are companies bridging the gap? The deal sees H2O Midstream increase its produced water gathering network to more than 435,000 B/D of disposal capacity and 190 total miles of pipeline. The Permian water midstream company will add more than 40,000 B/D of recycling capacity with the option to double that capacity over time. The transaction is planned to be structured as a spin-off of TechnipFMC’s onshore/offshore segment to create SpinCo and RemainCo. The separation is expected to be completed in the first half of 2020. Calgary-based Pembina Pipeline Corp. has entered into agreements to acquire Kinder Morgan Canada Ltd. and the US portion of the Cochin Pipeline system from Kinder Morgan for a total purchase price of approximately $4.35 billion.
The subsea operations company said its most recent campaign is the first fully unmanned offshore pipeline inspection completed “over the horizon,” surveying up to 100 km from the shore. One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates. The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September.