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Recent advances in field development are not based on specific technical breakthroughs (although shale oil and gas and deep oil owe a lot to those) but on economic models and scenarios run at the very beginning, before any dollar is invested.
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This paper presents a new approach for more-accurate modeling of liquid blockage in tight oil and gas reservoirs and investigates the use of solvents for blockage removal.
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This paper evaluates the ability of different groups of surfactants to improve oil recovery in unconventional liquid reservoirs (ULRs) by experimentally simulating the fracture treatment to represent surfactant imbibition in a ULR core fracture during a soaking flowback.
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In this paper, the authors consider the development plan of shale gas or tight oil with multiple multistage fractured laterals in a large square drainage area that they call a “section” (usually 640 acres in the US).
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With low primary-recovery rates in unconventional reservoirs and the longer-term development prospects for EOR applications on a fieldwide scale, the potential for accelerated completion optimization in new wells and production-enhancement treatments in existing wells is substantial.
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Well-placement optimization is one of the more challenging problems in the oil and gas industry. Although several optimization methods have been proposed, the most-used approach remains that of manual optimization by reservoir engineers.
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The results of numerical simulations for the Lost Hills field were not successful because of the special characteristics of its diatomite reservoirs—low permeability but high porosity, weak rock strength, and strong imbibition.
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This paper shows how a new approach to small fields could unlock more than twice the net present value (NPV) of larger conventional fields in Southeast Asia at a similar level of capital expenditure (CAPEX).
