Reservoir
A report commissioned by Havtil, the Norwegian Ocean Industry Authority, calls for better dialogue regarding pore-pressure uncertainty and higher-end drilling techniques like managed pressure drilling as methods to reduce the risk of well-control events.
The events will be co-located 3–5 May 2027 at Reliant Park in Houston, Texas.
Bridging the gap between foundational guidance and real-world application, SPE’s Oil and Gas Reserves Committee is advancing PRMS education with a new, peer-reviewed training initiative. This article highlights the evolution of the PRMS knowledge base and introduces the PRMS Training Master Slides—a modular, instructor-led framework designed to improve consistency, cl…
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In this paper, the authors derive and implement an interwell numerical simulation model (INSIM) that can be used as a calculation tool to approximate the performance of a reservoir under waterflooding. -
Understanding how much rock is being stimulated and propped is critical for unconventional producers. New imaging methods using electromagnetic energy or acoustic microemitters could represent a milestone in understanding what is left behind after fracturing.
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The world’s first reflection seismic field tests were conducted near Oklahoma City in 1921, and, ever since then, the industry has endeavored to improve that seismic imaging process.
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Thermal steam stimulation is considered the most effective of current methods for heavy-oil production. However, the method has problems with low coverage by steam injection and decreased efficiency.
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Acquiring new 3D broadband seismic data of a gas field containing legacy 3D conventional towed-streamer seismic data.
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Integration of microgravity, resistivity, and seismic data improves the fidelity of seismic images and the depth match.
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The addition of a hydrocarbon condensate to steam operations in heavy-oil and bitumen reservoirs has emerged as a potential technology to improve not only oil recovery but also energy efficiency.
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Chemical enhanced-oil-recovery methods such as polymer and alkaline/surfactant/polymer (ASP) flooding are generally not considered suitable for oil viscosities greater than 100 or 200 cp.
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In drawdown management, operators can exert control over the downhole flow pressure, reservoir pressure, and choke size to avoid estimated ultimate recovery (EUR) losses.
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The integration of microseismic data with 3D seismic attributes, and well log and completions data is used to understand geomechanical rock properties.
