Management: The High-Tech World of Testing
- Mario Ruscev (Schlumberger)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 2007
- Document Type
- Journal Paper
- 34 - 36
- 2007. Copyright is retained by the author. This document is distributed by SPE with the permission of the author. Contact the author for permission to use material from this document.
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Driven by mounting pressure to reduce E&P risk, the testing techniques introduced by brothers E.C. and M.O. Johnston in the 1920s are mounting a revival. But they bear little resemblance to those early days when simple downhole tools were run and the only measurements consisted of examining the produced fluids. Often characterized by large amounts of piping and heavy equipment, testing has become high-tech and makes use of the most sophisticated types of metrology available. Today, testing results can be delivered in near-real time. Results are highly accurate and integrate seamlessly with comprehensive, dynamic reservoir models that benefit from the aggregate of exploration, drilling, formation evaluation, and production data.
In reality, a test involves a pressure sensor of the right resolution and accuracy put in the right place and left for the right amount of time. The trick, of course, is in the determination of what is “right,” and that involves a deep understanding of the reservoir as well as flow dynamics and fluid mechanics. Absent these qualities, a test can be deemed a “successful failure”—meaning one where all the valves, chokes, separators, tanks, and gauges work properly, but the data are ambiguous and inconclusive.
Today, operators simply cannot risk getting it wrong. For example, if a subsea system or a floating production facility is installed that is either too large or too small or because production was incorrectly predicted, the cost can be ruinous. The risks of drilling and completing wells have grown exponentially, as have the potential values of oil and gas production. Modern testing minimizes those risks to the maximum.
Plumbers No More
While hooking up myriad valves, pipes, and tanks to separate fluids into three phases (oil, gas, and water) in order to make flow measurements worked in earlier times, it cannot solve today’s challenges. In the past, the industry’s appreciation of testing was gauged by the amount of steel involved. Today, high-speed sensors resolve multiphase flow that often includes gas and condensate. Operators need solid information on which to base critical decisions, and they want details on today’s well conditions, as well as an accurate view of the future. Answers must address life-of-the-reservoir issues. Much of the technology to support these solutions is available, but more development is needed. Two areas in which high technology is playing a major role are multiphase flowmetering and fast pressure/volume/temperature (PVT) analysis.
Portable on-site well fluid analysis services are now available that can be set up at the wellsite in minutes and provide key fluid parameters that figure in the operator’s production decisions. Essential for evaluating the profitability of the prospect, fluid composition and physical properties from samples collected at the well-head impact completion and production facility design. Compositional analysis to C12 for gas and C36 for oil provides key input for reservoir and equations-of-state simulators. Results can now be derived, verified, and presented, usually before the testing crew has rigged down. Besides enabling near real-time-quality control, data from the on-site PVT analysis are used to optimize multiphase flowmeter measurements.
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