Reservoir Engineering in Modern Oilfields

Vertical, Deviated, Horizontal and Multilateral Well Systems

Wilson C. Chin

• Publisher: Wiley-Scrivener
• Year: 2016
• Print ISBN: 9781119283782
• eBook ISBN: 9781119284611
• Edition: 1
• Topic: Physical Sciences
• Subtopic: Energy

Real-world reservoirs are layered, heterogeneous and anisotropic, exposed to water and gas drives, faults, barriers and fractures. They are produced by systems of vertical, deviated, horizontal and multilateral wells whose locations, sizes, shapes and topologies are dictated "on the fly, at random"by petroleum engineers and drillers at well sites. Wells may be pressure or rate-constrained, with these roles re-assigned during simulation with older laterals shut-in, newer wells drilled and brought on stream, and so on. And all are subject to steady and transient production, each satisfying different physical and mathematical laws, making reservoir simulation an art difficult to master and introducing numerous barriers to entry. All of these important processes can now be simulated in any order using rapid, stable and accurate computational models developed over two decades.

And what if it were further possible to sketch complicated geologies and lithologies, plus equally complex systems of general wells, layer-by-layer using Windows Notepad? And with no prior reservoir simulation experience and only passing exposure to reservoir engineering principles? Have the user press "Simulate, " and literally, within minutes, produce complicated field-wide results, production forecasts, and detailed three-dimensional color pressure plots from integrated graphics algorithms?

Developed over years of research, this possibility has become reality. The author, an M.I.T. trained scientist who has authored fifteen original research books, over a hundred papers and forty patents, winner of a prestigious British Petroleum Chairman's Innovation Award in reservoir engineering and a record five awards from the United States Department of Energy, has delivered just such a product, making real-time planning at the well-site simple and practical. Workflows developed from experience as a practicing reservoir engineer are incorporated into "intelligent menus" that make in-depth understanding of simulation principles and readings of user manuals unnecessary. This volume describes new technology for down-to-earth problems using numerous examples performed with our state-of-the-art simulator, one that is available separately at affordable cost and requiring only simple Intel Core i5 computers without specialized graphics boards. The new methods are rigorous, validated and well-documented and are now available for broad petroleum industry application.

1
Reservoir Modeling – Background and Overview

Overview

Reservoir simulation is as old as petroleum exploration itself – it is essential to the profession because it supports cash flow analysis and economic planning. Its beginnings in the 1930s were humble and easily summarized. Let R_w and R_res denote wellbore and farfield reservoir radii, Pw and Pres their corresponding pressures, k the isotropic permeability, μ the liquid viscosity and H the thickness of the circular field. When this field is produced at the center by a fully penetrating vertical well, the steady-state pressure distribution is given by P = P_w + (P_res – P_w) (log r/R_w)/log(R_res/R_w) while the corresponding volume production flow rate is Q = – (2πKH/μ) (P_res – P_w)/log(R_res/R_w) where “r” is the radial coordinate. For transient compressible flows, analogous time-dependent formulas are found which depend on farfield boundary conditions – these models importantly predict production decreases with time and assist companies with investment and corporate planning. For the first several decades, these simple methods sufficed for most purposes, and quite literally, the entire field of reservoir engineering could be explained in a few volumes using equations and charts that did not require any computer access or modeling expertise.

Reservoir modeling landscape. All of that changed starting with the early 1990s. Horizontal wells emerged on the scene. These evolved into multilateral well systems drilled from offshore platforms. Reservoirs were no longer uniform and thick. Heterogeneities, anisotropy and layering were the rule. Produced fluids evolved from liquid to multiphase. Gas flows that were produced required thermodynamic descriptions and difficult nonlinear solutions not amenable to classical analysis methods. And finally, the vertical wells that penetrated ideal reservoirs were replaced by general wellbore topologies and multilateral systems (decided by drillers and geologists at the well site) and which penetrated formations that were as complicated as Nature and geology would allow. All of this made reservoir simulation challenging – but extremely frustrating in spite of the fastest computing machines.

Reflections on simulation and modeling. I began my career in reservoir modeling in the early 1990s, and being the “closet mathematician” that I knew myself to be, I was elated to work on anything resembling of Laplace’s equation – a formulation close to my prior comfort zone in theoretical aerodynamics. I expected the rigor and excitement that I had experienced, first in obtaining my Doctorate from the Massachusetts Institute of Technology (in mathematics and fluid dynamics), and later, as Research Scientist at Boeing, then the industry’s leader in computational fluids. However, practical reservoir simulation in oil company settings was not exactly research and not quite very exciting.

We ran massive simulations on Crays and IBM mainframes. Computations, accurate models we were told, crunched along for hours and days over evenings and weekends with unerring accuracy. But the methods were “black boxes” because the technology was proprietary – we could not assess the methods since the underlying equations and algorithms were off-limits. Graphical user interfaces were non-existent. Three-dimensional color plots were outputs required additional days of processing on dedicated graphics computers. Jobs were submitted using “keyword inputs” that replaced the Fortran decks that engineers had grown accustomed to. And these inputs included “matrix solver selection,” a nightmare even to Ph.D. mathematicians, since the optimal solver actually depended on the (evolving) reservoir being modeled.

Because getting simulators to operate properly required reading countless user manuals, reservoir engineers were often happy to get any output, right or wrong. At one leading company, in fact, results were almost always wrong. In an age when computer memory actually cost money, megabytes were allocated according to employee status – lower seniority personnel were allocated fewer memory blocks than their higher ranking peers. But they were not aware of nor privy to this policy – no one knew except middle management. And so, our expensive computers would overwrite recent results over and over, in the process generating absolutely useless numbers and just as garbled graphics.

Extrapolating core level rock properties to grid blocks that were literally hundreds of feet long in each direction required an incredible leap of faith that few engineers would admit to. Throw in the additional shale streak or fault that more than likely hides beneath the surface and one wonders what geology is really being modeled. Geostatistics, the new game in town at the time, was viewed with skepticism since modeled rocks did not look like rocks. Common sense dictated that a good geologist could probably produce a better picture of the underground reservoir than the best workflows exploration companies developed. With time, this author understood more the limitations behind the methods and algorithms used. These ideas are discussed in Chapter 2, which is essential reading for those who wish to understand the fundamental differences between our simulator and many commonly used. However, our explanations are not required for those who simply want to use our software – in fact, this Handbook is written with practitioners in mind and is very results oriented.

Reservoir Flow Algorithms for Petroleum Engineers

The author’s ideas behind reservoir flow modeling were strongly influenced by his background in mathematics and fluids, developed and honed at M.I.T. and Caltech, and later at Boeing and United Technologies, where advanced methods were put to use in modeling complicated three-dimensional effects. Early applications of these methods to reservoir engineering led to a Chairman’s Innovation Award at British Petroleum in 1990 (refer to Figure 1-1). New approaches to horizontal and multilateral well modeling were later marketed as 3D/SIM^TM by Gulf Publishing Company (e.g., see Figure 1-2), and offered as (the original) StrataSim™ by StrataModel, Inc. in 1992 (Figure 1-3). A comprehensive theoretical monograph, namely, Modern Reservoir Flow and Well Transient Analysis (Chin, 1993) appeared soon thereafter, and was followed a decade later by Quantitative Methods in Reservoir Engineering, First Edition (Chin, 2002) – a Second Edition, offered by Elsevier Science, will appear in late 2016. The methods described in the earlier publications are highlighted in Figures 1-4 to 1-6. Readers interested in these methods, or wishing to pursue research or develop related software...

Table of contents

• Cover
• Title page
• Copyright page
• Preface
• Acknowledgements
• Chapter 1: Reservoir Modeling – Background and Overview
• Chapter 2: Mathematical Modeling Ideas, Numerical Methods and Software
• Chapter 3: Simulation Capabilities – User Interface with Basic Well
• Chapter 4: Vertical, Deviated, Horizontal and Multilateral Well Systems
• Chapter 5: Well Models and Productivity Indexes
• References
• Index
• About the Author
• Multisim™ Software Order
• End User License Agreement