- 1.1. Introduction
- 1.2. Components of the Petroleum Production System
- 1.3. Well Productivity and Production Engineering
- 1.4. Units and Conversions
- References
This chapter is from the book
This chapter is from the book
This chapter is from the book
1.3. Well Productivity and Production Engineering
1.3.1. The Objectives of Production Engineering
Many of the components of the petroleum production system can be considered together by graphing the inflow performance relationship (IPR) and the vertical flow performance (VFP). Both the IPR and the VFP relate the wellbore flowing pressure to the surface production rate. The IPR represents what the reservoir can deliver, and the VFP represents what the well can deliver. Combined, as in Figure 1-7, the intersection of the IPR with the VFP yields the well deliverability, an expression of what a well will actually produce for a given operating condition. The role of a petroleum production engineer is to maximize the well deliverability in a cost-effective manner. Understanding and measuring the variables that control these relationships (well diagnosis) becomes imperative.
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Figure 1-7. Well deliverability gap between the original well performance and optimized well performance.
While these concepts will be dealt with extensively in subsequent chapters, it is useful here to present the productivity index, J, of an oil well (analogous expressions can be written for gas and two-phase wells):
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Equation (1-6) succinctly describes what is possible for a petroleum production engineer. First, the dimensioned productivity index with units of flow rate divided by pressure is proportional to the dimensionless (normalized) productivity index JD. The latter, in turn, has very well-known representations. For steady-state flow to a vertical well,
)
For pseudosteady state flow,
)
and for transient flow,
)
where pD is the dimensionless pressure. The terms steady state, pseudosteady state, and transient will be explained in Chapter 2. The concept of the dimensionless productivity index combines flow geometry and skin effects, and can be calculated for any well by measuring flow rate and pressure (reservoir and flowing bottomhole) and some other basic but important reservoir and fluid data.
For a specific reservoir with permeability k, thickness h, and with fluid formation volume factor B and viscosity μ, the only variable on the right-hand side of Equation (1-6) that can be engineered is the dimensionless productivity index. For example, the skin effect can be reduced or eliminated through matrix stimulation if it is caused by damage or can be otherwise remedied if it is caused by mechanical means. A negative skin effect can be imposed if a successful hydraulic fracture is created. Thus, stimulation can improve the productivity index. Finally, more favorable well geometry such as horizontal or complex wells can result in much higher values of JD.
In reservoirs with pressure drawdown-related problems (fines production, water or gas coning), increasing the productivity can allow lower drawdown with economically attractive production rates, as can be easily surmised by Equation (1-6).
Increasing the drawdown (p – pwf) by lowering pwf is the other option available to the production engineer to increase well deliverability. While the IPR remains the same, reduction of the flowing bottomhole pressure would increase the pressure gradient (p – pwf) and the flow rate, q, must increase accordingly. The VFP change in Figure 1-7 shows that the flowing bottomhole pressure may be lowered by minimizing the pressure losses between the bottomhole and the separation facility (by, for example, removing unnecessary restrictions, optimizing tubing size, etc.), or by implementing or improving artificial lift procedures. Improving well deliverability by optimizing the flow system from the bottomhole location to the surface production facility is a major role of the production engineer.
In summary, well performance evaluation and enhancement are the primary charges of the production engineer. The production engineer has three major tools for well performance evaluation: (1) the measurement of (or sometimes, simply the understanding of) the rate-versus-pressure drop relationships for the flow paths from the reservoir to the separator; (2) well testing, which evaluates the reservoir potential for flow and, through measurement of the skin effect, provides information about flow restrictions in the near-wellbore environmental; and (3) production logging measurements or measurements of pressure, temperature, or other properties by permanently installed downhole instruments, which can describe the distribution of flow into the wellbore, as well as diagnose other completion-related problems.
With diagnostic information in hand, the production engineer can then focus on the part or parts of the flow system that may be optimized to enhance productivity. Remedial steps can range from well stimulation procedures such as hydraulic fracturing that enhance flow in the reservoir to the resizing of surface flow lines to increase productivity. This textbook is aimed at providing the information a production engineer needs to perform these tasks of well performance evaluation and enhancement.
1.3.2. Organization of the Book
This textbook offers a structured approach toward the goal defined above. Chapters 2–4 present the inflow performance for oil, two-phase, and gas reservoirs. Chapter 5 deals with complex well architecture such as horizontal and multilateral wells, reflecting the enormous growth of this area of production engineering since the first edition of the book. Chapter 6 deals with the condition of the near-wellbore zone, such as damage, perforations, and gravel packing. Chapter 7 covers the flow of fluids to the surface. Chapter 8 describes the surface flow system, flow in horizontal pipes, and flow in horizontal wells. Combination of inflow performance and well performance versus time, taking into account single-well transient flow and material balance, is shown in Chapters 9 and 10. Therefore, Chapters 1–10 describe the workings of the reservoir and well systems.
- Gas lift is outlined in Chapter 11, and mechanical lift in Chapter 12.
- For an appropriate product engineering remedy, it is essential that well and reservoir diagnosis be done.
- Chapter 13 presents the state-of-the-art in modern diagnosis that includes well testing, production logging, and well monitoring with permanent downhole instruments.
- From the well diagnosis it can be concluded whether the well is in need of matrix stimulation, hydraulic fracturing, artificial lift, combinations of the above, or none.
- Matrix stimulation for all major types of reservoirs is presented in Chapters 14, 15, and 16. Hydraulic fracturing is discussed in Chapters 17 and 18.
- Chapter 19 is a new chapter dealing with advances in sand management.
- This textbook is designed for a two-semester, three-contact-hour-per-week sequence of petroleum engineering courses, or a similar training exposure.
To simplify the presentation of realistic examples, data for three characteristic reservoir types—an undersaturated oil reservoir, a saturated oil reservoir, and a gas reservoir—are presented in Appendixes. These data sets are used throughout the book. Examples and homework follow a more modern format than those used in the first edition. Less emphasis is given to hand-done calculations, although we still think it is essential for the reader to understand the salient fundamentals. Instead, exercises require application of modern software such as Excel spreadsheets and the PPS software included with this book, and trends of solutions and parametric studies are preferred in addition to single calculations with a given set of variables.