Xuehao Tan

Sucker Rod Pumping

Sucker rod pumping, also referred to as “beam pumping,” provides mechanical energy to lift oil from bottom-hole to surface. It is efficient, simple, and easy for field people to operate, and can be used to pump a well at very low bottom-hole pressure to maximize oil production rates. It is applicable to slim holes, multiple completions, and high-temperature and viscous oils. The major disadvantages of beam pumping include excessive friction in crooked/deviated holes, solid-sensitive problems, low efficiency in gassy wells, limited depth due to rod capacity, and bulky in offshore operations. Beam pumping trends include improved pump-off controllers, better gas separation, gas handling pumps, and optimization using surface and bottom-hole cards. This chapter presents the principles of sucker rod pumping systems and illustrates a procedure for selecting components of rod pumping systems. Major tasks include calculations of polished rod load, peak torque, stresses in the rod string, pump deliverability, and counterweight placement.

Chapter 7 – Forecast of Well Production

This chapter illustrates how to perform well production forecast, that is, future production rate and cumulative production of oil and gas wells, using the principle of nodal analysis and material balance. Accuracy of the forecast strongly depends on the quality of fluid property data, especially for the two-phase flow period. The reservoir conditions determine future inflow performance relationship (IPR) and, therefore, well production rates. Production rates are predicted using IPR and tubing performance relationship in the future times. Cumulative productions are predicted by integrations of future production rates. A complete production forecast should be carried out in different flow periods identified on the basis of flow regimes and drive mechanisms. For a volumetric oil reservoir, these periods include the following: transient flow period, pseudo-steady one-phase flow period, and pseudo-steady two-phase flow period. Readers should notice that reservoir simulators are often used in the industry for well production forecast, although this technique is not demonstrated in detail in this chapter.

Chapter 5 – Choke Performance

Wellhead chokes are used to limit production rates for regulations, reduce liquid loading problems, avoid sand production problems due to high drawdown, and control flow rate to avoid water or gas coning. Two types of wellhead chokes are used: positive (fixed) chokes and adjustable chokes. Placing a choke at the wellhead means fixing the wellhead pressure and thus the flowing bottom-hole pressure and production rate. For a given wellhead pressure, the flowing bottom-hole pressure can be determined by calculating pressure loss in the tubing. If the reservoir pressure and productivity index are known, the flow rate can be determined on the basis of inflow performance relationship. This chapter presents and illustrates different mathematical models for describing choke performance.

Wellbore Flow Performance

Wellbore performance analysis involves establishing a relationship among tubular size, wellhead and bottom-hole pressure, fluid properties, and fluid production rate. Understanding wellbore flow performance is vitally important to production engineers for designing oil well equipment and optimizing well production conditions. Oil can be produced through tubing, casing, or both in an oil well, depending on which flow path provides better performance. Producing oil through tubing is a better option in most cases to take the advantage of gas-lift effects. The mathematical models are also valid for casing flow and casing-tubing annular flow as long as hydraulic diameter is used. Among many models, the modified Hagedorn–Brown model has been found to give results with good accuracy. The industry practice is to conduct a flow gradient (FG) survey to measure the flowing pressures along the tubing string. The FG data are then employed to validate one of the models and tune the model if necessary before the model is used on a large scale.

Chapter 15 – Well Workover

Well workover refers to oil and gas well intervention involving invasive techniques, such as wireline, coiled tubing, or snubbing. It is a process of pulling and replacing a well completion to repair an existing production well for the purpose of restoring, prolonging, or enhancing the production of hydrocarbons. This chapter describes types of workover operations and associated equipment. Technical contents include work string mechanics and fluid mechanics in vertical and horizontal wells for wellbore cleaning and repair. Calculations are briefly outlined and illustrated with computer programs.

Chapter 6 – Well Deliverability

Well deliverability is determined by the combination of well inflow performance and wellbore flow performance. The former describes the deliverability of the reservoir, whereas the latter presents the resistance to flow of production string. This chapter focuses on prediction of achievable fluid production rates from wells including vertical, horizontal, fractured, multi-fractured, and multilateral wells. The technique of analysis is called Nodal analysis. Local flow path dimension, fluid properties, and heat transfer must be considered to improve accuracy. It is vitally important to validate inflow performance relationship and tubing performance relationship models before performing Nodal analysis on a large scale. A Nodal analysis model is not considered to be reliable before it can match well production rates at two bottom-hole pressures.

Gas Hydrate Control

Water and hydrocarbon fluids can form hydrate and block oil and gas pipelines, resulting in restrictions to oil and gas transportation through pipelines. Mitigating hydrate formation in pipelines is one of the most important issues in flow assurance. This chapter describes hydrate forming conditions and methods employed in the petroleum industry to effectively mitigate gas hydrate problems in pipeline operations. These methods include water removal, chemical inhibition, thermal insulation, heating, and system depressurization. This chapter also provides guidelines to maintaining pipeline flow efficiency.

Chapter 18 – Other Artificial Lift Methods

This chapter provides a brief introduction to the principles of electrical submersible pumping (ESP), hydraulic piston pumping, hydraulic jet pumping, progressive cavity pumping, and plunger lift systems. The ESP is a relatively efficient artificial lift. Under certain conditions, it is even more efficient than sucker rod beam pumping. Hydraulic piston pumping systems can lift large volumes of liquid from great depths by pumping wells down to fairly low pressures. Crooked holes present minimal problems. The chapter presents design guidelines and illustrates example calculations with spreadsheet programs.

Chapter 8 – Production Decline Analysis

This chapter presents empirical models and procedure for using these models to perform production decline data analyses. Production decline analysis is a traditional means of identifying well production problems and predicting well performance and life span based on real production data. It uses empirical decline models that have little fundamental justification. These models include exponential decline (constant fractional decline), harmonic decline, and hyperbolic decline. Although the hyperbolic decline model is more general, the other two models are degenerations of the hyperbolic decline model. The relative decline rate and production rate decline equations for the exponential decline model can be derived from volumetric reservoir model. Cumulative production expression is obtained by integrating the production rate decline equation. Computer programs can be used for model identification, model parameter determination, and production rate prediction.

Chapter 11 – Transportation Systems

This chapter describes oil and gas transportation systems. Crude oil and natural gas are transmitted over short or long distances mainly through pipelines. Pumps and compressors are used for providing pressures required for the transportation. The chapter presents principles of pumps and compressors and techniques that are used for selecting these types of equipment. Pipeline design criteria, fluid flow in pipelines, and pipeline modification are also discussed in the chapter. The chapter presents and demonstrates the procedure for selecting pumps and gas compressors and illustrates the theory and applications of pipeline design.