If producing oil or liquid rate is plotted (X axis) against producing bottomhole pressure (BHP), one of two inflow performance relationships (IPR) usually is seen. Obviously, wells should be drilled and completed with future production and lift methods in mind, but this is often not the case.Īmong the most important factors to consider when selecting an artificial lift system are current and future reservoir pressure and well productivity. If oil prices are low, it is tempting to select a small casing size to help with current economics. Even if target production rates can be achieved, smaller casing sizes can lead to higher long-term well-servicing problems. This can lead to an ultimate loss of total reserves. Many times, a casing program has been designed to minimize well-completion costs, but it is later found that the desired production could not be obtained because of the size limitation on the artificial lift equipment. Once the method is selected, the wellbore size required to obtain the desired production rate must be considered. Such geographic, environmental, and production considerations can limit the choices to only one method of lift determining the best overall choice is more difficult when it is possible to apply several of the available lift methods.Īrtificial lift method selection should be a part of the overall well design. Also, deep wells producing several thousands of barrels per day cannot be lifted by beam lift other methods must be considered. However, in a densely populated city or on an offshore platform with 40 wells in a very small deck area, sucker-rod pumping might be a poor choice. For example, sucker-rod pumping is, by far, the most widely used artificial lift method in onshore US operations. Good data are required for a complete present-value analysis, and these data are not always broadly available.Įnvironmental and geographical considerations may be overriding issues. Conventional wisdom considers the best artificial lift method to be the system that provides the highest present value for the life of the project. Typically, the reserves need to be produced in a timely manner with reasonably low operating costs. If the “best” lift method is not selected, such factors as long-term servicing costs, deferred production during workovers, and excessive energy costs (poor efficiency) can reduce drastically the net present value (NPV) of the project. However, when significant costs for well servicing and high production rates are a part of the scenario, it becomes prudent for the operator to consider most, if not all, of the available evaluation and selection methods. Also, the equipment and services available from vendors can easily determine which lift method will be applied. In most cases, what has worked best or which lift method performs best in similar fields serve as selection criteria. with the use of economics as a tool of selection, usually on a present-value basis Evaluation of initial costs, operating costs, production capabilities, etc.“Expert” systems to both eliminate and select systems.Evaluating lists of advantages and disadvantages.Determining what methods will lift at the desired rates and from the required depths.What is working in adjoining or similar fields.What methods are available for installations in certain areas of the world.The methods historically used to select the lift method for a particular field vary broadly across the industry. To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. For offshore and higher-rate wells around the world, the use of ESPs and gas lift is much higher.
These statistics indicate the dominance of rod pumping for onshore operations. Of the nonstripper “higher” volume wells, 27% are rod pumped, 52% are gas lifted, and the remainder are lifted with ESPs, hydraulic pumps, and other methods of lift. The vast majority of these stripper wells are lifted with sucker-rod pumps. Approximately 80% of all US oil wells are stripper wells making less than 10 B/D with some water cut. In the US, sucker-rod pumps lift approximately 350,000 wells. More than 750,000 of the lifted wells use sucker-rod pumps.
More than 1 million wells use some type of artificial lift. There are approximately 2 million oil wells in operation worldwide. This system has a PCP with the motor and some other components similar to an ESP. There are other methods, such as the electrical submersible progressive cavity pump (ESPCP) for pumping solids and viscous oils, in deviated wells. Reciprocating and jet hydraulic pumping systems.6 Long-term reservoir performance and facility constraints.4 Reservoir pressure and well productivity.
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