Managing Artificial Lift

Abstract

Distinguished Author Series Summary The goal of this work is to describe an approach to produce a well for maximum profitability by managing artificial lift effectively. Achieving maximum profitability from an artificially lifted well begins with selecting the lift method and continues with selecting materials, protecting materials, monitoring production data, and monitoring equipment performance. Changes suggested by the monitoring process strive to increase the profitability on an individual well basis. Introduction Managing artificial lift is a continuous process designed to achieve maximum profitability from a producing or service well. We must keep in mind our ultimate goals.Maximum profits, not maximum hydrocarbon production; one does not always mean the other.Maximum profits, not minimum equipment failures; again, one does not always mean the other.Maximum profit within the scope of operating safely and in an environmentally sound manner. The purpose of this paper is to detail an approach to managing artificial lift. This approach is described as a series of steps. Step 1. Original selection of the artificial-lift method. Step 2. Evaluation of production factors and expected production problems. This evaluation results in the selection of the original equipment used in the well, the failure-control methods, and the monitoring deemed necessary for protecting well equipment. Step 3. Continuous monitoring of meaningful production data: rates, fluid levels, water cuts, amp charts, pressures, etc. Step 4. Continuous monitoring of equipment performance data. Step 5. Evaluation of the production equipment-failure data regularly and as needed. This monitoring/evaluation results in courses of action that may include operational changes. Changes in the lift type might be from rod pump to progressing cavity pump or vice versa, from continuous to intermittent gas lift, or from rod pump to electric submersible pump (ESP) or vice versa. Equipment changes could include moving from a bottom hold down to a top holddown rod pump, from an insert to a tubing pump, or from steel to fiberglass rods. Another possible equipment change would be to add or remove a gas separator onan ESP system. Alterations in the failure-protection method might include changing from batch to continuous downhole corrosion treatment or vice versa, starting a scale-control program, changing the pump metallurgy or the ESP cable type, or running a cable with a chemical treating string. A change in the way the well is produced could be indicated, such as increasing or decreasing the stroke speed or changing the stroke length, raising or lowering the pump, anchoring the tubing, using a variable-speed drive on an ESP to reduce water production, or changing the type of power fluid in a hydraulic pumping installation. Thus, the loop is closed; the evaluation can, and sometimes does, take us back to where we started-e. g., to artificial method selection or, in some cases, to replacement/substitution. If it is to achieve its goal of maximum profitability, the process must look at each well individually. Well-by-well economics is the basis of the process. Artificial-Lift Selection The selection of the lift method considers the following. Geographic location. An offshore and/or Arctic location can limit the viable lift methods through size/weight restrictions or environmental concerns. Capital cost. These include not only the lift equipment, but also the production facilities required to support the lift method (e.g., compression requirements for gas lift). Operating costs. These costs include the energy needed to operate the lift and the cost to repair lift-system failures. Production flexibility. This means evaluating the minimum and maximum rates available from the lift method based on normal operating conditions compared with expected production. Reliability. Reliability includes expected run time and is a function of the failure frequency and the logistics required to repair failures. P. 335^