ESP's: On and Offshore Problems and Solutions
Abstract: TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThis paper is a follow-on to SPE 28694 (Ref. 180) which summarizes and categorizes ESP literature by a number of different topics. The intent is to list problems mentioned in various papers and a quick mention of the solutions, which are discussed in the given references. As mentioned in the previous reference, it is also an attempt to relate problems to various field conditions, however many of the field papers do not include a complete listing of field cond… Show more
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For many years rod pumping has been a desirable artificial lift method for on-shore oil wells. Today, in addition to rod pumps, other artificial lift methods such as gas lift and electrical submersible pumps (ESP) are also available for assisting well production. While rod pumps have been proven to be one of the simplest and most economical choices, when it is not sufficient for high-rate wells, harsh-fluid production, or deep wells, operators turn to other lift methods to produce hydrocarbons to the surface. The selection of appropriate artificial lift methods revolves around many factors, including economics. This paper presents a conceptual and feasibility study of combination of two methods of lifting for production of moderate volumes of oil from deep or ultra-deep onshore wells. It proposes to use an ESP and a sucker rod pumping unit simultaneously to lift fluids. The argument is that to lift from a deep well, with only ESP the cost and housing limitation of the wellbore may become a vital problem. Lifting the hydrocarbons to a certain depth by an ESP system, and then using the rod pump to transport the fluid to the surface may be a solution for deep and ultra deep wells. One of the critical issues in this concept is that rod pump lift is an intermittent lift, but ESP is a continuous lift. This issue has been address with the design of a chamber in between the two systems to accommodate the two lift devices and ensure continuity. This paper presents an example with detailed calculations to provide the technical support to the idea. Even though this approach has not been applied in the field, once proven feasible, the dual lift method can bring a solution with economic value to artificial lift for ultra-deep onshore oil wells. Introduction Artificial lift is a means to assist oil well production. It is applied when the wellbore pressure drop is too high, and the pressure at the bottom of the well (supplied from the reservoir) cannot lift the desired amount of fluid naturally to the surface. The main methods of artificial lift include gas lift and pump lift, such as sucker rod pump, plunger pump, positive capacity pump and electrical submersible pump (ESP). While gas lift aims at lowering the pressure gradient in the tubing, pump lift increases production rate by lowering the bottomhole flowing pressure and boosting the pressure with the pump. There are two types of pumps in artificial lift, positive displacement pumps (sucker rod pumps) and dynamic displacement pump (e.g. electrical submersible pump). The rod pump is, probably, the oldest method of artificial lift and has proven to be a very desirable lift method due to the simplicity and minimum requirement of maintenance, for many years rod pumping has been a very desirable artificial lift selection for on-shore oil wells. As the technology has allowed operators to go deeper and produce at higher rates many other artificial lift methods have been developed. A modern example is ESP systems. Compared with a rod pump, an ESP can handle higher flow rates, and is more tolerable of the produced fluid. Selecting the appropriate artificial lift method is an essential but well-understood practice in production engineering. The decision of artificial lift methods revolves around many factors, predominately economics and technical complexity. The fundamentals have been discussed in detail in many publications (Allen and Robert, 1978, Economides, et. al., 1994, Lea and Bearden, 1999, and Naguib, et. al., 2000), and have been followed in the field applications. As energy demands have increased and technologies advanced, deep and ultra deep wells have been increasingly drilled. The industry faces the challenges in drilling and completion of these wells, as well as producing such a well with appropriate artificial lift. While rod pumps are limited in deep wells, the conventional design of ESP will also have wellbore space and cost concerns. To the point, in some deep wells only one lift method may not satisfy the production requirement. This paper discusses a possibility of combining two forms of artificial lift methods for deep well production.
For many years rod pumping has been a desirable artificial lift method for on-shore oil wells. Today, in addition to rod pumps, other artificial lift methods such as gas lift and electrical submersible pumps (ESP) are also available for assisting well production. While rod pumps have been proven to be one of the simplest and most economical choices, when it is not sufficient for high-rate wells, harsh-fluid production, or deep wells, operators turn to other lift methods to produce hydrocarbons to the surface. The selection of appropriate artificial lift methods revolves around many factors, including economics. This paper presents a conceptual and feasibility study of combination of two methods of lifting for production of moderate volumes of oil from deep or ultra-deep onshore wells. It proposes to use an ESP and a sucker rod pumping unit simultaneously to lift fluids. The argument is that to lift from a deep well, with only ESP the cost and housing limitation of the wellbore may become a vital problem. Lifting the hydrocarbons to a certain depth by an ESP system, and then using the rod pump to transport the fluid to the surface may be a solution for deep and ultra deep wells. One of the critical issues in this concept is that rod pump lift is an intermittent lift, but ESP is a continuous lift. This issue has been address with the design of a chamber in between the two systems to accommodate the two lift devices and ensure continuity. This paper presents an example with detailed calculations to provide the technical support to the idea. Even though this approach has not been applied in the field, once proven feasible, the dual lift method can bring a solution with economic value to artificial lift for ultra-deep onshore oil wells. Introduction Artificial lift is a means to assist oil well production. It is applied when the wellbore pressure drop is too high, and the pressure at the bottom of the well (supplied from the reservoir) cannot lift the desired amount of fluid naturally to the surface. The main methods of artificial lift include gas lift and pump lift, such as sucker rod pump, plunger pump, positive capacity pump and electrical submersible pump (ESP). While gas lift aims at lowering the pressure gradient in the tubing, pump lift increases production rate by lowering the bottomhole flowing pressure and boosting the pressure with the pump. There are two types of pumps in artificial lift, positive displacement pumps (sucker rod pumps) and dynamic displacement pump (e.g. electrical submersible pump). The rod pump is, probably, the oldest method of artificial lift and has proven to be a very desirable lift method due to the simplicity and minimum requirement of maintenance, for many years rod pumping has been a very desirable artificial lift selection for on-shore oil wells. As the technology has allowed operators to go deeper and produce at higher rates many other artificial lift methods have been developed. A modern example is ESP systems. Compared with a rod pump, an ESP can handle higher flow rates, and is more tolerable of the produced fluid. Selecting the appropriate artificial lift method is an essential but well-understood practice in production engineering. The decision of artificial lift methods revolves around many factors, predominately economics and technical complexity. The fundamentals have been discussed in detail in many publications (Allen and Robert, 1978, Economides, et. al., 1994, Lea and Bearden, 1999, and Naguib, et. al., 2000), and have been followed in the field applications. As energy demands have increased and technologies advanced, deep and ultra deep wells have been increasingly drilled. The industry faces the challenges in drilling and completion of these wells, as well as producing such a well with appropriate artificial lift. While rod pumps are limited in deep wells, the conventional design of ESP will also have wellbore space and cost concerns. To the point, in some deep wells only one lift method may not satisfy the production requirement. This paper discusses a possibility of combining two forms of artificial lift methods for deep well production.
The number of electrical submersible pumps (ESPs) used as an artificial lift process is increasing worldwide, due to their efficiency and their ability in increasing production rate substantially. Yet ESP's field implementation needs a proper design to achieve the lift efficiency needed. In case of deep and ultra deep wells, which are drilled frequently, selecting the right ESP configuration and arrangement is critical to the success of the lifting operation. The wellbore space, the rate targeted and the costs involved are among the crucial parameters for the choice of an ESP system. Reservoir conditions or at least near wellbore conditions are not taken directly into consideration while designing the ESP system. The overall ESP design -including the number of stages and motor size -is determined by pre-defined wellbore parameters, and intake and discharge pressure. The present analysis reveals the effect of skin on the targeted ESP design and the associated system characteristics. IntroductionWhen oil wells are not able to flow naturally, the well production is sustained by artificial means, known as artificial lift. Usually artificial lift is applied when the wellbore pressure drop is larger than the bottom hole flowing pressure, and therefore to overcome the pressure difference several techniques are used. The main artificial lift methods are: (i) gas lift to lower the pressure gradient in the production tubing and (ii) pumps to lower the bottomhole flowing pressure. Different types of pumps were used at the early stages of artificial lift operations. Examples include as positive displacement pumps, e.g, sucker rod pumps; and thrust pumps, e.g., electrical submersible pumps (ESP). This latest technology was possible as operators could deploy it deeper in the well and extract higher production rates (Sachdeva, et al., 1994, Macary, et al., 2003, Qahtani, 2007and Zhou & Sachdeva, 2010. A successful design of an ESP system relies on both economics and technical complications. Several authors have previously summarized the effect of each of these factors (Lea and Bearden, 1999 and Naguib, et al., 2000).Still the industry faces challenges in understanding the reasons and causes of ESP system failure, due to the complexity of the environment and the harsh media that these systems are designed for. The run life of an ESP system is shorter in some cases than the expected design life time. Near-wellbore conditions are not considered a crucial part in the design of an ESP system. Formation damage could impact substantially on the well flow performance. Therefore expected design parameters could lead to an ESP system under design for particular well scenarios. The presence of a skin in the near-wellbore region can result in additional pressure considerations. Wattenbarger and Ramey (1970) described the effect of skin on well performance and that skin was an obstruction to the flow, caused by an infinitesimaly thin damaged region around the wellbore. The present paper discusses the effect of the near-wellbore region condi...
The present paper is concerned with a study of electrical submersible pump failure due to scale build-up. From motor current signals recorded several weeks before the failure, weak fluctuations were recorded, indicating a change in the motor load. The advanced signal analysis of the motor current data revealed the presence of a dynamical character of the electrical submersible pump signal when scale started rapidly building up in the pump stages. Based on the raw data from the motor current draw a dynamical cascade was identified from the current marked with the superimposition of several characteristic frequencies added in time and developing a chaotic trend. The analysis is conducted with different signal analysis recognition tools such as Fourier transform, wavelet transform and chaotic attractors, which describe the nature of the scale signature in the current logs clearly. This analysis can be the first step towards developing real time diagnostic tools to predict ESP failures and acting accordingly.
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