Posted by E Kofi Sakyiamah (Oil & Gas Industry Certified & Experienced Rigger/Crane Lifter, Logistician, and HSE Pro ) :
Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positive-displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate.
To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. The methods historically used to select the lift method for a particular field vary broadly across the industry. The methods include operator experience; what methods are available for installations in certain areas of the world; what is working in adjoining or similar fields; determining what methods will lift at the desired rates and from the required depths; evaluating lists of advantages and disadvantages; "expert" systems to both eliminate and select systems; and evaluation of initial costs, operating costs, production capabilities, etc. with the use of economics as a tool of selection, usually on a present-value basis.
These methods consider geographic location, capital cost, operating cost, production flexibility, reliability, and "mean time between failures." This chapter discusses some of the most commonly used methods. In most cases, what has worked best or which lift method performs best in similar fields serve as selection criteria. Also, the equipment and services available from vendors can easily determine which lift method will be applied. 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. 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. Typically, the reserves need to be produced in a timely manner with reasonably low operating costs. Conventional wisdom considers the best artificial lift method to be the system that provides the highest present value for the life of the project. Good data are required for a complete present-value analysis, and these data are not always broadly available.
In some situations, the type of lift already has been determined and the task is to best apply that system to the particular well. The more basic question, however, is how to determine the proper type of artificial lift to apply in a given field for maximum present value profit (PVP). This chapter briefly reviews each of the major types of artificial lift before examining some of the selection techniques. Some less familiar methods of lift also are mentioned. Preliminary factors related to the reservoir and well conditions that should be considered are introduced.
Environmental and geographical considerations may be overriding issues. For example, sucker-rod pumping is, by far, the most widely used artificial lift method in onshore United States operations. 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. Also, deep wells producing several thousands of barrels per day cannot be lifted by beam lift; therefore, other methods must be considered. Such geographic, environmental, and production considerations can limit the choices to only one method of lift; however, determining the best overall choice is more difficult when it is possible to apply several of the available lift methods. The poster, Emmanuel Kofi Sakyiamah, is an experienced Petroleum Industry (Oil & Gas Crane Lifter/Rigger, HSSEQ, Materials Coordinator Professional, etc ) who has worked on several exploration and production projects in Africa with GNPC, LUKOIL, NARANS ENERGY, ENI, SPRINGFIELD E&P, etc. You can reach E. Kofi Sakyiamah on +233 245 170 917 or +233 050 200 80 89 to engage him for his professional services with integrity.
Article Source/Credit:
Reference(s): Society of Petroleum Engineers
Artificial lift is a method used to lower the producing bottomhole pressure (BHP) on the formation to obtain a higher production rate from the well. This can be done with a positive-displacement downhole pump, such as a beam pump or a progressive cavity pump (PCP), to lower the flowing pressure at the pump intake. It also can be done with a downhole centrifugal pump, which could be a part of an electrical submersible pump (ESP) system. A lower bottomhole flowing pressure and higher flow rate can be achieved with gas lift in which the density of the fluid in the tubing is lowered and expanding gas helps to lift the fluids. Artificial lift can be used to generate flow from a well in which no flow is occurring or used to increase the flow from a well to produce at a higher rate. Most oil wells require artificial lift at some point in the life of the field, and many gas wells benefit from artificial lift to take liquids off the formation so gas can flow at a higher rate.
To realize the maximum potential from developing any oil or gas field, the most economical artificial lift method must be selected. The methods historically used to select the lift method for a particular field vary broadly across the industry. The methods include operator experience; what methods are available for installations in certain areas of the world; what is working in adjoining or similar fields; determining what methods will lift at the desired rates and from the required depths; evaluating lists of advantages and disadvantages; "expert" systems to both eliminate and select systems; and evaluation of initial costs, operating costs, production capabilities, etc. with the use of economics as a tool of selection, usually on a present-value basis.
These methods consider geographic location, capital cost, operating cost, production flexibility, reliability, and "mean time between failures." This chapter discusses some of the most commonly used methods. In most cases, what has worked best or which lift method performs best in similar fields serve as selection criteria. Also, the equipment and services available from vendors can easily determine which lift method will be applied. 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. 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. Typically, the reserves need to be produced in a timely manner with reasonably low operating costs. Conventional wisdom considers the best artificial lift method to be the system that provides the highest present value for the life of the project. Good data are required for a complete present-value analysis, and these data are not always broadly available.
In some situations, the type of lift already has been determined and the task is to best apply that system to the particular well. The more basic question, however, is how to determine the proper type of artificial lift to apply in a given field for maximum present value profit (PVP). This chapter briefly reviews each of the major types of artificial lift before examining some of the selection techniques. Some less familiar methods of lift also are mentioned. Preliminary factors related to the reservoir and well conditions that should be considered are introduced.
Environmental and geographical considerations may be overriding issues. For example, sucker-rod pumping is, by far, the most widely used artificial lift method in onshore United States operations. 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. Also, deep wells producing several thousands of barrels per day cannot be lifted by beam lift; therefore, other methods must be considered. Such geographic, environmental, and production considerations can limit the choices to only one method of lift; however, determining the best overall choice is more difficult when it is possible to apply several of the available lift methods. The poster, Emmanuel Kofi Sakyiamah, is an experienced Petroleum Industry (Oil & Gas Crane Lifter/Rigger, HSSEQ, Materials Coordinator Professional, etc ) who has worked on several exploration and production projects in Africa with GNPC, LUKOIL, NARANS ENERGY, ENI, SPRINGFIELD E&P, etc. You can reach E. Kofi Sakyiamah on +233 245 170 917 or +233 050 200 80 89 to engage him for his professional services with integrity.
Article Source/Credit:
Reference(s): Society of Petroleum Engineers
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