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The following topic describes the intermittent-flow gas lifts and the factors which affect its design and performance. Intermittent-flow gas lift is applicable to low-productivity wells and to low- and high-productivity wells with low reservoir pressure. As the name implies, the reservoir fluid is produced intermittently by displacing liquid slugs with high-pressure injection gas, as illustrated inFigure 1. Either an electronic or clock-driven time-cycle controller, or an adjustable or fixed choke, controls the flow of injection gas. Not all gas lift valves operate on choke control. The number of intermittent-flow gas lift installations on time-cycle control far exceeds the number of choke-controlled installations. Intermittent-flow gas lift should be used only for tubing flow.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
PUBLICATION RIGHTS RESERVED This paper is to be presented at the 36th Annual Fall Meeting of the Society of Petroleum Engineers of AIME in Dallas, October 8โ11, 1961, and is considered the property of the Society of Petroleum Engineers. Permission to publish is hereby restricted to an abstract of not more than 300 words, with no illustrations, unless the paper is specifically released to the press by the Editor of JOURNAL OF PETROLEUM TECHNOLOGY or the Executive Secretary. Such abstract should contain conspicuous acknowledgment of where and by whom the paper is presented. Publication elsewhere after publication in JOURNAL OF PETROLEUM TECHNOLOGY or SOCIETY OF PETROLEUM ENGINEERS JOURNAL is granted on request, providing proper credit is given that publication and the original presentation of the paper. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and considered for publication in one of the two SPE magazines with the paper. Abstract A peripheral water injection system was begun in the Abqaiq Field of Saudi Arabia in 1956. The initial system consisted of gravity injection into three nose wells. Following the completion of the flank installations and electrification in 1958, injection rates were increased to the present rate of 30 to 40 MBD per well. The field water injection rate is approximately 300 MBD. The volumetric effectiveness of injected water is 50 per cent and is expected to increase to 70โ80 per cent. The water supply source, the Wasia formation, is a prolific aquifer containing non-potable water of 8,000 ppm total dissolved solids. The water is corrosive, however, corrosion is controlled by inhibitor injection. The Wasia water injection system is a closed pressure system. A temporary sea water injection system was installed to evaluate the problems of a sea water injection project. The results of this project are presented. FIELD HISTORY The Abqaiq field was discovered in 1940, but full-scale development did not begin until 1946. Figure 1 is a structure contour map of the Abqaiq field. For analytical purposes the field has been divided into two areas designated A and B as shown on the map. At present there are 61 producible wells in the field. They are drilled on a contour pattern and the average spacing is about 5,000 feet. Initial pressure at -6,500 feet datum was 3,395 psig and the bubble point of the reservoir fluid is 2,545 psig. The reservoir was undersaturated at discovery. Average solution gas-oil ratio is 850 scf/STB. There has been essentially no change in producing gas-oil ratio. Separation is done at centralized separator plants of which there are three: one, in Area B and two in Area A. The crude goes through separation stages of 500, 250, 50 and 2 psig.
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Asia > Middle East > Saudi Arabia > Eastern Province > Arabian Basin > Widyan Basin > Abqaiq Field (0.99)
- Asia > Middle East > Saudi Arabia > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Wasia Formation (0.99)
Summary Gas injection pressure has a very decided effect on the efficiency and operation of a continuous flow gas lift well. Selection of a gas injection pressure that is too high can result in needless investment in compression and other equipment, whereas pressures that are too low can cause in efficient gas lift operations and failure to produce a well's full potential. This paper discusses the produce a well's full potential. This paper discusses the effect of various producing parameters on the selection of gas injection pressure and describes techniques for predicting and evaluating these effects on a specific gas predicting and evaluating these effects on a specific gas lift installation to determine the most profitable operating system. Introduction The function of injection gas in a continuous flow gas liftwell is two-fold. First, it must aerate the fluid sufficiently to unload the well column down to an operating point. Second, it must reduce the fluid column density sufficiently to allow the reservoir pressure to push the produced fluid to the surface. The depth at which the produced fluid to the surface. The depth at which the operating valve is located depends on several factors, but primarily it is a function of the available injection gas primarily it is a function of the available injection gas pressure. pressure. To understand the current situation in the U.S. regarding injection gas pressures, it is necessary to examine the history of gas lift. In the early days (1865 to 1925), very large air stations were built and air was compressed and used to provide gas for artificial lift. The early compressors were driven by steam, which was generated in boilers burning crude oil. Later, compressors were driven by oil combustion engines and, in some areas, electric motors. These early compressors were usually single or dual stage and since they were made for a very low suction pressure (atmospheric pressure), there sulting discharge pressure was relatively low, usually on the order of a few hundred psi. In these early days, very little gas lift equipment mas available for use inside the well. Thus, the depth of lift was strictly a function of the depth to which the produced fluid column could be balanced, or slightly overbalanced, by a column of air. This meant that with a 600-psi[4.1-MPa] injection gas pressure at the surface, a well could be unloaded and gas injected down to about 1,500to 2,000 ft [457 to 610 m] of depth. However, such a situation may not have represented too much of a problem at that time, since most of the producing wells were problem at that time, since most of the producing wells were rather shallow compared with today's standards. During the 1920's, the oil industry began collecting and selling the gas associated with oil production. The operating pressure for most of the gas transmission systems was usually around 800 psi [5.5 MPa] or less. Therefore, as a natural adjunct to the gas sales system, some of the compressed natural gas was used for gas lift. This yielded gas with much better properties at a higher pressure than was available from the old air lift systems. pressure than was available from the old air lift systems. In most respects, even today, gas lift injection pressures are still governed by the gas sales system pressures are still governed by the gas sales system pressures. Downhole equipment has been developed pressures. Downhole equipment has been developed during the past 50 years that allows wells to be lifted deeper with the available pressure, but basically the surface injection pressures have remained dependent on the gassales system pressures. Even where large gas fields have been discovered with higher pressures, the source for gaslift has almost always been located downstream of the processing facilities leading to the gas sales system. processing facilities leading to the gas sales system. The in efficiency of such low-pressure gas lift systems in deeper wells was masked during the early years of gas lift by the low value of gas and the low cost of gas compression. In addition, a low demand for oil encouraged very low well rates that could be accomplished with very little pressure drawdown in the producing well. About 12 to 15 years ago, this situation changed and suddenly many gas lift systems were found to be grossly inadequate for producing the higher rates that were required. How Gas Injection Pressure Affects Gas Lift Efficiency In a continuous-flow gas lift system, injection gas is used to supplement formation gas (Fig. 1) and the gas from these two sources combines to reduce the overall density of the produced fluid column. A low-pressure gas, which must be injected high in the fluid column, can affect the density of the fluid only above the point that it is injected(Fig. 2). Therefore, high volumes of gas, injected high above the formation, are required to affect the pressure drawdown at the reservoir face. Like wise, a relatively small volume of gas injected near the depth of the reservoir can have a decided effect on the density of the fluid column above it and thereby result in a significant pressure drawdown at the reservoir, pressure drawdown at the reservoir, JPT p. 1305
- North America > United States > California > Carpinteria Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/29a > Maureen Field (0.99)
Abstract Gas lift has long been used as a petroleum industry vehicle for secondary artificial lift. Typically run in a conventional jointed tubing completion string or, more recently, in manufacturer installed spoolable systems utilizing continuous pipe; new applications utilizing modifications of existing equipment and processes have enabled "on-location" make up of coiled tubing conveyed gas lift strings and subsequent installation and/or extraction of same. This application was designed as an alternative to conventional gas lift systems as well as other means of artificial lift in order to effectively address mechanical problems due to wellbore conditions and expensive and frequent workover operations all dictated by marginal well economics from tail-end field reserves. Results from this completion method have been mechanically and economically successful for this application and field installed coiled tubing gas lift has been expanded to exploit other formation types.
- North America > United States > Texas > Newton County (0.29)
- North America > United States > Montana > Sheridan County (0.25)
Abstract The variable-gradient design-line method is a widely accepted procedure for spacing gas-lift valves (GLV's) in a continuous-flow gas-lift (GL) installation. Injection-pressure-operated (IPO) and production-pressure-operated (PPO) GLV's can be used in a variable gradient designed installation. The primary purpose of GLV's is to unload a well to the desired depth of gas injection. If the installation design is based on a constant surface injection-gas pressure (pio). the GLV's must be opened by an increase in the flowing-production pressure at valve depth (ppfD) rather than an increase in injection-gas pressure at valve depth (pioD). PPO, also called fluid-operated, valves are opened and closed by changes in ppfD. This paper outlines in detail the calculations for a variable-gradient continuous-flow installation design procedure based on a constant pio for spacing the unloading PPO valves. The valve spacing and port size selection includes performance characteristics of PPO GLV's. A simplified method for calculating the injection daily volumetric gas rate (qgsc) throughput of an unbalanced bellows type of PO valve on the basis of a change in ppfD and the valve bellows- assembly load rate (Blr) is given in the Appendix. Introduction Pressure-operated GLV's can be either IPO or PPO valves. There are major differences in GL installation design considerations for these two types of GLV's. The primary opening force for the IPO GLV is an increase in pioD, and an increase in ppfD provides the primary opening force for the PPO valve. Most published methods for designing continuous-flow GL installations are based on static force balance equations. The increase in pressure, or pressures 1 to stroke the valve stem is not considered in these design calculations. Design safety factors are included in the GLV mandrel spacing and opening pressure calculations to compensate for the lack of GLV injection qgsc throughput information. An understanding of the PPO GLV's injection qgsc throughput performance In relation to a changing PpfD is important for PPO GL installation design and GL operations analyses. P. 79