Gas Lift Operations Research Articles

Determining the Most Profitable Gas Injection Pressure for a Gas Lift Installation (includes associated papers 13539 and 13546 )

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 inefficient gas lift operations and failure to 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 lift installation to determine the most profitable operating system.

Evaluation of Valve Port Size, Surface Chokes and Fluid Fall-Back in Intermittent Gas-Lift Installations

Abstract By utilizing an 8,000-ft experimental field well equipped with 10 gaslift valves and 10 Maihak pressure recorders, gas-lift tests were conducted with port sizes ranging from 5/16 through 1 in. The well was equipped to provide accurate means of measuring surface pressures, temperatures, quantity of injection gas and fluid production. The tests were conducted in 2 3/8-in. OD tubing, and the well was making 95 per cent water. A complete evaluation of gas-lift-valve port sizes shows the relationship of per cent recovery, gas-liquid ratios, minimum pressure created at the operating valve and horsepower requirements for each port. The length of time necessary for the fluid in the tubing to reach equilibrium conditions after each cycle was recorded. Fall-back of fluid at depths of 477, 969, 1,685, 2,493 and 4,290 ft was noted. For each port size, pressure loads of 250, 300, 350, 400 and 450 psi were lifted with a valve operating at approximately 550 psi at 6,000 ft. Gas-liquid ratios for each load were varied from excess gas to a gas volume per cycle whereby the load failed to reach the surface. Numerous curves are presented in evaluating the accumulated data. The results show a 1-in. port to be the most efficient under all conditions. The production of intermittent liquid slugs against different-sized surface chokes was evaluated. These tests were conducted from a 7/16-in. ported valve at 4,072 ft. Tests indicate that, when possible, a 3/4-in. in diameter choke or larger should be used at the surface. Introduction In the past few years most of the advancement in gas-lift operations has been made in continuous-flow operations. Yet, it is estimated that at least 70 per cent of the wells on gas lift in the United States are of the intermittent type. Since the term "slug flow" is sometimes used in both intermittent- and continuous-flow operations, it would be well to distinguish between the two types of flow. Continuous-flow gas lift is defined as a method whereby the fluids are produced at a continuous rate at the surface. This generally requires a continuous injection of gas through a surface choke; however, various other control devices sometimes are installed to eliminate freezing, to shut-off gas during natural flow periods, etc. The actual flow of fluids in the tubing may be of the slug type (one of many flow patterns known to exist in continuous flow). Intermittent flow is defined as a method of gas lift whereby the liquid is produced in separate piston-type slugs. Perhaps this type of flow could best be thought of as a ballistic type flow where the liquid leaves bottom as a piston, propelled by a slug of expanding gas. Gas generally is injected through some type of control at the surface at predetermined intervals. However, the valve may have characteristics whereby gas can be injected through a small choke and still result in a ballistic-type flow. The purpose of the experimental work was to evaluate the most efficient port size to be used on the operating valve for the ballistic type of lift and, in addition, to establish the importance of utilizing a surface choke large enough to allow slugs to be produced without detrimental effects. This work is part of a comprehensive study of both intermittent and continuous-flow gas lift, representing a joint project conducted by the Ohio Oil Co., the Sun Oil Co., Otis Engineering Corp. and The U. of Texas. The problem of evaluating port sizes has been given little previous attention. Some work undoubtedly has been done which has not been published to date. Some tests were conducted when the wireline, mechanically-opened valve (Nixon) first came on the market. This valve was capable of utilizing full tubing area as its port size. It is known that this was a very efficient valve, but to the authors' knowledge the results of tests have never been published. EXPERIMENTAL EQUIPMENT These tests were conducted on an actual field well, the Ohio-Sun Unit Well No. 2-E, in the North Markham- North Bay City field, Matagorda County, Tex. The well incorporated 2 3/8-in. OD tubing and produced 95 per cent water. Since the running of equipment was to be quite elaborate and expensive, a well was selected in which both intermittent- and continuous- flow tests could be conducted. This particular well was capable of producing in excess of 1,000 B/D of liquid (95 per cent salt water), yet with a 3/64-in. in diameter bottom-hole choke, production was controlled to 82 B/D. Most of the intermittent tests were conducted at this low rate. Figs. 1 and 2 show all the surface and downhole equipment. As can be seen, every attempt was made to insure that ample equipment was available for reliable testing procedures. Fig. 1 shows the surface testing equipment. JPT P. 315^

Performance of an Alternate Repressuring and Producing Project

Introduction A reservoir which is being subjected to an alternate repressuring and producing mechanism is the Rincon field Frio D–7 sand lens located 16 miles northeast of Rio Grande City, Starr County, Tex., along the Vicksburg flexure and the southwestern edge of the Rio Grande embayment. As in most Frio fields in this area, numerous sand lenses are encountered and, in this instance, throughout 12 distinct strata. The subject reservoir, the D–7, was the seventh reservoir to be outlined in the D stratum. The D–7 reservoir shown in Fig. 1 is a 38 acre-ft, sand lens located at a subsea depth of - 3,230 ft on the west side of the Rincon structure. Only two wells, T. B. Slick HB No. 90 and 91, were drilled into the sand lens, encountering 12 and 16 ft of sand, respectively. Although Well No. 91 was cored, no analysis was obtained; therefore, 23 per cent porosity and an irreducible water saturation of 24 per cent, the average figures in Frio D sands in this area, were used. A fluid analysis is not available from the D–7 reservoir. Therefore, an analysis from the D–5 reservoir (sand) in proximity to the subject reservoir was used to obtain the assumed formation volume factor of 1.172 at 1,523 psi and 155°F. Primary Performance History In June, 1941, the T. B. Slick HB No. 91, the only well that produced during primary operations, was completed in the D–7 reservoir and potentialed for 166 B/D, no water, flowing through a 1 1/64 in. choke with a GOR of 311 cu ft/bbl, and tubing pressure of 320 psi. Flow valves were installed in Aug., 1944; in Feb., 1946, the well was shut in due to low productivity. The flow valves were repaired in Dec., 1947, and the well was re-potentialed for 45 B/D. The well then produced until Feb. 21, 1950, at which time it was permanently shut in due to low productivity. The primary production history of the reservoir is illustrated in Fig. 2. Cumulative production at the end of the primary life was 80,820 bbl of oil, no water and 159,872 Mcf of gas. Bottom-hole pressures taken in 1948, 1950 and 1951 are thought to be in error and probably represent gas-lift system pressures caused by a leaking valve. The gas-oil ratio increased from 311 to 52,800 cu ft/bbl, but the accuracy of the erratic gas-oil ratio history after 1946 is questionable and can probably be contributed to the inherent industry-wide problem of measuring injection gas during intermittent gas-lift operations.

Producing Wells on Casing Flow - An Analysis of Flowing Pressure Gradients

Published in Petroleum Transactions, AIME, Volume 213, 1958, pages 202–206. Abstract The Cretaceous limestone wells of the Mara/Maracaibo Dist. of Venezuela are extremely prolific producers. To maintain production on cessation of natural flow, large scale gas-lift operations were commenced involving high production rates on casing flow. For the design of these gas-lift installations it was essential to have some knowledge of the pressure gradients involved in casing flow, so that the required injection pressures optimum gas injection rates, etc., could be forecast. This paper presents a method of calculating these annular pressure gradients. Basically the method makes use of an energy balance equation coupled with an empirical energy lab factor derived from field data. The calculations have been put in a form suitable for "punch card-type" calculating machines. A set of gradient curves for Mara/Maracaibo conditions covering flow rates up to 12,000 B/D, and GOR's of 500 to 2,000 cu ft/bbl is presented. From these (curves the flowing BHP can be predicted from surface data and the vertical flow performance under varying conditions of gas injection can be estimated. The method has been applied to La Paz and Mara gas-lift operations for over three years and has given consistently accurate results. Introduction The Cretaceous limestone fields of the Mara/Maracaibo area in Venezuela are characterized by the presence Of widely distributed fissure systems. Under these conditions individual wells frequently have extremely high potentials and such wells are generally flowed on the casing-tubing annulus in order to reduce the pressure loss in vertical flow. To maintain production on cessation of natural flow, an extensive gas-lift system was planned. As a first approach to this gas-lift design problem, an attempt was made to construct a set of empirical flowing gradient curves from the available subsurface pressure data. Such a method has been used successfully for tubing-flow conditions in California by Gilbert. Unfortunately, the empirical construction of casing-flow gradient curves presents additional difficulties, as pressure bombs cannot be run in the casing-tubing annulus against high rates of flow. Thus, the full flowing gradients cannot be defined by actual measurement and the best that can be done is to obtain spot pressures at the tubing shoe. Under these conditions a vast accumulation of BHP data is required to construct a set of gradients.

Theoretical and Practical Aspects of Free Piston Operation

Abstract Theory of operation of the free piston as well as practical limits of the device in prolonged flowing life of wells producing from volumetric type reservoirs are discussed. Reservoir behavior and the gas expansion work formulae are used to exhibit utility of free piston in prolonging natural flowing life. Examples are exhibited to show actual performance of the tool in West Texas. Investment and operating costs of the free piston are compared with those required for other artificial lift methods. A nomograph which may be used in determining adaptability of the tool is exhibited. Use of the free piston in intermittent gas lift operations is briefly mentioned. Introduction The basic idea of interposing in the tubing of a producing well of a solid interface, between gas and liquid phases of the produced fluid, to increase the efficiency of the lift is not new. In the original plunger lift the interface used was a solid critical diameter piston. The increase of efficiency of lift was obtained by better utilization of the energy of the compressed gas, either of the formation gas or of compressed gas supplied to the well from an outside source. Reduction to a minimum of the channeling of gas through the liquid phase and the filling back of the oil and water to be produced resulted in better utilization of the energy. This type of installation required a perfectly cylindrical and uniform diameter tubing to permit the travel of the tool. Several years ago a free piston was developed which incorporated an expanding rubber element for sealing against the tubing wall and was therefore applicable in any conventional tubing string. Fig. 1 shows the piston. The piston is manufactured in two types: Type 1, which is designed for installations using an outside source of gas; and Type 2, which is designed for those installations which use the well's own energy as a driving mechanism. This paper will consider only the latter type of free piston which has had considerable success in operations in West Texas, with the performance of the Type 1 only very briefly mentioned later in the text.