This paper provides insights on the design of downhole gas separators based on the laboratory study of various separator designs. A downhole gas separator, also known as a gas anchor, may be installed below the pump to separate free gas from the produced liquid. The free gas-produced downhole is usually separated through the casing-tubing annulus (the casing-tubing annulus acts as a natural gravity separator) while the liquid is produced through the tubing. However, inefficient gas anchor designs are widespread and an acceptable guide for their optimum design does not currently exist.Laboratory testing of downhole gas separators has been ongoing since January 2005 at The University of Texas at Austin Petroleum Production Engineering Facility (UTAPPEF) using an instrumented full-scale model of a wellbore and separator constructed with clear acrylic pipe to visualize the fluid mechanics of the separation process. An air and water mixture is injected through the well's perforations. The air and water flow rate measurements are used to measure and define a performance plot of each separator design. The separator designs tested differed in entry-port configuration, size of dip tube, and the relative position of the separator-fluid entry ports with respect to the well's perforations. Based on the results of the tests, a new separator design that includes the effect of centrifugal forces to separate the gas and liquid phases was developed.The results show that, for the conditions in the laboratory, 100% separation was achieved whenever the entry ports were located 1-to 2-feet (ft) below the bottom-most casing perforation thereby dispelling the predominant industry-held opinion that more distance is required betweent the separator-fluid entry ports and the bottom-most casing perforation. Similarly, laboratory results equally show that an optimum dip tube length of 5.5 ft is sufficient for the optimal separation of free gas from the produced liquid by the separator. This clearly runs contrary to the accepted industry practice, as many industry models employed for the estimation of dip-tube length were found to over-estimate the dip-tube length, and this subsequently results in the undesirable increased pressure drop across the separator. Lastly, the entry port geometry does not appear to have a significant impact on the separator performance as long as sufficient flow area is present. The efficiency of all gravity-driven separators was limited by the liquid velocity inside the separator annulus. When the liquid velocity inside the separator averaged approximately 6 in. per second or less, an almostto-complete gas separation was achieved. On the other hand, the centrifugal separator had a liquid capacity 70% greater than any of the gravity-driven, static-downhole gas separators.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWhen working in mature fields, one needs a lot of imagination because many times economic resources are limited. Workovers, that utilize proven and new technology may solve this problem. Using existing wells that already have casing, tubing, artificial lift systems and surface facilities is an excellent way to increase reserves and production with a small investment. Identifying the candidates for the workovers is the key to success.In 2005, 43 wells were worked over in the Texas County, Oklahoma area of the Hugoton and Panoma Fields, resulting in a production increase of 2,914 MSCFD for a total cost of only $1.6 MM. Payout of the program occurred in just 4.6 months, using a conservative gas price of only $3.89 per MSCF. The techniques involved fracture stimulation, mechanical wellbore cleanouts, artificial lift type changes and acidizing. A successful workover program should apply the fundamentals of science and engineering, coupled with field operations and geology. The screening methods developed may lead to further workover activity with anticipated reserve and production increases in other areas of the Hugoton and Panoma Fields.

Due to the complexity and cost of stimulating horizontal multilateral wells in an offshore environment, all aspects of this project type must be considered prior to project implementation. Utilizing all technical disciplines to understand the reservoir characteristics and select intervention candidates greatly influences the chance of success for any project. During 2006–2008, 39 wells (19 producers, 17 water injectors and 3 gas injectors) were stimulated in the Shuaiba reservoir in Idd El Shargi North Dome Field, offshore Qatar, resulting in production increases as high as 50% and injection increases as high as 100% in some wells. The wells were stimulated by rigless coiled tubing. A new tool that allows coiled tubing to enter each lateral in multilateral wells was used for these projects. This successful acid stimulation workover program utilized the fundamentals of engineering, geology, geophysics, and petrophysics and applied them with field operations. The screening methods developed led to further workover activity and new drilling development with anticipated reserve and production increases. Introduction Idd El Shargi North Dome (ISND) field was discovered in 1960. ISND is located approximately 55 miles east of Doha, Qatar. ISND is a shallow offshore field, located in water depths ranging between 100 and 150 feet (Fig 1). ISND production is dominated by the Jurassic Arab and Cretaceous Shuaiba carbonate formations, although Jurassic Uwainat (carbonate) and Cretaceous Nahr Umr (clastic) are also developed. Production began in 1964, and Occidental Petroleum of Qatar Ltd. (OPQL) entered into a production sharing agreement with the State of Qatar to operate and develop the field in 1994. The Shuaiba reservoir is the largest of the ISND reservoirs in terms of oil in place but the recovery factor is very low. The Shuaiba reservoir is a densely fractured and highly faulted, low permeability carbonate reservoir. Various well configurations such as single lateral horizontals and multilateral horizontal completions have been used to develop this reservoir. A liftboat unit was contracted in 2006 for data acquisition and rigless stimulation. The successful stimulation campaign explained in this paper is the result of utilizing all technical disciplines to understand the reservoir characteristics for selecting underperforming candidates and designing the stimulation. In this paper, an actual field example is used to show how candidate wells can be identified and how the intervention design can be prepared utilizing a multidisciplinary team effort (geophysicists, geologists, petrophysicists, reservoir and operations engineers). In addition, the paper will explain one technology that can be used to stimulate horizontal multilateral wells without a drilling/workover rig. The methodology described in this paper can be applied to any field that has horizontal and multilateral wells, especially those fields containing naturally fractured carbonate reservoirs. Reservoir Description The Shuaiba formation is extensively faulted and fractured due to domal uplift and regional tectonic events. Shuaiba is a high porosity and low permeability reservoir where large and small scale fracturing has created enhanced permeability regions and pathways in an otherwise tight matrix reservoir. The Shuaiba formation consists of four layers: Shuaiba A, B, C and D and is bounded by two shales: Nahr Umr (above) and Hawar (below). Shale barriers vertically separate the layers, although communication occurs through fractures and faults. Shuaiba A, B, and D are most productive and Shuaiba A is the most prolific, containing the highest percentage of the total Shuaiba oil in place. The Hawar Shale located below Shuaiba D closes the Shuaiba sequence. Immediately below the Hawar Shale is the Kharaib series of carbonate layers. These productive intervals are similar in nature to the Shuaiba D and are in pressure communication with the Shuaiba layers through fractures and faults.

Summary Downhole gas separators are often the most inefficient part of a sucker-rodpump system. This paper presents laboratory data on the performance of fivedifferent gas-separator designs. Only continuous flow was studied. Field dataare presented on two of the designs. The field data indicate that success orfailure of the gas separator is dependent upon the fluids and wellborepressures as well as the mechanical design of the gas separator. Successful andunsuccessful examples of gas-separator performance in the field are shown alongwith field fluid data properties. Introduction Gas interference in downhole plunger pumps has been studied for severalyears. The first comprehensive analysis was presented by Clegg (1963), whodeveloped a theoretical analysis of separator performance and set some of therules of thumb that are still in use today. These guidelines were applied insubsequent studies that developed practical methods for matching separatorperformance to specific well producing conditions (Campbell and Brimhall 1989;Dottore 1994; Ryan 1992). Poor performance of downhole rod pumps and problemswith progressing cavity (PC) pump operation owing to gas prompted theundertaking of laboratory experimental studies by Robles and Podio (1999) thatincluded visual observation of separator-fluid mechanics using a full-scaleplexiglass wellbore and a conventional rod pump. The problem of downhole gasseparation recently has become of further interest in relation to dewateringlow-pressure gas wells and operating coalbed-methane wells. Patterson andLeonard (2003) studied some different downhole gas-separation designs forcoalbed-methane operations in Wyoming. In these designs, the inlet to the gasseparators was smaller than normal and, along with some baffles, was thought toallow gas to vent from inside the gas separator, obtaining good gas separationin the field installation. While field installations provide the ultimatevalidation of gas-separator performance, it is extremely difficult to isolatethe influence of each design parameter. It was these installations thatprompted the laboratory study of the gas-separator geometry to determinewhether the rules-of-thumb used by the industry for gas-separator design werevalid (Lisigurski 2004). One of the most common sources of inefficiency in oilwell pumpinginstallations (rod pumps and ESPs of PC pumps alike) is gas interference, whichprevents the pump from delivering liquid at the design rate. Although this is awell-known effect, there seems to be limited understanding of the mechanismsthat control gas interference, and this often results in the use of remedies, such as installing downhole gas separators, that are ineffective or evendetrimental to the pumping-system performance. The objectives of this paper are to give a clearer insight on the mechanismsof gas interference in pumping wells and to present the results of recentlaboratory and field studies on the flow characteristics and performance ofsome downhole gas separators. In a pumping installation, one of the principal functions of the wellbore isto operate as a two-phase (gas/liquid) separator so that the pump (which isdesigned to pump liquid) can operate efficiently. Although this concept appearsto be obvious, it seems to be totally ignored by most operators when theydesign completions and install hardware (gas anchors and the like) to combatthe effects of gas interference. In these applications, the separation of gas from liquid is achieved throughgravity separation without the introduction of other mechanisms (centrifugalforces, nozzles, etc.). Thus, the difference in density between the gas andliquid is the main driving force to be used for separation. This also impliesthat forces that oppose the effect of gravity, such as viscous drag caused byhigh fluid velocity and turbulence, will be detrimental to the separationprocess. Thus, high velocity of liquid or gas should be avoided ifpossible.