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Summary Modern completion techniques have greatly increased the production-rate capability of wells. Many wells have the potential to produce more liquid and gas, but the use of tubing anchors in certain wellbore locations chokes the gas flow up the casing and results in increased backpressure against the formation, which restricts production from the well. A gaseous liquid column can form above the tubing anchor and cause high pressure in the gas below the tubing anchor that restricts the liquid and gas flow from the reservoir. Often, low pump fillage and low production rates are blamed on a poor gas separator, when actually the separator is operating efficiently and is separating the liquid from the gas. In the condition described, all of the liquid in the wellbore below the tubing anchor falls to the pump and is being removed by the pump. The problem is that high pressure in the gas column below the tubing anchor is restricting production from the well. Additional production is available if the high pressure that is restricting production from the formation is removed. The accumulation of a gaseous liquid column above the tubing anchor when constant low pump fillage is observed indicates that liquid exists above the tubing anchor whereas only free gas exists from the tubing anchor down to the pump. Limited liquid production falls down the casing wall, while the casing annulus is almost completely filled with gas if the pump is set below the formation (McCoy et al. 2013). Field testing with automated fluid-level-measurement equipment to perform liquid-depression tests verifies that a gaseous liquid column exists (Rowlan et al. 2008) above the tubing anchor and a gas column exists below the tubing anchor in wells with high fluid levels, with low pump fillage, and with the tubing anchor located above the pump. These field data were acquired on several wells and are shown to verify the preceding analysis of the well's performance. This fluid-distribution condition is not generally known. Locating the tubing anchor below the pump prevents this condition and will improve production in these wells.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (24 more...)
Summary Advances in horizontal drilling and large fracturing technology have resulted in wells that produce larger volumes of oil and gas than have been common domestically. Artificially lifting large volumes of oil and associated gas to the surface has always been a problem because of the difficulty of separating liquid from large volumes of gas downhole, especially in rod-pumped wells. This paper describes a separation technique that uses a packing element to divert the formation fluids through the separator and into the casing annulus at the top of the separator, above the pump inlet at the bottom of the separator, so that the liquids and gas can separate by gravity. The pump seating nipple is located at the bottom of the separator so that the pressure drop is less in the liquids moving from the casing annulus to the pump intake. Better pump fillage is obtained with the technique of setting the pump intake at the bottom of the separator rather than above the long separator, as show by the field data. This paper also describes a quantitative technique for evaluating the effectiveness of downhole gas separators. Often, the evaluation of separator performance is based only on pump fillage and the total gas production from the well, instead of a comparison of the liquid fillage in the pump in relation to the percentage of liquid that exists in the casing annulus surrounding the pump.
Abstract Advances in horizontal drilling and large fracturing technology have resulted in many more wells that produce larger volumes of oil than have been common domestically. Artificially lifting large volumes of oil and associated gas to the surface has always been a problem because of the difficulty of separating downhole oil that is to be lifted to the surface from large volumes of gas especially in rod pumped wells. Many downhole gas separators are inefficient, and the percentage of liquid in the pump is actually less than the percentage of liquid in the fluids in the casing annulus surrounding the gas separator. This paper describes techniques for evaluating the effectiveness of downhole gas separators. Often times, the evaluation of a separator's performance is based on pump fillage and the total gas production from the well instead of the amount of gas present in the gaseous liquid column that exists in the casing annulus surrounding the pump. This paper also describes a separation technique that diverts the formation fluids into the casing annulus above the pump inlet so that the liquids and gas can separate by gravity. A seating nipple is positioned within inches of the liquids that exist in the casing annulus surrounding the gas separator to reduce the pressure drop so that gas is not released from the oil that flows from the casing annulus into the pump chamber. If the pump seating nipple is positioned above the gas separator fluid exit ports, a pressure drop in the liquids entering the pump occurs and gas will be released into the pump chamber. Also, if the conduit or tube from the liquid in the casing annulus to the pump inlet is restrictive to flow, an excessive pressure drop occurs because of the high velocities associated with the pump plunger upward movement which often approaches 80-100 inches per second on high pump capacity wells. The separator design can be used with a conventional packer or a special pack-off assembly consisting of elastomer rings on a tube positioned between the separator and the tubing anchor below the separator. The pressure drop across the separator is generally less than 10 psi so flexible elastomer rings can be used instead of a high pressure packer. The separator is generally used with a tubing anchor, and the tubing anchor should be positioned immediately below the separator instead of above the separator because field data indicates that the tubing anchor can cause an accumulation of gas below the tubing anchor and considerable liquid accumulation above the tubing anchor. A recent complicating factor that must be considered when evaluating gas separator systems is the recent use of high clearance plungers in the pump. Large plunger clearances for sand problems are common in some areas that result in pump leakage of 50 % of the pump capacity, so the pump appears to be full or almost full when actually the liquid in the pump is circulated liquid that is bypassing the plunger. Field data has been measured and obtained where the pump chamber is full, but the production in the tank is negligible. The operator may think the separator is acting efficiently when the high pump fillage results from plunger leakage and not good separator performance. The paper describes gas separation techniques and presents field data on several types of downhole gas separators.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
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.
Abstract Downhole gas separators are often the most inefficient part of a sucker rod pump system.This paper presents laboratory data on the performance of five different gas separator designs. Only continuous flow was studied. Field data is presented on two of the designs.The field data indicates that success or failure of the gas separator is dependent upon the fluids and wellbore pressures as well as the mechanical design of the gas separator.Successful and unsuccessful examples of gas separator performance in the field are shown along with field fluid data properties. Introduction Patterson[1] studied some different down-hole gas separation designs for coal bed methane operations in Wyoming.In these designs the inlet to the gas separators were smaller than normally used and along with some baffles, thought to allow gas to vent from inside the gas separator, obtained good gas separation in the field installation. While field installations provide the ultimate validation of gas separator performance, it is extremely difficult to isolate the influence of each design parameter. It was these installations which prompted the laboratory study of the gas separator geometry to understand if the "rules-of-thumb" used by the industry for gas separator design were valid. One of the most common sources of inefficiency in oil well pumping installations (rod pumps, ESPs of PC pumps alike) is gas interference, which prevents the pump from delivering liquid at the design rate. Although this is a well known effect, there seems to be limited understanding of the mechanisms that control gas interference and this often results in the use of remedies, such as installing downhole gas separators, that are ineffective or even detrimental to the pumping system performance. The objectives of this paper are to give a clearer insight on the mechanisms of gas interference in pumping wells and to present the results of recent laboratory and field studies on the flow characteristics and performance of some downhole gas separators. In a pumping installation, one of the principal functions of the wellbore is to operate as a two-phase (gas-liquid) separator so that the pump (which is designed to pump liquid) can operate efficiently. Although this concept appears to be obvious, it seems to be totally ignored by most operators when they design completions and install hardware (gas anchors and the like) to combat the effects of gas interference. In these applications, the separation of gas from liquid is achieved through GRAVITY separation without the introduction of other mechanisms (centrifugal forces, nozzles, etc.). Thus, the difference in density between the gas and liquid is the main driving force to be used for separation. This also implies that forces that oppose the effect of gravity, such as viscous drag caused by high fluid velocity and turbulence, will be detrimental to the separation process. Thus, high velocity of liquid or gas should be avoided if possible. The Pumping Wellbore as an Efficient Gas-Liquid Separator The preferred pumping installation for maximum pump efficiency requires installing the pump intake BELOW the lowest point of fluid entry into the wellbore and requires having an open casing-tubing annulus from the bottom to the wellhead. This configuration is shown in Figure 1A. Gas and liquid enter the wellbore through the perforations and liquid flows to the bottom of the well under the action of gravity. The lighter gas bubbles rise through the liquid forming a gaseous liquid column, from the bottom of the perforated interval to the fluid level, then gas flows through the casing-tubing annulus to the wellhead where it exits to the flow line. Practically 100% liquid accumulates at the bottom of the well and enters the pump intake to be discharged by the pump into the tubing. This completion is similar to the surface facility vertical two-phase separator shown in Figure 1B. To be equivalent both the x-sectional area for flow diameter to length ratios would have to be the same. The gas-liquid mixture enters the vessel about two-thirds up the vessel wall. The gas outlet is at the top of the vessel; Liquid falls to the bottom and accumulates in the "quieting chamber" of the vessel where it flows to the pump intake through the liquid outlet.Proper operation of the separator requires that the liquid retention time be sufficient for most of the gas bubbles to rise to the gas/liquid interface and that the gas velocity be low enough for most of the liquid droplets to fall to the gas-liquid interface. These are the two criteria used for correctly sizing the separator to meet the flowing requirements. The unusual characteristics of this "equivalent separator" are that:It would have to be built with 4 to 7 inch diameter pipe It would be at least 30 feet tall It would not have liquid level controls The capacity of a 2-phase separator is defined in terms of liquid and gas capacity as a function of operating pressure and gas and liquid densities