Wichita Falls, TX, United States
Wichita Falls, TX, United States

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Sutton R.P.,Marathon Oil | Sutton R.P.,Reservoir Performance Group | Cox S.A.,Marathon Oil | Lea J.F.,PLTech LLC | Rowlan O.L.,Echometer Company
SPE Production and Operations | Year: 2010

Critical velocity calculations in the form of charts or simple equations are frequently used by field personnel to evaluate a gas well's flowing conditions to determine if the well is experiencing liquid-loading problems. Literature detailing the critical velocity necessary to keep a gas well unloaded suggests using the conditions at the top of the well as an evaluation point. This is convenient for personnel conducting the evaluation because wellhead pressure and temperature data are readily available. A number of situations exist where the use of the wellhead as the evaluation point can lead to erroneous conclusions. The most obvious situation occurs with a change in geometry downhole when a tapered tubing string is run in a well or when the tubing is set above the perforations. In these instances a more robust evaluation results from using conditions at the bottom of the well and the downhole tubing geometry. Other conditions exist where the use of downhole conditions provides a better evaluation point. The assumptions used in the development of the standard, simplified form of the critical velocity equations and charts may not be appropriate for downhole application. In these cases, the fundamental equations must be used. The calculation of critical velocity requires knowledge of pressure, temperature, produced fluids, and pressure/volume/temperature (PVT) properties. The determination of critical rate requires the same properties with the addition of pipe diameter. The required PVT properties, including surface tension and density for both the gas and liquid phases, are reviewed. Correlations to calculate water-gas surface tension were found to have excessive error, so a new, more accurate method is presented. This paper provides recommendations for the use of a surface or a downhole evaluation point is more appropriate for the determination of the minimum critical gas velocity in a well. Copyright © 2010 Society of Petroleum Engineers.


Rowlan O.L.,Echometer Company | McCoy J.,Echometer Company | Lea J.,PLTech LLC | Nadkrynechny R.,T RAM Canada Inc. | Cepuch C.,T RAM Canada Inc.
SPE Production and Operations Symposium, Proceedings | Year: 2013

Plunger fall velocities for various plungers have been measured in many different wells in the field and measured in a large scale well simulator. A new theoretical plunger fall velocity model has been developed. This model equates plunger fall velocity to be inversely proportional to a constant multiplied by the square root of the density of the gas the plunger falls through. The measured fall velocity at a specific pressure and temperature is used to calibrate the model, and then the model can be used to calculate fall velocity at other conditions for the same plunger or used to show how changing a feature like plunger weight can impact fall velocity. The model's predicted fall velocity for different types of plungers will be compared with measured fall velocities. A large scale plunger lift well simulator was used to determine plunger fall behavior in clear PVC tubing through compressed air and through gas free water. The performance of 36 different types and metallurgies of plungers were measured. Both in the field and at the well simulator an acoustic instrument was effectively used to accurately measure plunger fall velocity. All plungers have the same general trend of fall velocity; where the plunger fall velocity is fast at low pressure and slows at higher pressure. Construction features of plungers and well conditions impacting plunger fall velocities will be highlighted. Using published fall velocities to determine the shut-in time period for a particular plunger type but may not be accurate for a well, because well pressure significantly impacts plunger fall velocity. The knowledge of how various parameters impact plunger fall velocity allows the operator to determine if the plunger has reached the bottom of the tubing by the end of the shut-in period and then optimize the plunger lifted well using the shortest possible shut-in time to maximize liquid and gas production. Copyright 2013, Society of Petroleum Engineers.


Rowlan O.L.,Echometer Company | McCoy J.N.,Echometer Company | Podio A.L.,University of Texas at Austin
Journal of Canadian Petroleum Technology | Year: 2011

Three pump-intake-pressure (PIP) calculation methods available for wells artificially lifted with sucker rods are discussed in detail in this paper. The values of PIP obtained from acoustic fluid-level measurements in wells with moderate pump submergence can yield PIP estimates that agree with those of pump fluid-load analysis. If PIPs determined using these methods do not agree, then the operator must review the data quality and may reduce the deviation by adjusting certain parameters affecting the calculations. Field data for a significant group of wells are used to compare the PIP results of the three methods. The results show that the PIP computed using the maximum and minimum pump dynamometer loads usually calculates a PIP that is too low, while the PIPs computed using the valve test loads are usually too high. Recommendations are presented for quality control of the computed values. Copyright © 2011.


McCoy J.N.,Echometer Company | Podio A.L.,University of Texas at Austin | Rowlan O.L.,Echometer Company | Becker D.,Echometer Company
SPE Production and Operations | Year: 2015

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. Copyright © 2015 Society of Petroleum Engineers.


McCoy J.N.,Echometer Company | Rowlan O.L.,Echometer Company | Taylor C.A.,Echometer Company | Podio A.L.,University of Texas at Austin
SPE Production and Operations | Year: 2015

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. Copyright © 2015 Society of Petroleum Engineers.


McCoy J.N.,Echometer Co | Becker D.,Echometer Co | Capps K.,Capsher Technology | Podio A.L.,University of Texas | Rowlan O.L.,Echometer Co
SPE Production and Operations Symposium, Proceedings | Year: 2013

Understanding the performance and behavior of a sucker rod pumping system can be a difficult and time consuming task but is a requirement to optimize the performance of a large number of wells by efficiently identifying and correcting production problems. Streamlined and optimized acquisition of dynamometer, fluid level and pressure data has been achieved using fourth generation wireless instrumentation that is quickly installed at the surface and is controlled by a user friendly graphical application that requires minimum user intervention. During a well monitoring session the data records are acquired seamlessly without interruption of the operator's workflow. Results are displayed in real time including quantitative visualizations of the downhole rod pump operation, plunger motion, valve action and fluid flow. Pump intake and discharge pressures are computed and displayed in synchronization with plunger movement, pump liquid fillage, traveling valve operation and standing valve operation. The pump animation is computed by the solution of the wave equation using the polished rod load and acceleration data stream and presented simultaneously with the corresponding fluid distribution and pressures in the wellbore obtained from the acoustic fluid level survey. The user can see, at a glance, the total performance of the well and lift system without having to devote much time to interpret a conventional dynagraph or fluid level record. Evaluation of the performance of the well and artificial lift system is performed at the well so that reports and recommendations for optimization can be issued immediately. This paper presents the physics and the practical aspects of the application of these advanced analysis and well monitoring tools. Case studies are presented showing analysis on a variety of wells. Copyright 2013, Society of Petroleum Engineers.


McCoy J.N.,Echometer Company | Rowlan O.L.,Echometer Company | Taylor C.A.,Echometer Company | Podio A.L.,University of Texas
Society of Petroleum Engineers - SPE/AAPG/SEG Unconventional Resources Technology Conference | Year: 2016

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 back pressure against the formation that 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 times, 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 indicates that liquid exists above the tubing anchor when 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. Field testing using automated fluid level measurement equipment to perform fluid depression tests verifies that a gaseous liquid column exists above the tubing anchor and a gas column exists below the tubing anchor in some wells. This field data was acquired on several wells and is shown to verify the above analysis of the well's performance. This fluid distribution condition is not general known. Locating the tubing anchor below the pump prevents this condition and will improve production in these wells. Copyright 2014, Unconventional Resources Technology Conference (URTeC).


Mccoy J.N.,Echometer Company | Podio A.L.,University of Texas | Rowlan O.L.,Echometer Company | Becker D.,Echometer Company
SPE Production and Operations Symposium, Proceedings | Year: 2013

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. Copyright 2013, Society of Petroleum Engineers.


Taylor C.,Echometer Company | Rowlan L.,Echometer Company | McCoy J.,Echometer Company
Society of Petroleum Engineers - SPE Western North American and Rocky Mountain Joint Meeting | Year: 2014

The distance to the fluid level provides beneficial information throughout the life of a gas-lift well. From the initial unloading of the well, to maintaining production, and even into troubleshooting the well, the location of the fluid level plays a crucial role in understanding the well's performance. Some of the most valuable fluid level shots occur during the unloading process, when the fluid level is compared to the gas injection depth. Fluid levels can be used to help determine whether a problem is occurring within the wellbore or due to equipment malfunction. A quick surface measurement determines valves below the fluid level are not injecting gas. Finding holes in the tubing string and location of any restrictions in the tubing or casing help identify problems impacting production. During a workover, monitoring the fluid levels of a well filled with kill fluid ensures sufficient hydrostatic pressure is maintained against the formation. In gas-lift wells without a packer, producing bottomhole pressures can be accurately measured using an acoustic fluid level instrument. Bottomhole pressure information is useful in designing and operating gas-lift installations and measuring overall producing efficiency1. Examples of fluid level shots on gas-lifted wells will be used to demonstrate these concepts. Acoustic fluid levels acquired on gas-lift wells provide a low cost, direct method to observe the well and benefit the operator through knowledge of the well's producing conditions. Copyright 2014, Society of Petroleum Engineers.


Rowlan O.L.,Echometer Company | McCoy J.N.,Echometer Company
SPE Production and Operations Symposium, Proceedings | Year: 2015

Both the surface and the pump dynamometer cards are used to analyze sucker rod-pumped wells. Diagnostic pump card loads are calculated using the wave equation from the measured surface dynamometer load and position. The pump plunger fluid load, Fo, applied to the bottom of the rod string is directly related to difference in pressure across the plunger over the plunger area. Typical pump card loads plot near zero load when the traveling valve, TV, is open during the down stroke. When the standing valve, SV, is open during the upstroke the pump card loads should plot near fluid load determined using the pump intake pressure from a fluid level measurement. An expected fluid load maximum load line can be calculated by setting the pump intake pressure equal to zero. The diagnostic pump card loads can be compared to these three reference load lines 1) Zero line, 2) Fo line from Fluid Level and 3) Maximum Fluid Load, Fo max, line. Certain downhole pump problems can be identified based on the location of the pump card loads with respect to these three load reference lines. If no load transfers between the TV and SV, then the diagnostic pump card becomes a flat shape. The location of the flat pump card can be used to determine if there is 1) the traveling valve could be stuck open, 2) a deep sucker rod string part occurs near the pump depth 3) the rods could be parted at a depth above the pump, 4) tubing could be dry, or 5) the SV could be stuck open. If the pump intake pressure is low then the pump card load on the upstroke should plot near the Fo max reference load line. At a glance the location of the upstroke pump card loads can be used to estimate the pump intake pressure. Excessive downhole friction is indicated by the pump card displaying down stroke loads considerably below zero and upstroke loads substantially above the Fo from Fluid Level reference lines. Incomplete pump fillage is often associated with a "pumped-off well", meaning that the pump displacement exceeds the production capacity of the reservoir. There are other causes of partial liquid pump Tillage: gas interference or the presence of a flow restriction in the annulus or excessive pressure drop at the pump intake. This paper describes analysis methods used to compare the pump card diagnostic loads to the reference load lines. The analysis of the data can be used to identify the reason for lack of pump action or the cause of incomplete pump fillage. Several example field datasets will combine dynamometer and fluid level records to identify the source of the problem and presents recommendations for possible solutions. Use of downhole pump load and position is the basis of pump card diagnostic analysis and troubleshooting. Copyright 2015, Society of Petroleum Engineers.

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