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Humphreys, C. R. (Occidental Petroleum Corp.) | Vangolen, B. N. (Occidental Petroleum Corp.) | Allison, A. P. (Occidental Petroleum Corp.) | Yin, D. (Occidental Petroleum Corp.) | Yicon, C. (Occidental Petroleum Corp.)
The performance of artificial lift systems on horizontal wells is greatly influenced by both the volume of gas produced and the tendency for gas slugging. With a sucker rod pump (SRP) system, this behaviour leads to gas interference at the pump, reducing system efficiency and equipment run life. With an electric submersible pump (ESP), gas slugs can cause cycling of the ESP, which may significantly shorten its run life. A trial project was launched to evaluate the performance of two tailpipe systems that could be applied to both forms of artificial lift to achieve the following goals:
Reduce the frequency and magnitude of slugging behaviour seen at the pump,
Reduce the flowing bottomhole pressure without having to land pumps past the kick off point (KOP), and
Improve separation of free gas from the produced fluid before it reached the pump intake.
Two tailpipe systems were tested in a number of wells using both SRPs and one ESP for lift. The systems differ in both separator design and packer location. The first uses a conventional packer-style gas separator with a reduced inner diameter (ID) tailpipe extending below the separator and past the KOP. The second uses a specialty cyclonic separator with a reduced ID tailpipe, and the packer is located at the lower end of the tailpipe.
Some of these installations are outfitted with downhole gauges (DHGs) measuring pressure and temperature at several points along the tailpipe. The DHGs recorded pressure at the tailpipe inlet, tailpipe outlet, pump intake pressure, and pump discharge pressure. This surveillance package allowed for real-time monitoring of the performance of both the tailpipe and the artificial lift system, while also providing data for modelling the flow regime through the tailpipe. The modelling results were used to forecast long-term performance of the system as the well production declines over time.
Results from the field trial show the performance of each system from a variety of standpoints: changes in flowing bottomhole pressure, flowing behaviour through the tailpipe, separation effectiveness, and changes in production. Challenges were noted, and potential solutions or courses of investigation are proposed. Conclusions were drawn regarding the overall effectiveness of the concept, as well as the relative effectiveness of the two systems.
We examined the differences between two tailpipe systems regarding the isolation location, whether at the top or bottom of the tailpipe, to aid us in designing future systems. A comparison of the two separators was attempted, and various operational challenges are discussed so as to improve the design, installation, startup, and operation of these systems.
Electric Submersible Pump (ESP) is a key artificial lift technology to the petroleum industry. Worldwide installations of ESPs are in the range of 130,000 units, contributing to about 60% of the total worldwide oil production. An ESP is made up of hundreds of components integrated together to perform the lifting function. Materials in these components belong to several categories including metals, ceramics, polymers, and others. A good understanding of these materials and vigilant selection for a specific application are critical to the reliability and run life of an ESP system. This paper presents an overview of two classes of materials used in ESP systems: metallic and ceramic materials. A subsequent paper is planned to cover all other categories of materials. The intent is to provide a reference for ESP field application engineers who are responsible for ESP design, component selection, equipment longevity and production optimization.
The information compiled in this paper is a result of extensive literature review. It covers materials used in the motor, protector, pump, and cable (Sensor, packer, Y-tool, diverter valve, surface components of variable speed drives and transformer not included). For each class of materials, it identifies relevant material properties and discusses suitable application conditions.
Annulus pressure at depth is a primary requirement of any gas lift design. There are several methods of determining annulus pressure including reference to a monograph, density equation used to full depth with average pressure and temperature, and density equation used in small depth increments with average temperature and pressure within the increment. The choice of which method to use comes with limitations on the accuracy of the predicted pressure at depth.
When the annulus pressure at depth is calculated by use of a computer program, the choice of which correlation to use to model the critical properties of the gas and which compressibility factor correlation also affects the accuracy of the calculated pressure at depth.
As a gas lift well transitions from a geothermal temperature profile to a flowing temperature profile during the unloading and lifting process, the annulus pressure at depth will decrease even though the surface injection pressure remains unchanged.
Finally, the change in annulus pressure during the unloading process is governed by the volume of gas present in the annulus. A decrease in pressure is due to a reduction in gas volume. Traditional design techniques ignore this reality and substitute a theory of valve performance to explain annulus pressure changes during unloading. This simplified analogy of valve performance made it easy to design a gas lift well but incurred errors and misconceptions about how the annulus pressure changes during unloading.
This paper will address all of the above issues and provide advice on which method of annulus pressure prediction at depth is most appropriate for specific conditions, advise on the accuracy of the combination of different critical properties and compressibility correlations, offer an alternative design technique to account for changing annulus temperature during the unloading process, and finally, provide guidelines on how to accurately and realistically model the changes in annulus pressure during the unloading process.
Foam lift has proven to be an effective method to mitigate liquid loading in unconventional resource (UCR) wells. Water-soluble surfactants are commonly used when liquid loading is mainly caused by formation water. There is a larger uncertainty involving the efficacy of water-soluble surfactant at water cuts below 80%. Therefore, oil-soluble surfactants are recommended. However, high oil-soluble surfactant price causes a significant increment in Opex, which can make the well production uneconomical.
Flow loop tests have been carried out in a closed-loop 2″ ID facility to emulate continuous backside foam injection. The oil condensate is emulated using a low density commercial isoparaffin oil, while tap water and compressed air are used instead of formation water and natural gas. The experiments are conducted at water cut values that range between 70% and 100% for surfactant concentration of 250 ppm. The foamer surfactant is a commercial water-soluble surfactant that is commonly used in oil field applications. The liquid loading onset is primary parameter obtained from each test through video and data analysis. Other parameters such as flow pattern and pressure gradient are also reported.
The experimental results show that liquid loading initiates at gas flow rates around 252 MSCFD for air-water flow in a 2-in. ID tubing. Adding the condensate fraction with a fixed total liquid rate and no surfactant slightly increases the critical gas rate. After surfactant injection, the reduction in critical gas flow rate is approximately 40% for most water cuts except the case of 70% water cut, where the oil presence seems to inhibit the surfactant effectiveness. Visual observations at this case show a significant reduction in generated foam, and relatively similar flow pattern transitions as the case of no surfactant. These results demonstrate that water-soluble surfactants are very effective in mitigating liquid loading at high water cuts, but their effectiveness reduces as water cut decreases. This causes an increase in the critical gas flow rate despite foam injection.
Currently, most operators aim to produce from condensate-rich shale in order to increase profit. The results of this study offer a first look in the following two issues. First, the effect of oil in liquid loading is investigated and the effectiveness of surfactant at different water cuts is evaluated. Second, the results can be used to design cost effective treatments based on water-soluble surfactants. Most literature about the effect of water cut on surfactant injection effectiveness is based on small scale lab. This experimental study is one of the few flow loop tests to investigate the effect of oil on the onset of liquid loading with surfactant.
Projected gas production is a critical variable in well planning, and the downhole tools chosen for gas mitigation are vital to production performance. With sucker rod pumps, inefficiencies due to gas presence can reduce the time between pulls and negatively affect production rates. The packer-style gas separator (PSGS) has higher-liquid-volume capabilities than "poor-boy" gas anchor style tools. Packer-style gas separators have become an industry-recognized tool used to increase production in gaseous fluids on rod-lift wells by using volume restrictions to create pressure changes then filtering the free and entrained gases from liquids.
This study examines the operational parameters involved in the use of a PSGS in downhole gas separation. A flow loop laboratory test was conducted to evaluate the separator's qualitative properties. Additionally, two separate case studies were analyzed to understand the impacts of downhole gas separation on production rates, pump run time, and pump fillage.
The laboratory experiments used a transparent model in the flow loop for a visual analysis of the separation occurring during operation. A water-nitrogen solution of varying concentrations was run through the separator to examine drawdown parameters during inflow. The results showed that at 95% liquid capacity, the nitrogen inflow was successfully contained within the modeled tubing-casing annulus, preventing entry of gas into the simulated pump intake.
Two case studies were recorded in separate geographical regions to verify operational success. In south Texas, an operator successfully mitigated gas from five high-GLR wells. The PSGS in each well successfully separated 300 to 500 Mcf per day of gas from tubing production inflow. As a result, the total fluids output increased by up to 200%. In west Texas, an operator used the separator in nine different wells. On average, the fluid production increased by 61%, pump fillage increased by 11%, and pump run time increased by 33%.
Overall, through laboratory and field testing, the PSGS has proven its ability to handle a wide range of downhole conditions. By improving downhole gas separation before fluid enters the pump, gas interference effects are mitigated and overall rod lift system efficiency is enhanced.
Plungerlift was installed in conjunction with gaslift to improve efficiency in delifiquification of unconventional gas wells. The dual artificial lift methods were implemented to more aggressively reduce bottom-hole pressure, in order to increase production in Barnett Shale wells.
Wells are selected based on a series of metrics, including gas-liquid ratio, fluid production, casing pressure and differential between casing and line pressure. The basics of both plunger-assisted gaslift (PAGL) and gas-assisted plungerlift (GAPL) both utilize injection gas and a plunger to optimize the well. Plunger-assisted gaslift is continuous injection and continuous plungerlift. PAGL is implemented on higher gas and fluid producers. These wells require the addition of injection gas to raise the critical velocity needed to lift both the plunger and the fluid of the well. GAPL is intermittent injection and conventional plungerlift. It is implemented on lower gas and fluid producers. Gas is only injected during certain phases of the plunger cycle to supplement the wellbore inflow and successfully lift fluid and plunger to surface.
This presentation will describe the process and results of installing PAGL and GAPL on specific case studies in the Barnett Shale. Historical data, including production, pressures and producing methods will be presented, to compare the results of prior lift methods to those of PAGL or GAPL. By implementing PAGL and GAPL, bottom-hole pressure was successfully lowered and production increased. A secondary benefit is the reduced quantity of gaslift that results in lower operating costs and a more-effective use of horsepower. The results of over-injection in unconventional wells will also be notated.
This presentation will detail the benefits and results of dual artificial lift that can efficiently and economically add value to a field.
Gas/liquid ratios (GLRs) typically increase later in the life of a sucker rod-pumped well, and unconventional reservoirs may have high GLRs from the beginning of production. How to handle that gas production is important for sucker rod pumps, as the efficiency is reduced when gas enters the pump. A project was undertaken to quantify several methods used to handle gas production with sucker rod pumps and the effectiveness of each.
This project focused on three areas of design or operation intended to improve gas handling:
Gas separator design: The sizing of downhole gas separators was reviewed, and steps were taken to match the pumping system with the proper separator. In cases where the separator was not pulled, the pump displacement was adjusted to ensure it was within the capacity of the existing separator. Where there was an opportunity to replace the separator, the design was modified to ensure the separator capacity matched the expected well production.
Variable speed drives: Horizontal wells do not provide consistent inflow, but rather exhibit slugging behavior as portions of the lateral load up with liquid or gas. This makes pump-off control difficult with conventional rod pump controllers, which stop the pump completely when there is a lack of fluid at the pump. The performance of variable speed drives was studied to determine if continuous operation while adjusting the speed to accommodate slugging would improve production.
Backpressure valves: Backpressure has been used as a method to improve the performance of wells with gas interference, but the benefits have been questionable compared to the negative impacts on equipment loading. Wells with elevated tubing backpressure were identified, the backpressure was reduced to line pressure, and the impact on performance was monitored.
To maximize electrical submersible pump (ESP) uptime and production in North Kuwait's diverse reservoir conditions, it was necessary to combine variable speed drive (VSD) feedback control functionality with reservoir knowledge and real-time data and subsequently develop an operating strategy tailored to individual wells. The case studies in this paper show how well performance can be stabilized and production increased by incorporating motor current and downhole pressure into the VSD frequency control loop.
In North Kuwait fields, engineers studied wells with ESPs running in unstable condition or suffering frequent tripping due to underload or high temperature. Their ESP design datasheets, production test results, historical VSD running parameters, and downhole gauge data were used to calibrate pump and well performance models and identify the pump operating point. From these simulation results, the VSD feedback control loop function was optimized to minimize tripping and/or enhance stability, thereby increasing production.
The main causes of well instability and ESP downtime in North Kuwait are declining bottom hole flowing pressure and gas interference. The case studies illustrate how to select the appropriate VSD frequency feedback object function for each of these cases. For weak inflow, the VSD is configured to maintain constant intake pressure, especially where the intake pressure is less than 500 psia. For ESPs suffering from gas interference, constant current was implemented to avoid gas locking. The before and after results from the case study wells demonstrate the effectiveness of this technique for well stabilization and associated production increase. After the study, this method was implemented on 60 wells and resulted in a 21% reduction in the number of ESP trips over 6 months and an associated increase in uptime from 92% to 97%.
This case study describes a workflow that integrates ESP historical running data, reservoir knowledge, and VSD feedback control functions to increase well uptime by preventing ESP tripping. In addition, the workflow enhances ESP system operating stability and optimizes the reservoir drawdown, which offers the operator a viable option to achieve production objectives.
In rod-pumped systems, the locations to install rod guides along the rod are determined through the analysis of calculated side forces exerted on/by the rod string. The side forces are computed from axial forces in combination with information about the trajectory of the rod string in the well. Traditionally, the trajectory of the rod string is estimated from directional survey data, obtained by magnetic or gyroscopic surveys at typically 100ft reporting intervals. However, because the surveys are run in open hole, in casing, or in tubing, it is the trajectory of these structures that are described by the directional data. None of them are accurate representations of the actual trajectory of the rod string, implying that the resulting side forces may suffer from reduced accuracy, and therefore are not optimal for decisions on rod guide placement. Additionally, due to the low resolution survey data, local variations in the wellbore trajectory within the survey intervals, which may affect the forces on the rods, may be undetected.
In a previous paper we developed a method for analyzing the small-scale tortuosity of a wellbore from high-resolution (1ft) survey data. One important outcome of this analysis is the finding that high small-scale tortuosity substantially narrows the free passage through a wellbore or tubing. The narrowing is quantified in terms of the reduction in the effective diameter of a device that can be placed in the wellbore. In this paper, the technique has been extended for the calculation of points along the wellbore where the rod string is expected to make contact with the tubing. This is an important result by itself, indicating where rod guides may be needed along the rod string. With these points of contact, the trajectory, or shape of the rod within the production tubing is estimated. The use of this estimate instead of the traditional directional survey data in the calculations of side forces is expected to improve the accuracy of the results.
The technique has been applied to a number of field cases, and two are presented in this paper. The results show that the forces on the rod calculated from the proposed technique are similar to, and exhibit the same general trend as the forces calculated with conventional methods. However, there are some differences, due primarily to the use of the estimated shape of the rod string in the proposed method. The forces on the rod at the estimated points of contact of the rod and the tubing can be extracted and used for rod guide placement decisions.
By providing improved estimates of contact point locations and the forces acting between the rod and the tubing, the method may help to optimize the rod pumping system for producing wells. It may help to explain occurrences of pump failures, erosion of the production tubing by the rods, and other issues that are not fully understood. This may result in reduced failure rates, energy savings, and cost savings resulting from reduced workovers and production losses.
Gas lift operations in toe-down gas wells are usually dictated by convenience or knowledge based on previous experience. Parameters such as end of tubing location and packer placement are vital in determining efficacy of gas lift operations, alongside injection rate and injection location. The aim of this study is to quantify the effects of these parameters. The scope of this study is to provide guidelines to help assist design of gas lift systems for toe down gas wells.
A large scale experimental facility was constructed to study gas lift operations in toe-down gas wells. Air and water were used as test fluids, and the flow rates studied were those typically seen in toe down gas wells, resulting in slug flow being the dominant flow regime. Three end of tubing locations were studied, and in two of these locations the effect of a packer was quantified. Two different injection locations were studied as part of this study. Flow parameters such as pressure drop, holdup and slug characteristics were measured along the test facility.
Experimental results indicated that gas lift operations do not significantly affect the behavior of flow parameters such as holdup and pressure, upstream of the point of injection. The most significant effect of gas lift is observed to be a reduction of pressure drop fluctuations downstream of the point of injection. Packer placement also significantly affects gas lift performance, and it was observed that packered configurations are more efficient. Also, for a given end of tubing location, gas lift injection at the deepest point is observed to be the most effective in reducing pressure drop fluctuations.
This is the first experimental study conducted on the effect of end of tubing location and packer placement on gas lift operations on a large-scale test facility with field scale diameters for casing and tubing. Packer placement is currently dictated by mechanical concerns and depth limitations. This study addresses potential risks and benefits of running a packer as deep as possible, from a hydrodynamic standpoint.