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SPE Artificial Lift Conference and Exhibition - Americas
Abstract All-metal progressing cavity pumps (AMPCPs) are frequently used in oil and gas applications to produce high-temperature fluids to surface. Unfortunately, due to the interaction of the metal rotor on the metal stator, AMPCPs can exhibit accelerated wear during operation that results in decreasing pump volumetric efficiency over the pump's life. While decreasing pump volumetric efficiency can be a result of pump wear, it can also be due to changes in downhole operating conditions, such as increasing pump differential pressure or decreasing pump speed. For this reason, when evaluating the state or condition of an AMPCP, the use of pump efficiency alone may be a misleading or imperfect indicator. In this work, a proposed condition indicator is presented that estimates the wear experienced by an AMPCP at any given time in operation and takes into consideration the potential effects of downhole operating conditions. The proposed condition indicator can also be extrapolated into the future and used to estimate the potential remaining useful life (RUL) of an AMPCP by considering the current pump condition and the estimated future downhole operating conditions. An example is provided to demonstrate how to calculate the condition indicator of an AMPCP and several case studies are presented that illustrate the effects of varying downhole operating conditions and various workover activities, such as rotor re-landing and rotor swaps, on the condition of an AMPCP and its potential RUL. The proposed AMPCP condition indicator enables operators to estimate the condition of an AMPCP over time, which allows for better pump selection based on the anticipated operating decisions, better operating practices to maximize system performance, as well as improved planning of upcoming workovers based on more accurate AMPCP RUL estimates.
Abstract Electric submersible pumps (ESPs) are currently being tested in the service company's newly built viscous lab testing loop; whereby, the viscous performance of each pump stage type is analyzed at multiple speeds and viscosities. This viscous lab testing loop is capable of speeds up to 70 Hz, 30,000 B/D of fluid, with a maximum of 500 HP, and can manage fluid viscosities up to 2,500 cP. Four pumps were tested at speeds ranging from 40 to 70 Hz, in 10 Hz intervals, and up to 2,500 cP fluid viscosity. The viscosity correction factors, for each operating speed and viscosity, were developed for each pump stage and compared with the stage-specific speed. The effects of viscosity and operating speed on flow, head, and horsepower were observed. An increase in viscosity deteriorates pump performance, while an increase in rotational speed reduces the rate of deterioration; therefore, increased operating speeds improve the performance of an ESP pump in viscous applications. Additionally, diameter and specific speed effects (a "dimensionless[DL1] " number for pump design criteria) on viscosity are being investigated as a design criterion. A correlation is being developed for the effects of the specific speed on the viscosity correction factors. The new correlation will help obtain viscosity correction factors for other pumps with different diameters, operating at different speeds and viscosities, based on the specific speed relationship. The service company's Research and Development department's viscosity testing program, its results, analysis, and new findings are discussed in this paper.
Abstract Jet lift has no moving components downhole, which makes it a higher reliability lift method for accelerating initial production from unconventional tight oil wells. The surface jet lift power fluid pump frequently becomes the primary limitation of overall system reliability and uptime. This paper will review several field case studies of novel wireless instrumentation being applied in combination with machine learning techniques to increase the runtime of multiplex plunger pumps and horizontal surface pumps used as power fluid pumps. Wireless instrumentation was installed on multiple wells to capture critical power fluid pump equipment health data (vibration, temperature, magnetic flux, etc.). This instrumentation was installed on all critical components of the surface pump system, and then combined with electrical and site instrumentation data connected to the pump's variable speed drive. The entire data feed was then captured through a local gateway and into a cloud data historian. The data was processed to establish an acceptable performance baseline. Equipment health models were created using machine learning techniques to compare the real-time data feed against reliability prediction algorithms. The equipment health status was then used to evaluate time-based maintenance versus condition-based maintenance, improving overall system uptime performance. The field case studies indicated that overall jet lift system reliability is improved by carefully monitoring, modeling, and predicting power fluid pump performance. When combined with condition-based maintenance and field response protocols, overall jet lift system uptime can be improved. Safety risks are also reduced due to less frequent site visits. Most machine learning and AI papers focus on applying new analytics methods to existing instrumentation and data. Maximizing the benefit of analytics requires more robust data and an integrated field instrumentation approach. This paper will present the increased benefit of developing and deploying additional instrumentation to capture equipment health data designed to increase the performance of cloud analytics.
Abstract The patented hydraulically regulated progressing cavity pump (HRPCP) has been tested previously in the oilfield, but its range of application is being expanded. The HRPCP can be used in any well where a PCP would be installed and provides added protection in cases where significant free gas may be present. It is as effective as a standard PCP in pumping high viscosity fluids or fluids with high solids content, or both. It retains its effectiveness as a pump even when no gas is present, although its primary benefit is the increase in PCP run-life when there is free gas present at the pump intake. The present study is to evaluate the performance of the HRPCP in new applications around the world. Previous publications on the HRPCP have looked at installations in Argentina, Venezuela, and Kuwait. There are now installations in coal seam gas (CSG) in Queensland, Australia, gassy oil wells in Colombia, and heavy oil wells in the Lloydminster area of Canada, and in wells in the newer operations in the Clearwater formation near Slave Lake in Alberta, Canada. In Canada in particular, there have been 27 installations in thirteen fields by six oil companies at the time this paper was prepared. In Colombia, the HRPCPs were installed in new wells that were expected to produce high gas volumes while still producing some sand. In the Australian CSG wells, operators wanted to land the pumps higher in the well to avoid solids problems, knowing that this would result in higher gas volume fraction at the pump intake, so the HRPCP was chosen. In the Canadian heavy oil areas, there can be a higher GOR in many wells than there was in the past, so the gas fraction at the pump intake can now be a larger factor in PCP run-life than in the past. In some of the Canadian wells, the performance data of the previous installation is available for a direct comparison. Overall, the run-life of the HRPCP has been excellent in comparison to either expectations or to the run-life of previous PCPs in the same wells or fields. In one example well, the previous PCP suffered a significant drop in efficiency (from 60% to 10%) after 90 days. The HRPCP that followed it has been running at 70% efficiency for over 180 days (and still going). In Colombia, the operator saw reduced load on the pump due to the "gas lift" effect from the gas going through the pump and up the tubing, while exceeding expectations for run-life.
- South America (1.00)
- North America > Canada > Alberta (0.54)
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.69)
- Geology > Rock Type > Sedimentary Rock > Organic-Rich Rock > Coal (0.48)
Abstract Carbon dioxide (CO2) is commonly used for enhanced oil recovery (EOR) in the Permian Basin and is gaining interest for Carbon Capture, Utilization & Storage. A study was conducted to develop candidate selection criteria, pilot test the design, and optimize CO2 gas lift to stabilize production on intermittently flowing wells in one of these EOR fields. The initial CO2 gas lift design was installed in 2019 using a capillary string, downhole check valve, gas lift mandrel, and packer. A 34-day bottomhole pressure and temperature survey was evaluated to assess the success of the pilot and improve the equipment design for future installations. The phase changes of CO2 were accounted for when evaluating the pilot, modeling gas lift, and improving equipment design. Carbon dioxide is a complex fluid at the bottomhole pressures (BHP) and temperatures (BHT) observed during the pilot. These pressures and temperatures were plotted on the CO2 phase diagram, which showed phase changes between vapor and liquid at higher gas lift injection rates. Further analysis revealed the CO2 changed phase from a liquid to a vapor across the downhole check valve. The Joule-Thompson (JT) effect across the check valve at the tubing entry point dropped the temperature of the produced fluids so much that the CO2 changed phase from a vapor back to a liquid. This increased the hydrostatic pressure and therefore, the bottomhole flowing pressure. These CO2 phase changes in the tubing occurred in cycles comprising five distinct stages: (1) BHT cooling forced CO2 from the vapor to liquid phase and increased BHP; (2) BHT remained fairly steady as BHP increased due to liquid loading; (3) BHT started warming at a faster rate as BHP rose due to the decreasing pressure drop across the downhole check valve; (4) the tubing unloaded as CO2 flashed in a chain reaction down the tubing, resulting in an influx of warmer reservoir fluid; and (5) BHT remained steady as BHP decreased and the annular packer fluid restarted the cooling process. Results from this initial pilot were used successfully to optimize CO2 gas lift for subsequent installations. CO2 gas lift can be an effective artificial lift method to stabilize production if the equipment is designed correctly to maximize the CO2 gas fraction at the tubing entry point. A poorly designed CO2 gas lift installation may result in unstable production from liquid loading events caused by the cyclic JT effect. CO2 gas lift is a valuable artificial lift method to reduce failure frequency and operating costs in EOR fields with readily available CO2.
- 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)
- (23 more...)
Abstract Fiberglass rods are mainly used to overcome the design limitations of rod pump equipment when additional lift capacity is required. Economic analyses for new installations or repair jobs must consider the life span of fiberglass rods. This study evaluates the cost-effectiveness of fiberglass rod applications by reviewing their life spans in the Permian Basin. The objective of this project was to build a stress fatigue diagram to help minimize expenses by maximizing the effective life of fiberglass rods. In theory, this diagram would define the allowable stress range that could be applied to fiberglass rods without causing excessive failures. Each data point would consist of one fiberglass rod failure, and all calculations would be performed over the age of the taper, from initial installation to failure. These operating limits would then be applied to field applications. The industry's rule of thumb for the "end of life" for fiberglass rods is 30-40 million rod reversals. However, most failures occurred before the rods reached one-third of their life expectancy, even though the fiberglass rods were operated well within the recommended stress ranges provided by the manufacturers. There was a positive relationship between average fiberglass taper failure frequency and average peak polished rod stress. Failures mainly occurred in the steel connection in the pin. Therefore, failures were not due to tensile stress fatigue in the fiberglass body. Failure frequency was so high in some fields that upsizing the pumping unit made more economic sense than installing a fiberglass taper. The recommendations from this project were to: (1) understand connection failures better through improved root cause failure analysis (RCFA) data collection and manufacturer involvement; (2) reassess and improve operational conditions at failure, such as rod pump design, pump off setpoints, and pump fillage; (3) evaluate switching to a 100% metal string with an upsized pumping unit or installing a different artificial lift method if failure frequency is not reduced by operational changes; and (4) re-evaluate rod string design criteria to maximize value, as current designs are based on tensile loading in the body of the top rod, but actual failures were not due to tensile stress fatigue in the body. Significant cost savings can be achieved if the average life span can be increased to the industry standard of 30-40 million rod reversals. More work needs to be done to understand connection failures.
- North America > United States > Texas (0.71)
- North America > United States > New Mexico (0.61)
- 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...)
Abstract Horizontal wells have brought significant improvements in production of unconventional reservoirs. However, one of the main debates in completion optimization lies on the effects of horizontal well geometry throughout a well's life. On the other hand, gas lift installations are becoming widespread to leverage the depletion in pressure and flow rate. Transient multiphase simulation allows physics-based modeling of flow performance in horizontal wells without or with gas lift application. The objective of this work is to use these simulations and provide a qualitative analysis of well geometry effects on slugging and production of horizontal wells. This study uses OLGA as a transient multiphase simulator to mimic a horizontal well's production over 36-hour time periods. The well produces through a 2-7/8″ ID tubing with MD of 10000 and TVD ranging from 4900 ft to 5100 ft, depending on the lateral geometry. The lateral section has a deviation angle range of 88-92°, with three geometries simulated, including toe-up, toe-down and horizontal. For each geometry, two cases are simulated: one without any undulations and one with random undulations along the lateral section. A realistic decline curve equation is used to estimate the decline in reservoir pressure throughout the well's life and simulate its production for 6 years, including early life with higher rates and late life of the depleted well. Gas lift is also installed late life to analyze its impacts on flow. The simulation results offer valuable insight into well geometry effects throughout a well's life. At early life, slugging is minimal and production rates are close for all the geometries, with simulations favoring the toe-up well by a small margin. However, the geometry effects increase significantly as the well depletes. Slugging becomes more severe in almost all toe-up and horizontal cases, causing large fluctuations in pressure and reduction in total production. Undulations in toe-up help reduce the slugging severity and slightly improve the production. Gas lift proves to help reduce the back pressure and slugging severity downstream of the valve, and significantly improve production. The study of well geometry and its impacts on production design remains to be limited. Therefore, this study is a unique effort to provide a guideline and optimize well configuration and artificial lift design.
- North America > United States > Texas (0.94)
- North America > Canada (0.68)
Abstract Bellows are mechanical devices used to compensate linear, thermal, or angular movement/expansion. Said bellows can be manufactured in different shapes, sizes, using different materials. One typical example of bellows application is in pipelines to compensate for thermal expansion between solid points. In oil and gas industry, among other applications, bellows are used in gas lift valves as a slidable seal between Nitrogen charged in valve dome section and injection pressure. Currently, only two nominal bellow sizes are used in gas lift application, one Inch and one and a half Inch. Examples of gas lift valves using one-and three-quarter Inch were manufactured but are not widely used. However, as manufactured bellows having very thin walls are not well suited for pressures higher than 200 PSI, depending on bellow size, shape and material used. To withstand much higher pressures bellows are being crimped, method that compresses bellow to shorter length which increases bellow overall mechanical toughness. In addition, bellows in gas lift valves must be pressure balanced inside and outside as much as possible to withstand high pressure up to 2500 PSI. By design bellows used in typical gas lift valves feature internal seal that is engaged once valve is in fully open position and bellow is expanded trapping "noncompressible" fluid usually silicone oil of different density. Nitrogen in gas lift valve is in direct contact with silicone oil and penetrates/dissolves into oil in form of bubbles. Being so called permanent gas Nitrogen never liquifies and always remain in gaseous state at any pressure no matter how high. This renders so called "noncompressible" fluid compressible and it does not prevent bellow damage when exposed to extremely high injection pressures. This theory used for decades in oil and gas industry is wrong resulting in premature bellow failures. This paper analyses existing gas lift designs and offers solution for problems specified herein.
New Mechanism of Sand Management Above ESPs: Cases Study in Colombia
Delgado, Anderson (Gran Tierra Energy) | Espinosa, Jorge (Gran Tierra Energy) | Hernandez, Maria (Gran Tierra Energy) | Gonzalez, Gustavo (Odessa Separator Inc) | Guanacas, Luis (Odessa Separator Inc) | Aya, William (Sonoma) | Perdomo, Juan (Sonoma)
Abstract One of the most expensive artificial lift systems in the oil industry is the Electric Submersible Pump (ESP) system, hence the unavoidable need of extending the run life of wells that have installed this system. Following the need of extending the run life, a sand regulator has been designed to protect the pump during shutdowns, and it has been incorporated into traditional sand control configurations to offer extensive protection above and below the pump. This paper will explain the mechanism of the sand regulator as well as the benefit of installing this system alone above the pump or complemented with a sand control system below the pump. The candidate wells to this integrated solution were selected from MMV (Middle Magdalena Valley) and Putumayo Basins, in Colombia. The wells had sand problems history and it was necessary to review pump designs, pulling reports and sensor parameters. Well conditions such as production, tubing size, and particle size distribution were analyzed to build the best design for every single well. In the design the geometry of the well was assessed to accommodate the cable and CT (Capillary tube) line downhole. The ADN Field in Colombia is characterized by heavy oil production (API between 13-18°), with fluid production between 1,000-2,000 BFPD, with a viscosity of 270 - 3090 cP @ 122°F, water cuts oscillating depending on the waterflooding effect (Between 1% to 95%) and high fine sand production (200 – 24,000 ppm). The CH Field wells produce between 1,000 – 6,000 BFPD, with API between 17-20°, high water cuts (> 77%) and a high sand production between 100 – 3,000 ppm. The wells selected had other type of sand control and management systems and were highly affected by frequent shutdowns. The Sand Regulator design was installed in 20 wells and was compared with the performance achieved using traditional sand control solutions. After the installation, production has remained stable in all the wells applied, allowing to reduce the PIP of the well of up to 400 psi. Less current consumption has been observed after each shutdown in all the wells, extending the run life of some wells up to double the average. Sensor parameters were analyzed after each pump restart to determine how difficult it was to restart operation after shutdowns. Compared to the tools installed above the ESP, this sand regulator allows flushing operation through it with flow ranges from 0.5 to 5 bpm. In addition, the unconventional design of this tool has opened the door to a new concept of ESP protection that works in wells with light or heavy oil and can be refurbished or inspected completely without cutting the tool.
- South America > Colombia (0.81)
- North America > United States > Texas > Dawson County (0.24)
Is It Possible to Run at High Speed Rotation, Above 3600 RPM, Asynchronous Electrical Submersible System? Myth, or Reality
Escobar, Carlos (Geopark) | Valencia, Victor (Geopark) | Castro, Jhon (Geopark) | León, Carlos (Alkhorayef Petroleum) | Pérez, Laura (Alkhorayef Petroleum) | Serrano, Juan (Alkhorayef Petroleum) | Ariza, Iván (Alkhorayef Petroleum)
Abstract Over the years, Electro-Submersible Pumps have been considered one of the main Artificial Lift Methods in different fields of the world due to their versatility in handling different well fluids and wide ranges of flow production. However, in many cases, it is not possible to reach the maximum potential of a well due to the perception of avoiding operating the Asynchronous Motors of the ESP system above 3600 RPM because it may induce failures. During the operation of ESP systems, situations may occur during which it may be necessary to operate the motor above the standard frequency 50/60 Hz (3000/3600 RPM) and take advantage of the maximum potential of the well without requiring an immediate intervention. These situations include but are not limited to well productivity index differing from the expected, loss of mechanical transmission in some of the system components, or decrease in efficiency due to wear associated with equipment operation. In the ESP industry there is a design practice of operating frequencies no higher than 60 Hz (3600 RPM) to avoid possible equipment failures associated with rotational instability, high temperatures or poor lubrication in the internal components due to greater friction at higher speeds. The recommended practices or international standards do not have an operating speed limit reference apart from the restrictions that can normally occur in the system, so there is uncertainty in the operating limits of these systems. The main objective of this paper is to verify or disprove the theory of the high speed rotation in 500-series ESPs with Asynchronous Motors (standard technology) with a specific number of wells that were operated at speeds above 4000 RPM.
- North America > United States > Texas (0.46)
- South America > Colombia (0.46)
- Asia (0.46)
- South America > Colombia > Casanare Department > Llanos Basin > Block LLA-34 (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salym Field > Verkhne Salymskoye Field > Vadelypskoye Field > Zapadno Salymskoyeskoye Field (0.99)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug > West Siberian Basin > Central Basin > Salym Field > Verkhne Salymskoye Field > Salymskoye Field > Zapadno Salymskoyeskoye Field (0.99)
- (4 more...)