Many McKittrick California wellbores are mature with a long reserve life. Original slotted liner gravel pack completions have eroded over time to pose a production threat. Sand enters the rod pumps and sticks the plungers. Additionally, conventional rod pumps on deep wells suffer more frequent rod parting events due to deviation and rod stretch, and CO2-mediated corrosion accelerates rod and tubing wear failures. The result is that rod pumps on this field's 3000+ feet deep, light oil sandstone wells have very poor reliability and require costly rig interventions to service. Enter the Cohelical-Axial Multiphase Pump (CHAMP) for ESP solution - a multiphase pump design to handle sand issues most centrifugal pumps cannot. Developed with assistance from Chevron Energy Technology Company through a joint industry project (JIP), the CHAMP-ESP is versatile to move high rate fluids with high sand/high gas/high viscosity content. This paper examines a case-study application to highlight the technical and economic challenges to keep these problematic old wells actively producing with the CHAMP-ESP concept. CHAMP and CHAMP-ESP are not trademarked names but rather acronyms created by the authors to facilitate understanding of the pump type and ESP system.

High-temperature electric submersible pumps (ESPs) are the most commonly used artificial lift method in steam-assisted gravity drainage (SAGD) wells. While conceptually the SAGD process should provide a low-viscosity single-phase flow to the ESP system, changing pressures and temperatures associated with well drawdown create opportunities for introduction of free gas, water vapor, or both, resulting in multiphase flow regimes. This can often lead to wellbore flow instability and ESP performance deterioration. An innovative approach to understanding ESP performance in multiphase flow conditions in SAGD production wells was developed by Shang, S. and Gomez-Bustamante, N. (2017) , using well-specific fluid PVT characteristics to create the produced mixture's phase envelope. This analytical approach is able to identify phase boundaries, determine gas-water vapor volume fraction (GWVF), and predict flow regimes as a function of surface and downhole flowing measurements. In this case study, the authors extend the modeling work done by Shang, S. and Gomez-Bustamante, N. (2017) with the objectives of constructing a wellbore model that includes the complex downhole completion, conducting transient analysis of the entire wellbore, analyzing slugging characteristics both upstream and downstream of the ESP, and ultimately providing operational recommendations to maximize well drawdown while maintaining wellbore stability.

Sizing electric submersible pumps (ESPs) for unconventional wells presents new challenges compared to traditional applications, typically conventional, vertical wells. These challenges are due to the highly dynamic, rapidly changing nature of unconventional wells compared to conventional wells. Traditional ESP sizing software is not structured to design for dynamic conditions, but rather a single point in time. The objective is to design an ESP tool fit for unconventional design applications. Because of the rapidly changing conditions of unconventional wells, it is difficult to balance the lifetime sizing needs of the equipment with needs of the equipment during peak demand. Changing flow rates, water cuts, pump intake pressure (PIP), and gas oil ratio (GOR) have a great effect on stage size, total dynamic head (TDH), and motor horsepower (HP) requirements at different points over time. The new design tool will allow the user to upload a well type curve and help chose a pump and motor combination by calculating different TDH and motor horsepower requirements for each day over the life of the well. Optimized ESP sizing will allow oil and gas operators to install one initial ESP at the completion of the well which lasts until production rates have declined to the conversion point of a lower rate form of artificial lift. This has significant cost savings implications both for capital and operational budgets, by avoiding overspending on oversized equipment upon the initial install of the wells, and greatly reduced the work of the operations team by eliminating workovers needed to downsize equipment. The use of this design tool allows much more rigorous reviews of vendor designs, to avoid over sizing equipment while still capturing high initial production rates during the early production life of the well. ESPs designed using the new design tool will be compared to historical ESP designs provided by the vendors on analogous wells. Production numbers, run life, and historical ESP data streams will be compared between wells designed using the old methodology vs the new design tool.

Electric submersible pump (ESP) systems have over many decades proven themselves as a reliable Industry leading lift system. However, there are limitations to the ESP lift system particularly with reliability and performance in high volume deep unconventional wells with steep decline curves and high amounts of free gas which present multiple challenges that require reliable solutions to enhance the performance and run life of the ESP system and increase overall production. This paper presents the "new innovative next thing" in artificial lift. A robust high volume, low speed positive displacement rotary gear pump (RGP) that has the ability to operate reliably throughout ranges untouched with centrifugal pumps, delivers optimal production and does so in a cost-effective manner in comparison to a conventional ESP system. The main challenge for long economical production is high decline rate – typically production rates drop 50-80% of initial rates after the first year. The primary reasons for such reservoir behavior: transient inflow effect, no pressure maintained and fracture deterioration. Producing a wide and flexible range of production rates with high efficiency is a significant challenge to artificial lift selection. With the Industry trending to reduce costs by drilling reduced ID horizontal wellbores with long lateral lengths, this poses a challenge particularly in integrating a life-time one artificial lift system design to capture both the high and low ends of the decline curves that can be handled by ESP systems particularly in confined wellbore architectures. This coupled with operational issues such as pump cavitation or gas locking, high motor operating temperatures, and abrasion/erosional issues due to excessive gas slugging and solids production led to the development of an innovative positive displacement pump. This paper describes the steps undertaken in designing, testing, and planning a pilot for a prototype rotary gear pump which replaces the centrifugal pump component of an ESP system while addressing all of the functional requirements for successful field implementation.

This paper summarizes the work of the exploratory phase of a Joint Industry Project (JIP) investigating operational instabilities and ‘no flow’ events observed in a large number of Steam Assisted Gravity Drainage (SAGD) wells produced with ESPs, where, while the ESP is operating, flow to surface suddenly stops. The impact of these events to the SAGD operations has included lost production due to downtime and reduced drawdown, additional stresses to the ESP due to operating without flow for extended periods and repeated shut-downs and restarts and some system failures. The primary objectives of this exploratory phase were to better understand the mechanisms and key factors responsible for these no flow events, to identify possible mitigation actions, which may be in the wellbore trajectory, ESP landing position, ESP system component designs, or operating practices. This work was structured as a series of progressive, inter-related tasks, using a combination of analytical models and Computational Fluid Dynamics (CFD), to systematically examine the components of an ESP completion and to narrow-in on the primary contributing factors. The approach was adopted in an effort to assess if the instabilities were due to flow conditions upstream of the ESP, past the ESP, through the intake or in the initial stages of the pump. For each step of the analysis, the output boundary conditions of an upstream analysis became the input boundary conditions of the corresponding downstream assessment. First, a combination of one-dimensional (1D) multiphase flow and multiphase CFD models were used to characterize the fluid conditions and flow behaviour in the lateral and heel of the well below the ESP. Second, flow past the ESP motor was examined using CFD models to examine the impact of motor heating on subcool reduction and steam vapour generation. CFD simulations were also used to examine fluid separation and flow into a bottom feeder ESP intake to assess the amount of non-condensable gas (NCG) entering the ESP and if the pressure drop through the intake was sufficient to cause significant steam vapour flashing. Finally, a representative SAGD ESP stage was analyzed using both a broad suite of analytical surge models to assess the stability of the pump given the gas-liquid fraction entering the pump, as well as CFD simulations of the rotating stage. The focus of the CFD assessment within the entrance and first stage of the pump was to determine whether vapour flashing was occurring within the ESP stage and the apparent impact on the stage’s ability to generate head. The results from this exploratory phase of the JIP indicated that vapour flashing within the ESP impeller due to insufficient required Net Positive Suction Head (NPSHr) appeared to be one of the dominant mechanisms causing no flow events, as opposed to NCG or steam entering the pump from the intake. Future work for this JIP includes validation of the CFD results using lab test data, further CFD simulations of other ESP stage designs and at a wider range of operating conditions, and examination of alternate ESP designs that may allow for production at lower subcool and lower NPSHr values.

Horizontal wells experience transient flow regimes throughout their long laterals. The average gas/liquid ratio (GLR) produced by a horizontal well may not overwhelm an ESP if the fluids travel in a steady stream. However, gas slugs commonly develop in the lateral section of a horizontal well, growing in size as they approach the heel of the well and move into the vertical section of the wellbore. A well with a pump intake pressure (PIP) of 500 psi at the ESP gauge may have plenty of fluid over the pump intake and still have problems with gas locking the pumps. Even with sophisticated gas handling pumps and gas lock-breaking control algorithms in the variable speed drive (VSD), the ESP still goes down with a gas locked pump. This paper covers a patent pending technology developed at EOG Resources' Production Technology Center that improves gas-liquid separation of fluids entering an ESP. The tool has been installed in wells with high GLRs, where ESP run times are lower than the field average, and has improved operational stability. This paper follows the development of the technology in the model wellbore at EOG's lab, the design and manufacturing of field trial separators, and the results of several field trials.

Caisson-ESP systems provide a cost-effective means of seafloor boosting. These systems are being applied in applications that requires the ESP to handle unusually higher gas fractions. The objective of this work is to investigate the gas-handling effectiveness of helicoaxial ESP stages used in combination with standard mixed flow pump stages. The results show that helicoaxial stages greatly extend the gas-handling capabilities of an ESP system and eliminate gas-lock over a wide range of conditions. It is well known that high gas fractions and viscous fluids degrade centrifugal pump performance. Additionally, gas locking occurs due to gas entrainment inside the pump causing operational problems. This study investigated the use of 4 helicoaxial pump stages at the entrance of a 48-stage ESP. Testing was performed at the Shell Gasmer Caisson-ESP Facility in Houston, Texas. This full-scale test loop can test ESP's over a wide range of conditions. The test matrix covered viscosities from 2 to 300 cp at different speeds, flow rates, intake pressures and gas volume fractions (GVF). Multiphase flow and viscosities affect the performance of the ESP pump system, degrading pump performance. The test results demonstrate that the high-flow helicoaxial pump can handle up to 73% GVF without gas lock. Pump performance improves at higher intake pressures and pump speeds with less pump degradation. In two-phase flow conditions, as viscosity increases, the pump degradation decreases thus improving gas-handling operations. A homogeneous model has a fairly good agreement with pump performance up to 30% GVF with minimal pump degradation. This work provides an important field-scale validation of the helicoaxial pump hydraulic performance at high GVF with high viscosity fluids. This has benefits to the deep-water industry, which is seeking more affordable seafloor boosting options.

The V-Pump is a radically new type of pump which has proven to deliver superior performance compared to conventional ESPs in conventional and unconventional wells. Unconventional wells producing at 75+% GVF (based on daily production figures), can often slug liquid followed by very high GVF fluid such that the pump must be capable of handling a very wide, indeed extreme range of fluid conditions. Different wells seem to cause different slug conditions, possibly due to the geometry of the horizontal section and hydraulic fracture network. The V-Pump has been able to work effectively throughout the GVF extremes which occur on such wells. The V-Pump has sand erosion resistance very much higher than previous pump technologies. The V-Pump is expected to be an outstanding pump for high viscosity fluids, with testing in flow loop up to 13,000cP, but has still not been deployed in a high viscosity well, expected soon. It is designed and flow loop tested as a SAGD pump. The V-Pump has operated with high percentage of sand both in flow loops and producing wells; the V-Pump can be used in unconventional wells with high sand concentration and high GVF. The development of this pump has taken a few years with a great deal of flow loop testing and field trial testing. This paper mentions some of the development work, flow loop testing, and case studies; the difficulties of replicating harsh field conditions in pump test flow loops, both the sand erosion loop and the multiphase loop.

ESP's are a technology that was adapted from water pumping in order to continue to produce high-rate, high-water cut wells with economic results. Using centrifugal pumps in wells that produce hydrocarbons creates the possibility, perhaps the inevitability, of centrifugal pumps that need to produce multiphase fluid, and originally this was a common limitation for their use. Gradually, the industry developed solutions to increase the capacity for ESP's to work in the presence of gas through technology (static gas separators, dynamic gas separators, and most recently multi-phase pump stages) and through simulations of ESP's in high-gas conditions to understand their behavior. The result is a set of historical concepts on the performance and behavior of ESP's with high-gas that gets passed down among generations of engineers who work for suppliers and producing companies. This paper's premise is that many of the beliefs about how ESP's operate in high-gas environments are mythological. They are learned early by engineers in the industry and accepted as true and unquestioned, even when presented with direct evidence that contradicts them. This paper will use conflicting examples to demonstrate that behavior is much more complex and unpredictable than previously considered. Perenco is an independent oil company whose strategy is to reinject life into mature oil assets. ESP's are a central part of Perenco's business because they offer an opportunity to boost flow rate for older wells with decreased reservoir pressure and high water cuts. Converting high-gas wells to ESP's has resulted in the opportunities for the examples in this paper.

To arrest production decline without infill drilling, one must maximize production from existing wells, typically by identifying wells with skin and increasing drawdowns on wells with good pressure support or lower water cut. This paper examines how high-frequency, high-resolution flow rate measurements on ESP wells can identify such opportunities without the need for buildups which cause production deferment. The application of this workflow was examined for wells in Egypt. To obtain flow rate measurements at frequencies greater than once an hour, without dedicating a test separator or multiphase flowmeter to each well, the method relied on real-time data to calculate liquid rate and water cut. The liquid flow rate calculation was based on the principle that the power absorbed by the pump is equal to that generated by the motor. Water cut was calculated by modelling the production tubing as a gradiometer. Analytical equations ensured that the physics were respected at all times, which yields greater repeatability and resolution than analogous methods based on correlations and artificial intelligence. The well analysis in Egypt demonstrated that the evolution of depletion and skin could be identified qualitatively using plots of rate-normalized differential pressure. These diagnostic plots are only possible with high-frequency and high-resolution flow rate measurements and could not be generated using traditional monthly production test data. The case studies also illustrated how frequency and resolution enabled real-time measurement of the impact of small changes in pump speed on both the reservoir inflow characteristic as well as production. This qualitative technique makes it possible to fine-tune production iteratively without the need for time-consuming simulation, which was nevertheless also conducted to quantify the changes in reservoir pressure and skin on the wells considered in this case study. Furthermore, with a water cut resolution of less than 1%, potential water coning can be identified rapidly, which allows the production operator to test small drawdown increases. Finally, this method also has the advantage that it can reduce the mobilization of testing equipment to the well site to measure the change in production, thereby minimizing and eliminating health, safety and environment (HSE) risks in remote locations while also optimizing the use of the available test packages. This novel use of real-time gauge data demonstrates how a cost-effective method can improve well testing quality and thereby identify production optimization opportunities, providing the means to arrest decline. This case study provided a proof of concept on specific wells, however fieldwide application is necessary to identify the wells with the highest production optimization potential because, typically, most of the gain is obtained from a minority of the wells in a given field.

This paper presents an engineering investigation on the impact of well trajectory on production performance of ESP-lifted shale wells. A representative set of field data was selected as the input data to model the shale well with an ESP installed. Based on these data, a comprehensive analysis of production performance from ESP-lifted shale wells was performed. These wells had the same or similar reservoir characteristics, but different well trajectories including relatively smooth and highly sinuous toe-up and toe-down well trajectories. A transient dynamic multiphase simulator was used to perform the engineering investigation by integrating ESP performance and wellbore models over the life of a shale well, evolving from initial steady natural flow production to late-life unsteady and slugging flow production. From the analysis, the well trajectory does not impact the well production performance of an ESP-lifted well. The slugging flow results in a dramatic gas volume fraction changing from 0 to up to 100% at the pump intake. The study combines multiphase transient modeling (for the specific well trajectory) with reservoir modeling and historic production data. The analysis includes models of the well behavior and instabilities that allow operators to evaluate the application of ESP systems considering well trajectory and optimize timing for installation and withdrawal.

This paper describes the steps taken in the planning, design, and field implementation of an enhanced artificial lift system to address the common challenges of conventional ESP installations. A set of case studies, in two basins, reviews the field installations and sequential optimization to achieve an improvement in ESP performance. Unconventional horizontal wells have the complexity of depth, temperature, fluid composition, and rapidly declining production rates. Most artificial lift systems struggle and inadequately cope with inconsistent slug flows from a horizontal wellbore, foamy fluids, damaging solids and gas interference. In ESPs, gas interference frequently overheats the motor resulting in excessive shut downs and/or premature failures. The root cause of gas interference is flow from the horizontal wellbore that tends to be sluggy with inconsistent mixtures of gas and liquid. A downhole flow conditioning artificial lift technology designed to smoothen and suppress slug flows prior to the ESP dramatically improved ESP performance. Field implementation revealed that the technology conditioned the flow and successfully reduced slug flow behaviour showing consistent rates and pump intake pressures. With the slug flow issue resolved, this revealed an unaddressed problem not previously noted with conventional ESP installations caused by liquid lifting in the small annular space adjacent the pump. With high enough gas rates, liquid lifting past the ESP can occur, starving the pump of liquid, overheating the motor, resulting in shutdowns. In initial field trials, this problem limited the ability to drawdown past 800 psi intake pressure. Subsequent field trials solved the problem by manipulating pump intake pressure or reducing equipment size for higher gas rate wells resulting in significantly lower pump intake pressures and improved ESP reliability. The paper describes consecutive cases that implement stepchange modifications to resolve both slug flows to the ESP and annular liquid lifting past ESPs. The optimized design resulted in an extended range of pump operability, improved reliability and enhanced control and reservoir management.

SPE Gulf Coast section Electrical Submersible Pump Workshop, 29 April - 1May, 2009, The Woodlands, Texas Abstract In the last 8 years, coiled-tubing-deployed ESP (CTDESP) systems have developed into a proven technology marrying the cost-effectiveness of coiled-tubing conveyance with the benefits of electrical submersible pumping(ESP) systems. Simultaneously, great strides have been made in the form of real-timemeasurement of reservoir and production data such as pressure, temperature, and flow rate, by means of permanent gauges placed in the completion string and theuse of fiber-optic distributed temperature systems. CTDESP technology with real-time monitoring and control results in analternative deployed intelligent completion that is able to optimize pumpperformance and run life, control injection rates, and maximize ultimaterecovery. Such a system was developed specifically for a Shell Sabah Berhad (SSB)medium oilfield, offshore Sabah-Borneo, East Malaysia. This particular reservoir is a mature depleting field, requiring pressure maintenance toextract more of the reserves. After 2 years of production, the oil rate of the primary reservoir had declined by about half. Studies showed that pressure maintenance by water injection (WI) was feasible and beneficial. However, high capital cost and long lead times prevented the implementation of a conventional WI scheme because the existing, unmanned platform was too small to accommodate a WI facility. The lithology of the area is conducive topressure maintenance with a large natural aquifer dumping from an upper zone into the lower producing zones (i.e., dumpflood). Two horizontal wells were drilled and completed, allowing natural dumpflooding of an estimated 3,000bbl/d/well. It was clear that augmenting the natural dumping ability of theupper zone aquifer with an inverted ESP would boost production (up to 10,000bbl/day per well), accelerate the reservoir pressure maintenance, and increase the sweep in the main producing reservoir. With anticipated tubing-deployed ESP run lives of 1 to 3 years, the ESPdumpflood strategy would not be a cost-effective solution because of the cost of rig mobilizations required for ESP workovers. Therefore, a CTDESP system wasselected to allow installation and subsequent change-out without rigassistance. Such a system was evaluated to be USD 25 million more cost-effective than a conventional surface injection system over the life of the project. In the past 3 years, the assisted intelligent dumpflood strategy has shown its value. By boosting the reservoir pressure, the ultimate recovery factor is believed to have increased from 24 to 48%, adding approximately 10million bbl of additional reserves. Additionally, one of the nearby production wells has shown a net increase of 600 bbl/d of oil since the start of assisted dumpflooding operations.

SPE Gulf Coast Section Electric Submersible Pump Workshop, The Woodlands, Texas, 25–27 April, 2007 Abstract ConocoPhillips China Inc. (COPC) operates the Penglai 19–3 oil field, located offshore in Bohai Bay, the People's Republic of China. COPC holds a production sharing agreement with China National Offshore Oil Corporation(CNOOC). The Penglai 19–3 field is the second largest oil field in China with 3.8 billion bbl of oil in place, discovered in May 1999 and put on productionin December 2002. Electrical submersible pumps (ESPs) were selected as the most economic artificial lift method to develop the field, based on the reliability, flexibility and robustness to produce wells with high flow rates and lift heavyoil in an offshore environment. The first ESP installations were challenged with high free gas and excessives and production, resulting in operational issues and a number of failures. Even in this hostile environment, production peaked at 37,800 BOPD during November 2003, before declining as a consequence of reservoir pressure depletion. Moreover, the lower reservoir pressure increased the free gas, thereby reducing pump performance, excessive sand production lead to plugging of the pumping system and sand fill across the reservoir reduced productivity. Various enhancements to the completion and ESP system were made during subsequent well interventions improving ESP performance, maximizing and maintaining production from the field. Furthermore, performing continuous ESP data trend analysis and performance modeling enabled the artificial lift system to be analyzed and diagnosed to maintain optimum well performance. Collaboration between Operator and Service Provider through performance review meetings and changes to operational practices were also implemented. This paper reviews the operation, optimization, and performance of the ESP systems and the challenges faced during the first 3 years of production. Covering initial installations, subsequent well interventions, operation philosophy, optimization methodology, case studies demonstrating value of gas separation and handling devices, completion improvements, ESP configuration enhancements, run life assessment and equipment dismantle findings.