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Collaborating Authors
SPE Artificial Lift Conference and Exhibition - Americas
Abstract Electric submersible pumps (ESPs) assist most of the wells in the Oriente basin because of their capacity to lift large amounts of fluids, commonly in mature fields. However, this technology has a limited run life and is prone to intervention and operational challenges. This proposal aims to reduce intervention time and operating costs in multizone wells using rigless technology. Compared to traditional well interventions, rigless ESP permits a replacement operation in a shorter time, thus, reducing cost and deferred production. The company completed a drilling campaign in the southern area of the Mariann field, obtaining outstanding results during the first months of production. The operator considered producing several reservoirs simultaneously using modern completion techniques as a viable alternative to accelerate production from these wells. The acquired experience in the first two wells completed with rigless ESP technology in the Tarapoa Block allowed us to illustrate the technical and economic advantages of combining rigless technology with intelligent completion systems. This paper describes the current state of this technology in Ecuador. It addresses several important aspects such as completion design, ESP selection, nodal analysis, and production planning from Lower U and Basal Tena reservoirs. Economic implications of this technology compared to dual completions are also discussed. The candidate well was Mariann-56 due to its excellent reservoirs and remaining reserves. Based on production engineering and economic analysis, this study confirmed the feasibility of rigless multizone technology and improved the field's learning curve in multizone wells. The most significant results indicate that the company could reduce intervention time by more than ten days, representing an 80% reduction in time typically used for an ESP replacement using a workover rig. The operator could also optimize the project's economics by approximately USD 1.1 million in the first intervention related to deferred production and intervention costs. In addition, managing water cut using flow control valves maximizes well performance and provides better economic results. The following paper consists of a complete engineering and economic study useful for the decision-making process that will serve as a guide to improving ESP cost efficiency in multizone completions.
- South America > Ecuador (1.00)
- Asia > Middle East (1.00)
- North America > United States > Texas (0.94)
- South America > Ecuador > Sucumbíos > Oriente Basin > Tena Formation (0.99)
- South America > Ecuador > Oriente Basin > Napo Formation > Napo U Formation (0.96)
- South America > Ecuador > Sucumbíos > Oriente Basin > Shushufindi Field > Napo Formation (0.94)
- (2 more...)
Carbon Footprint Reduction Using Permanent Magnet Motors in Artificial Lift Systems
Ararat, Luis Fernando (SierraCol Energy) | Herrera, Ronald Fabian (SierraCol Energy) | Parra, Sergio Andres (SierraCol Energy) | Solano, Francisco Javier (SierraCol Energy) | Martinez, Angie Catherine (Borets Company) | Suarez, Efrain (Borets Company)
Abstract Permanent magnet motor (PMM) technology was evaluated and implemented in the different artificial lift systems in Llanos Norte (LLN) and La Cira Infantas (LCI) fields aiming to find a more efficient motor that aligns with SierraCol Energy's mission as an independent operator in Colombia to generate energy consumption savings and contributing to reduce the carbon footprint. During the last decade, awareness has been raised about environmental issues and the need to combat the effects of climate change. Efforts led by different agreements between nations have gained strength based on the 1992 Earth Summit and the 2015 Agreement of Paris, which establishes measures for reduction of greenhouse gas emissions in order to minimize the impact of the carbon footprint in different industries strongly associated with the exploitation of fossil resources and its impact. More efficient technologies within the oil and gas sector are important since the increase in energy costs worldwide has been impacting the operating costs of mature oil and gas fields, and reservoir depletion, high water cuts, and equipment maintenance are increasing energy demands. The process of identifying new, more efficient technologies was initiated, and PMMs were selected and implemented, achieving a significant reduction in energy consumption (15% - 25%) in artificial lift systems at SierraCol Energy fields. In 2016, a trial test in LLN field began with the installation of PMM in two wells with ESP systems, with an average energy saving of 15%, based on ESP results. The trial test began in 2019 with two wells with PCP systems in LCI, obtaining 35% energy savings. These favorable energy savings resulted in a large-scale implementation in the initial completions in 2021. The last trial test for the SRP system began in 2020/2021 with the installation of five wells in LCI with an average energy saving of 18%. PMM met the expectations and objectives set for their evaluation; a 15% reduction in energy consumption has been achieved for the main artificial lift systems (ESP, SRP and PCP) with PMM technology compared to conventional systems. Savings in energy translates into a reduction of 24,500 tons CO2eq in five years; therefore, implementation of PMM technology is considered an energy efficient alternative and potential agent of change in reducing the carbon footprint. This paper shares technical details of the evaluation of new technologies and tests carried out in the field to validate the implementation of PMM technology in the artificial lift systems, the calculation of reduction of tons of CO2eq, and the main challenges in its application as an energy efficient solution for future projects.
- South America > Colombia (1.00)
- Asia > Middle East > Saudi Arabia (0.28)
- North America > United States > Texas (0.28)
- South America > Colombia > Santander Department > Middle Magdalena Basin > La Cira Infantas Field (0.99)
- South America > Colombia > Llanos Basin (0.99)
- South America > Colombia > Arauca Department > Llanos Basin > Cano Limon Field (0.99)
Abstract Electrical submersible pumps (ESPs) must handle two-phase flow (liquid and gas) conditions in production wells. Pump stages are designed for liquid handling, and the pump performance is significantly affected by the presence of gas. ESPs are tested in two-phase flow conditions, and performance is measured stage by stage to improve the understanding of gas, its limitations, and its effects. ESPs are tested in a high-pressure, two-phase flow loop. Pumps are instrumented across stages for pressure measurements. Pumps are tested at intake pressures between 50 and 250 psi, with gas percentages of 0 to 95% maximum, and at different flow rates ranging from 40 to 70 Hz for complete performance mapping. The flow loop is capable of up to 80+% gas and 250 psi intake pressure at the pump intake, running up to 60 Hz, 300 HP, and 18,000 bpd of fluid. Pump performance is evaluated for the various gas conditions at various speeds and intake pressures. Pump performance is significantly affected in two-phase applications. The performance deteriorates with an increase in the gas percentage and improves with an increase in the speed and the intake pressure. Mixed flow pumps handle gas better than radial flow pumps. Larger diameter pumps have higher gas handling capabilities than smaller diameter pumps. Sizing taper pumps operating in a flow range higher than the BEP flow range and additional pump stages in the sizing provides longer life, higher reliability, and more efficient operation in gassy applications. Pump performance under various downhole conditions was investigated, and a new technique was developed for the sizing of ESPs in two-phase flow applications.
Abstract Electrical Submersible Pump (ESP) is one of the most adaptable artificial lift methods that is capable of lifting high fluid volumes from wellbore to surface. Despite that, ESPs are not suitable for wells with high gas liquid ratio. Presence of free gas inside an ESP causes pump performance degradation which may lead to higher motor temperature and/or pump failures during operations. Thus, it is necessary to investigate effects of free gas on pump failures due to the degradation of pump performance under two-phase flow and high motor temperature. This study is one of the first attempts to simulate motor temperature using developed correlations which predict two-phase pump performance under downhole conditions. Field data from two ESP-oil wells were used to confirm the reliability of the developed simulations predicting two-phase ESP performance and motor temperature under downhole conditions. The simulation results show that liquid rate drops significantly due to the degradation of pump performance under two-phase flow, reduces by around 50% when free gas fraction increases from 0 to 0.4. In addition, ESP applications might be feasible in different gassy conditions with up to 0.35 free gas fraction. However, when the pump is run at 3500 RPM, the maximum free gas fraction that an ESP can tolerate is about 0.25 before the pump is overheated and failed. The findings from this study will help operating companies as well as ESP manufacturers to operate ESPs within the recommended range under downhole conditions.
- North America > United States (0.46)
- South America > Brazil (0.28)
Comparative Results for ESP Applications in Gassy Wells when Using Single Gas Handling Systems vs. Multiple Gas Handling Systems for Pioneer Natural Resources
Martinez Villarreal, Paola Elizabeth (Schlumberger) | Escobar Patron, Ana Katherine (Schlumberger) | Rosales Ballesteros, Eder Jean (Schlumberger) | Schreck, Stephen (Pioneer Natural Resources)
Abstract Electric submersible pumps (ESPs) have historically been limited when operating in gassy conditions. Studies and evidence gathered during failure analysis confirm the effects of gas on the performance of ESPs. Gas locking, mechanical wear, and low efficiency due to challenging environments have made operators change from a standardized string to a string that can mitigate the effects of gas, which can help maximize the production and increase the pump's run life. The impellers of the centrifugal pump require a minimum amount of liquid mass in the impeller vanes to transfer the kinetic energy to the fluid mixture. This energy will be transformed to potential energy in the diffuser, but if the mass mixture in the impeller cannot perform an efficient energy transfer for the mixture, only the liquid phase will be pushed out the vanes of the pump and most of the gas will stay behind, filling the vanes of the impeller and creating a gas-lock condition. In environments with a high presence of gas, additional equipment such as rotary gas separators are used to remove as much gas as possible before the fluids enter the pump. Gas separators have been proved as effective. However, when the conditions are extreme, such as in unconventional reservoirs, additional devices will be required to maintain a stable operation of the ESP, pump as much as possible a homogenous fluid, and minimize the downtime due to unnecessary trips to maximize the overall performance and run life of the ESP system, and optimize production and total cost of ownership for artificial lift operations. This paper presents the comparative results of the performance of a group of ESPs installed in unconventional wells of a leading Midland basin operator with challenging conditions to operate an ESP. It will analyze the performance of the ESPs and compare the trends of the downhole parameters while operating with a standard string with a single gas separator and gas-handling system with those of an upgraded string that includes a tandem gas separator, an advanced gas-handling system, and a multiphase gas-handling system equipped with helico-axial-flow stages. This change in designs and configuration has improved the run life of the ESPs for unconventional wells with high gas volume fractions.
- 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)
- (26 more...)
Abstract Among the many available methods for determining pump intake pressure and flowing bottom hole pressure in pumping wells, there remains the practical need to both reduce the input field data modeling requirements (carbon and cost reduction) and to combine the different but related concurrent, countercurrent and column multiphase flow phenomena governing the calculation (accuracy improvement). This paper furnishes both lab- and field-validated analytical multiphase modeling methods showing the various ways the discovered triangular interrelationship between pump intake pressure, gaseous static liquid level and downhole gas separation efficiency changes in response to different sensitivities. The pressure distribution along the entire multiphase flow path of the pumping oil well, including between the pump intake pressure and flowing bottomhole pressure at reservoir depths, is also modeled in detail. A notable difference in this work in reference to prior works of pump intake pressure and gas-to-pump (i.e., gas holdup at pump intake region) modeling is a more detailed physics-based understanding of how gas holdup changes and develops along the gaseous static liquid column above the downhole packer-less pump. In this way, using an easy-to-compute, zero-cost, independently reproducible, published model for bubbly to churn flow in combination with a cutting edge commercial analytical multiphase flow simulator, we first validate the simulator results with published lab datasets of developing gas flow through static liquid columns under carefully controlled conditions. Then, several published field datasets of producing oil wells with liquid levels are simulated to confirm the extensibility of our model to actual field wells and currently-active production operations. In these field validations, the transient countercurrent liquids loading feature of the simulator is utilized to determine the prevailing liquid level. We then additionally perform several important sensitivities showing the various ways that pump intake pressure, flowing bottomhole pressure, gaseous static liquid level, and downhole gas separation efficiency changes in response to different hydraulic diameters, flowing areas, casing-annulus clearances (e.g., ESP versus rod pump), liquid column flow patterns, axial developing flow lengths, and wellbore inclination. Regarding our liquid level buildup simulations, we demonstrate the effect that liquid levels have on dictating the possible operating limits on highest and lowest downhole gas separation efficiencies. This work represents a of the aspect of multiphase flows that is most pertinent to artificial lift: accurate critical gas velocity prediction leading to reliable modeling of countercurrent multiphase liquid loading and gas flow along static liquid columns. We lay the foundation for a change in conversation among the artificial lift community for paying much more practical attention as well as research interest into the multiphase countercurrent and gaseous static liquid column flow behaviors prevalent in the majority pumping oil wells and liquids loaded gas wells. To this end, a new industry digital computing capability is presented and comprehensively validated in both this paper and the part-2 paper of this paper series (Nagoo et al., 2022a): the ability to perform multiphase countercurrent liquid loading simulations that dynamically loads a pumping oil well casing-annulus or gas well tubing/casing, and the reliable calculations of the total pressure gradient that with the increasing gas holdup along the static liquid column of these wells. This means that for pumping oil wells (SRP, ESP, PCP, etc.), the pump intake pressure, flowing bottomhole pressure at reservoir depths, downhole gas separation efficiency and static gaseous liquid level above the pump can now be . For the part-2 paper, our new method is used to calculate the static gaseous liquid levels in liquid loaded gas wells from only basic surface field data. In terms of digital twin applications for the oilfield, our new methods can be performed in real-time in an autonomous way on an IIOT-enabled (IIOT = industrial internet of things) wellhead device to continuously optimize production to create value at scale. We term this device a "wellbore liquid level digital sensor": a solution that takes in real-time SCADA (supervisory control and data acquisition) surface data and converts it to automated calculations of pump intake pressure, flowing bottomhole pressure, downhole gas separation efficiency, gaseous static liquid column height and gas holdup profile along the static liquid column. This is an industry-first, at-scale, digital oilfield solution purpose built for . Such calculations are used to drive the real-time production operations decisions needed for minimizing lifting costs and minimizing unplanned shut-downs and pump/equipment failures. Indeed, a net-zero future for the oil and gas industry on a whole relies on the digital innovations like those provided in this large body of work to empower energy transformation, and to manage/harness the immense amount of asset data in ways that was not possible before. Incorporating novel digital solutions in will improve engineer productivity (higher value creation) as well as corporate profitability (safer, lower-carbon operations) by streamlining downhole calculations, analyses, operational performance indicators, and cutting costs for better decision-making support.
- Overview (1.00)
- Research Report > Experimental Study (0.45)
- Research Report > New Finding (0.45)
- 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)
- (25 more...)
- Information Technology > Sensing and Signal Processing (1.00)
- Information Technology > Architecture > Real Time Systems (1.00)
- Information Technology > Communications > Networks > Sensor Networks (0.48)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Model-Based Reasoning (0.34)
New Integrated Approach to ESP Management - Successful Strategy to Optimize Well Production and ESP Run Life
Spagnolo, Salvatore (Eni) | Pignotti, Eleonora (Eni) | Scarso, Marco (Eni) | Cappuccio, Pasquale (Eni) | Pilone, Salvatore (Eni) | Valente, Alberto (Baker Hughes) | Gonzalez Zamora, Mariangela (Baker Hughes) | Ciavarro, Lucio (Baker Hughes)
Abstract Our analysis identified specific best practices to help Production Engineers improve the performance of the ESP system. We demonstrated how, by closely monitoring the interactions between injected chemicals and pump control parameters, the ESP run life can be increased and total cost of ownership reduced. ESP are used in depleted reservoirs, but failure rate poses economical limitations when rig availability is low and workover costs are high. To minimize the deferred production, we devised a comprehensive strategy for de-risking ESP operations with ad-hoc chemical treatment. Many variables are analyzed in literature to increase ESP run life. However, they are often treated standalone. We evaluated previous studies conducted in this field, both at downhole level and surface production facilities. We focused our quantitative analysis on the interaction between reservoir fluids and ESP system to identify detectable signatures on pump control parameters. We continuously monitored operation of pumps at field level through real time data and identified distinctive anomalies in specific wells. We ran software simulations to evaluate likelihood and type of scale deposition downhole. We selected ad-hoc chemical treatment and accurately measured impact on ESP control parameters. Initially we observed a decrease in delta pressure (pump intake vs. pump discharge) in a well, a trend that was determined by possible pump plugging. The team decided to collect field samples of the produced fluids. A chemical downhole model was calculated through software simulation, then an ad-hoc chemical treatment was selected for the specific application. The team then iterated the solution in the field using additives for: i) inhibiting formation of further deposits; ii) removing existing scale deposits at ESP level. With rigorous evaluation of the new pump conditions through remote live monitoring and continuous adjustment of chemical treatment, the well showed a positive gain of delta pressure indicating the effectiveness of the solution. In the following months, well tests were conducted on site with test separators to collect actual data on the additives used. This allowed the team to fine-tune the long-term treatment program after further reducing the chemical dosage to optimize OPEX. Our study identified specific variables that Production Engineers must analyze when operating ESP in high-risk/high-return projects. Also, we identify a general methodology to promptly intervene in case of erratic pump behavior. The paper describes for the first time what a comprehensive production solution can do in increasing ESP run life while restoring production in complex wells prone to scale deposition. Software analysis and continuous data collection/interpretation from downhole pumps were key aspects to mitigate risk
Abstract For decades sucker rod pump artificially, lifted wells have used devices called pump off controllers (POC) to match the pumping unit's runtime to the available reservoir production by idling the well for a set time where variable frequency drives are not available. In doing this the POC allows the well to enter a set period of downtime when the downhole pump fillage is incomplete to avoid premature failures, and then brings the well back online to operate before production is lost. Although this method has been successful for several years, autonomous control algorithms can be utilized to reduce failures or increase production in cases where the downtime is not already optimized. Optimizing the idle time for a sucker rod pump artificially lifted well involves understanding the amount of time required to fill the near wellbore storage area before generating a fluid column above the pump intake that will begin to hinder inflow from the reservoir into the wellbore. By varying the idle time and observing the impact on production and cycles the program hunts for the optimal idle time. By constantly hunting for the optimal idle time the optimization process can adjust the idle time when operating conditions change. This gives the advantage of always meeting the current wellbore and reservoir conditions without human intervention. Autonomously modulating the idle time for a well, if done properly will reduce incomplete fillage pump strokes in cases where the idle time is too short or will increase the wells production in cases where the idle time is too long. Overall this will result in the optimization of wells by reducing failures and/or increasing production, generating a huge value to the end user by automating the entire process of downtime optimization.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.89)
- North America > United States > Texas > Permian Basin > Yates Formation (0.89)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.89)
- (24 more...)
Abstract An experimental and theoretical investigation of the mechanisms of downhole gravity (shroud type) separation under slugging conditions has been conducted. Based on the observations, a new mechanistic model for downhole separation failure has been proposed. A new facility has been designed and built to represent a section of a gravity-driven inverted shroud type separator at the primary separation region. This study focuses on how the Taylor bubble (large bubble) interacts with the primary separation region. High-speed video recordings were used to analyze the interaction in detail. The results show that the Taylor bubble starts to be ingested into the inverted shroud when a critical liquid flow rate is reached. This critical flow rate separates the regions of the ‘high efficiency’ and ‘disrupted efficiency.’ A gas ingestion criterion model has been proposed based on a simplified slug flow model in vertical wellbore conditions. The model has been evaluated with data from the large-scale downhole separator facility with favorable results. We present the results of the first experiments to investigate the main mechanisms of gas-liquid separation in a gravity-driven inverted shroud type separator under slugging conditions. Identifying the mechanisms is the first step in developing mathematical models for downhole separation design and troubleshooting. The results could be applied to a horizontal well configuration where electrical submersible pumps are deployed in larger GOR environments.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- 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 Liquid loading is a major factor limiting the production of gas wells. Liquid loading starts when the gas production rate does not provide sufficient transport energy to lift the liquid out of the well. The downhole liquid accumulation imposes an additional hydrostatic backpressure on the formation and decreases the production capacity of the well. This paper presents a data-driven model to predict the minimum gas rate required to lift the liquids out of the well. A dataset consisting of 394 horizontal plunger-lift gas wells was used to train the data-driven model. A total of 32,292 points of liquid loading onset were found in the dataset and the corresponding gas flow rate was labelled as the target. Principal Component Analysis and Mutual Information Regression were performed to choose twelve most influential features on the critical gas flow rate (target). A model group consisting of three different machine learning algorithms and ten different data preprocessing steps was trained on the dataset. The most accurate model in the group was chosen to be the critical gas flow rate model. Results showed that the data-driven critical gas flow rate model predicts the critical flow rate with R scores of 0.97 and 0.90 for train and test datasets, respectively. Also, the model results were compared to a few well-known empirical correlations in the literature (Turner, Coleman, Belfroid, Wang, Nagoo, and Shekhar equations). Results confirmed that the data-driven model has the highest agreement with the Belfroid model in comparison with the other equations. Next, an unsupervised learning method was used to modify the Belfroid equation. The modified correlation was proposed as a simple engineering tool to calculate the critical flow rate with higher accuracy in comparison with other correlations studied. It was observed that the Belfroid model underestimates the critical flow rate by around 32% and 5.2% for wells with tubing pressures lower than 300 Psig and higher than 300 Psig, respectively. Most of the current critical flow rate models are based on two theories to explain the onset of liquid loading, droplet reversal and film reversal. Yet, the liquid loading mechanism is unknown due to the complexity of dynamic interactions between the reservoir and wellbore. Besides, most of the current models have their own limiting assumptions. This study provides a model that avoids unlikely theories or unrealistic assumptions and utilizes one of the biggest datasets of wells.
- North America > United States > Texas (0.28)
- North America > United States > Pennsylvania (0.28)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Ohio > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > New York > Appalachian Basin > Marcellus Shale Formation (0.99)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Gas well deliquification (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)