Artificial Lift System Research Articles

Automatic sucker rod pump fault diagnostics by transfer learning using googlenet integrated machine learning classifiers

Oil and gas extraction is vital for meeting the energy needs of a growing global population. Artificial lift (AL) systems play a crucial role in oilfields, especially when reservoir pressure is low. Among these systems, sucker rod pumps (SRPs) are extensively employed for onshore hydrocarbon recovery operations. However, SRPs are susceptible to mechanical failures and operational challenges arising from evolving reservoir conditions. This study proposes an approach for fault diagnosis in SRPs using real-time data from sensors and machine learning (ML) algorithms to detect anomalies and patterns associated with potential problems. The proposed method involves deep learning (DL) for automated feature extraction from dynamometer cards and error-correcting output codes (ECOC) model-based supervised machine learners for efficiently assessing the operational state of the SRP. By forecasting potential failures, preemptive measures can be taken to minimize downtime and reduce maintenance costs. The application of ML in the analysis of SRP provides a potential tool for diagnosing and predicting failures, improving productivity efficiency, and reducing downtime. Also, the accuracy of Convolutional Neural Networks (CNN) models was compared with that of CNN-ECOC model-based learners in this study, and the results demonstrated that integrating algorithms such as Support Vector Machine (SVM) and k-Nearest Neighbor (k-NN) with the network caused significant improvements in the accuracy; however, Decision Tree (DT) and Naive Bayes (NB) did not perform well in the pattern classification task. Specifically, the GoogLeNet model achieved improved accuracy of 96.40 % and 99.40 % when SVM and k-NN were integrated, respectively. Conversely, with DT and NB, the accuracies dropped to 66.30 % and 75.10 %, respectively.

Applications of artificial intelligence algorithms in artificial lift systems: A critical review

In the oil and gas industry, the implementation of an artificial lift system is utilized to enhance the extraction of hydrocarbons from a reservoir that has depleted its natural energy. This can be achieved by employing pumps such as positive-displacement or centrifugal downhole pumps, or by injecting gas into the well tubing to reduce liquid hydrostatic pressure and improve fluid flow towards the surface. Recently, artificial intelligence-based algorithms have emerged as the leading approach for modelling various artificial lift parameters and problems. Consequently, there has been a renewed interest in understanding the role and effectiveness of different computational algorithms used in the artificial lift system domain. While there is an extensive body of literature on this subject, no prior research has effectively consolidated the findings from various artificial lift system domains, underscoring the need for an all-encompassing review. The purpose of this review is to create a guide that serves as a framework that helps scholars identify knowledge gaps and suggest novel ideas that would enhance the workings of artificial lift systems in the oil and gas industry. This article presents the first comprehensive analysis of artificial intelligence applications in five key areas of artificial lift systems in the oil and gas industry namely: prediction of oil and gas flow rates in artificial lift wells, prediction of artificial lift system failures, selection of artificial lift systems, parameter optimization, and the application of soft sensing technologies in artificial lift systems. The research studies pertaining to each of these areas were systematically identified from the existing literature, and their main features were highlighted. To ensure the uniqueness and novelty of this work, a critical evaluation of the artificial lift articles in each broad area was conducted. The review outcomes were then presented in clear tables that highlighted the main features of each study. Findings from the study indicate that artificial intelligence models are prevalent in almost every aspect of artificial lift systems, and the number of articles on this topic continues to grow. Some of these models have even been field tested and proven effective in improving artificial lift system operations and reducing costs. However, there is need to enhance the explicitness and interpretability of some of the predictive models by including vital details, to enhance seamless implementation and easy deployment in the field. This work will be valuable for industry operators, researchers, and students who seek a guide or reference material on artificial intelligence-based models for artificial lift systems.

DEVELOPMENT OF DOWNHOLE PUMP VALVE ASSEMBLY

The purpose of the work is modernization of the valve, in order to increase reliability, wear resistance, increase the pump flow and reduce the load on the rod string, as well as improve durability. The sucker rod pump is one of the most popular and extensively utilized artificial lift systems. It is a frequently chosen option for lifting oil because of its fundamental simplicity, low operating costs, and adaptability in power supply. In the long run of oil production history, sucker-rod pumping was the first option—and frequently the only option—when artificial lift was required. For this reason, the oldest and most popular method of producing oil wells worldwide is sucker-rod pumping. Since the steel used to make rods has limited strength, sucker-rod pumping is typically thought of as a way to raise moderate to low liquid production rates from shallow to medium well depths due to depth restrictions. Since the correct working of the standing and traveling valves is largely responsible for an efficient pumping operation, valves are regarded as the heart of the sucker-rod pump. The extremely high differential pressures across the valve during pumping necessitate a highly dependable sealing action between the ball and the seat. Small initial flaws in the sealing surfaces or subsequent corrosion- or abrasion-related problems result in greater liquid slipping and a quick decline in valve function because of fluid cutting. Subsurface pumps using traditional ball-and-seat valves suffer a number of basic operational issues: • Because of the greatly high number of pumping cycles per day, the sealing surfaces may sustain significant damage from the frequent collision of the two parts against one another. • In deviated wells, valve wear is uneven and can cause premature failure. • Typical cage constructions, meant to limit impact damage, typically restrict the flow area available through the valve and can be the source of pumping inefficiencies due to low fillage of the pump barrel. Keywords: sucker rod pumps, downhole pump, traveling valve, standing valve, valve assembly.

Maximizing Oil Recovery in a Marginal Oilfield: Niger Delta Case Study

Marginal field development and production are often abandoned by operators because of finding reliable and available equipment and services to enable the field to be developed. These challenges make it difficult to economically produce such fields. This research demonstrates the use of industry-based simulators (PIPESIM, ECLIPSE and PETREL) to design well completion model, Electrical Submersible Pump (ESP). model, simulate, and evaluate the performance of ESP on a typical marginal oilfield. The main objective of this study is to effectively optimize oil production from marginal fields in the Niger Delta using Electrical Submersible Pump (ESP). ECLIPSE software was used for the reservoir description. PIPESIM was used to design the artificial lift system (ESP) for five oil wells and PETREL was used to integrate the whole system for effective production optimization. The performance of ESP wells was simulated and compared with the naturally flowing wells. The results obtained from the production forecast showed that the ESP wells gave superior oil production when compared to natural flowing wells. From the simulation results, it was observed that the cumulative oil recovery without ESP was 33,684,736 stb while that recovered with ESP was 87,751,136 stb (about 261% oil increment). The findings of this study will enable petroleum engineers to design ESP systems and well completion that would effectively optimize oil production from marginal fields in the Niger Delta. Furthermore, the findings of the study will offer new and exciting ways to process and transform abandon oilfields into productive marginal oilfields.

Hybrid Energy Holds Promise for Artificial Lift for Offshore Brazilian Fields

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32671, “Technical Evaluation of the Use of Hybrid Energy (Solar and Offshore Wind) To Supply Artificial Lift Pumps on an Oil Platform on the Equatorial Margin,” by W.K. Silva, Ana L.R. Cunha, SPE, and Ana C. Alves, Federal University of Pará, et al. The paper has not been peer reviewed. _ The complete paper investigates the relevance of wind and solar energy for the supply of artificial lift systems on offshore platforms in the Brazilian equatorial region. The scope of the authors’ study encompassed a detailed technical and environmental assessment, with an emphasis on the integration of a 10-MW floating solar photovoltaic (FSPV) power system to meet demand for 10 pumps. The results obtained highlight the high viability of the system in meeting the demand of these pumps and ensuring an adequate and sustainable energy supply. Area of Study The equatorial margin is an area in northern Brazil covering part of the sedimentary basins of the equatorial Atlantic. The region is home to important sedimentary basins such as the Amazon Basin, the Pará-Maranhão Basin, the Barreirinhas Basin, the Potiguar Basin, and the Ceará Basin, all known for their hydrocarbon reserves. Offshore oil-exploration activities in the equatorial margin involve the installation of drilling and production platforms that include artificial lift systems. To power these systems, a reliable and continuous power source is required. The use of green energies such as wind and solar can be advantageous in meeting this purpose. For the present study, the coastal city of Salinópolis in the state of Pará was selected because of its plentiful meteorological data and its location in the Pará-Maranhão Basin region. Methodology The methodology of the work consists of the evaluation of the energy required for artificial lifting systems with 10 pumps, using the nine steps developed by Baker Hughes’ Artificial Lift Research and Technology Center for the calculation of the power required to drive the pumps. Additionally, the study uses the System Advisor Model (SAM), November 2022 version, developed by the National Renewable Energy Laboratory to simulate the FSPV. Information related to wind potential was obtained through the measuring stations of the National Institute of Meteorology (INMET).

7 Industry Leaders Share Their Insights on the Past, Present, and Future of Artificial Lift

_ In the past 25 years, the artificial lift industry has seen incredible changes, making hydrocarbon production smarter and more efficient. In this Q&A article, JPT talks with seven industry leaders from this field about its past, present, and future. This conversation showcases the technological progress such as materials, digital tools, and automation and the strategic leadership that has guided the industry to new heights. Join us as we dive into the world of artificial lift and discover the innovation and expertise shaping the future of energy. This roundtable Q&A includes the following participants: - Greg Stephenson, chief production engineer, Occidental Petroleum - Michael Romer, principal artificial lift engineer, ExxonMobil - Laura Labrador, senior production engineer, Ecopetrol, and 2023–2024 chairman of the SPE Artificial Lift and Gas Well Deliquification Technical Section - Shauna Noonan, Oxy Fellow and senior director global supply chain initiatives, Occidental Petroleum - Jose Ernesto Jaua, global product champion, SLB - Kevin Leslie, vice president artificial lift solutions, Weatherford International - Dana Meadows, global portfolio director, artificial lift systems, Baker Hughes JPT: Can you recall an experience, technical paper, or mentor that significantly influenced your early career in artificial lift? How did it shape your approach? _ Stephenson: Numerous individuals impact my early career, the most noteworthy being Herald Winkler, who was in the first class of SPE’s Legends of Artificial Lift awarded in 2014. I traveled to my first ATCE in New Orleans as a first-year petroleum engineering student. I distinctly remember walking the exhibit floor and seeing this little guy get mobbed by people asking him questions. I asked one of my fellow students, ‘Who is that guy? Tom Cruise?’ He told me, ‘No. That’s Wink.’ I then learned that Wink was one of the pioneers of gas-lift technology and wrote the first definitive book on the subject. At that moment, I realized that artificial lift might offer a viable career path for me. Eventually, I got to know him personally, first as a student and then as an artificial lift professional. One of the most impactful conversations I had with him was one in which he told me, ‘I am not a gas-lift expert. You cannot be an expert in gas lift—the field is too complex. I’m still learning things, and I’ve been doing this for over 60 years!’ That encounter taught me to be humble in approaching my craft and never assume I knew everything.

Artificial Lift: 25 Years of Change Tracked in the Pages of JPT

Nodding donkeys. Thirsty birds. Rocking horses. All are playful nicknames for the oil and gas icon known as a pumpjack. To the uninformed, the pumpjack is a thing-a-ma-jig that has something to do with oil, probably “fracking” because that’s what drilling rigs do, right? But as an industry-educated and well-informed reader of JPT, you know this is inaccurate. By whatever name you call it, you know that the pumpjack is the visible manifestation of an invisible physics equation, a mechanism buried deep underground that lifts reservoir fluids to the surface. You also know it is one type of artificial lift available in a stable of systems with equally curious and technical names like progressive cavity, plunger, jet, gas lift, and electrical submersible pump (ESP). While there is no global repository of artificial lift statistics, industry observers estimate that 90 to 95% of the world’s producing wells use artificial lift, as noted in a 2013 JPT story on the challenges and opportunities for artificial lift. Artificial lift, as applied in oil and gas production, has existed for over 100 years. A 2014 JPT story laid out a brief history of the practice, sharing how the walking beam principle dates back to at least 476 CE when used in Egypt, and evidence of the use of sucker rods to lift fluids has been excavated from the homes of wealthier families in the early days of the Roman Empire. Even as we leap forward to the modern-day application of artificial lift systems, many techniques and technologies resemble their original designs. How these systems are applied has changed, especially in the past decade-plus with the emergence of shale. As highlighted in a JPT story on the past 25 years of technology advances, the industry underwent a robust era of technology development in its rush to crack the shale development riddle. Since 1999, the industry also delivered a 36% increase in global supplies, as noted in this JPT story celebrating this industry’s biggest innovations. 1999 represents an interesting turning point in the industry’s technological journey. Also, it is the last time JPT editors took the opportunity to celebrate the publication as it turned 50 years old that year. What follows are a few highlights from JPT’s coverage of advances and changes made in artificial lift applications and practices over the past quarter century.

An uncertainty approach for Electric Submersible Pump modeling through Deep Neural Network

This work proposes a new methodology to identify and validate deep learning models for artificial oil lift systems that use submersible electric pumps. The proposed methodology allows for obtaining the models and evaluating the prediction's uncertainty jointly and systematically. The methodology employs a nonlinear model to generate training and validation data and the Markov Chain Monte Carlo algorithm to assess the neural network's epistemic uncertainty. The nonlinear model was used to overcome the limitations of the need for big datasets for training deep learning models. However, the developed models are validated against experimental data after training and validation with synthetic data. The validation is also performed through the models' uncertainty assessment and experimental data. From the implementation point of view, the method was coded in Python with Tensorflow and Keras libraries used to build the neural Networks and find the hyperparameters. The results show that the proposed methodology obtained models representing both the nonlinear model's dynamic behavior and the experimental data. It provides a most probable value close to the experimental data, and the uncertainty of the generated deep learning models has the same order of magnitude as that of the nonlinear model. This uncertainty assessment shows that the built models were adequately validated. The proposed deep learning models can be applied in several applications requiring a reliable and computationally lighter model. Hence, the obtained AI dynamic models can be employed for digital twin construction, control, and optimization.

Current balancing of scalar-controlled induction motors with long imbalanced cables for artificial lift systems

Induction motor current imbalance increases losses, torque ripple and vibrations. Current imbalance is known to appear in artificial lift systems, where motors are driven over long imbalanced cables. Power hardware modifications, namely transposition of cable phases in the wellbore, adjustment of the step-up transformer taps, and addition of balancing inductors have so far been proposed to suppress the imbalance. However, these solutions compromise the system's reliability or involve costly additional equipment, which must be customized according to the cable characteristics. This paper proposes a control method for current balancing of induction motors driven by scalar-controlled variable speed drives. In the proposed method, Second-Order Generalized Integrators (SOGIs) are used to extract the negative-sequence component of the motor currents, which is then suppressed by a Synchronous Reference Frame (SRF) current controller. The frequency and angle information required by the SOGIs and the SRF controller are obtained directly from the scalar algorithm, without needing a position sensor or observer, thus offering a novel, simple, robust and computationally effective implementation, which is also independent of the cable characteristics. The paper presents MATLAB/Simulink simulation results to illustrate the method's operating principles and performance in a variety of transient conditions. Experimental results obtained using full-scale equipment are also provided to demonstrate its effectiveness.

Carrier Line Technique for Downhole Chemical Injection in Oil and Gas Industry; Case Study: El Hamra Oil Company

In oil production companies, corrosion is a common issue with various adverse economic and environmental consequences. Active well production fluid always comprises inherently corrosive and highly corrosive substances. There are a variety of treatment techniques to prohibit corrosion, such as chemical treatment, cathodic protection, and paint-based corrosion inhibitors. El Hamra Oil Company produces crude oil from three main locations. The research group noticed several downhole localized corrosion problems in the artificial lift system. This paper presents a case study to quantify the extra operation cost of periodically replacing the entire tubing string, renting the pulling unit, and production deferring. The research quantifies the economic impacts after corrosion inhibitor is injected downhole using the carrier line technique (CLT). The results show that the company saved more than 672 K $ during three years of using downhole chemical treatment; dramatically decreasing the regular corrosion incidents in three active wells. The actual profits are expected to increase exponentially for the following years, meanwhile reducing the environmental impacts to meet Egypt’s strategy towards sustainable goals in 2030.

Selection and Application of Beam Pumping Unit for Heavy Oil Production

Beam pumping units were among the first and are still among the most widely used artificial lift systems. This study investigates the components of beam pumping units and the manufacturing mechanism and design procedure recommended by Recommended Practice and the QRod simulator. The API provides API RP 11L Recommended Practice to obtain the values and operating characteristics for each component in dimensionless form. A trial-and-error method is used during the design procedures to determine the best surface and subsurface equipment for a given well's data. When completing a well, the artificial lift method must be considered to ensure that the well is able to be produced at a satisfactory rate. Besides, the procedures created nine cases to compare the requirements of different production rates and depths for a heavy oil well with 14 APIs. A depth of 5,000 ft with a rate of 300 bbl/day and a depth of 7,000 ft with a rate of 500 bbl/day is the specific production rate and depths at which the well will produce. For 300 BBL/Day the tubing size selected was 2-7/8” OD, for this size the suitable plunger size is 2”, and the suitable stroke length was 74in. In cases 6, 8, and 9, all the simulated rod strings were unable to handle the stress imposed by the combination of high depth and high production rate. As a result, all designed systems will fail during production.

Performance analysis of artificial lift systems deployed in natural gas wells: A time-series analytics approach

In Coal Seam Gas (CSG) production, Artificial Lift (AL) systems comprising various downhole pumps produce coal-fine-laden water. Over time, the accumulation of coal fines results in mechanical failures of such pumps, which leads to a loss in natural gas production. This problem is exacerbated by CSG operators having to manage thousands of wells in their day-to-day operations. The reason for having such an exuberant number of natural gas wells is due to the fact that CSG reservoirs have a short production cycle when compared to conventional reservoirs. Therefore, thousands of CSG wells must operate simultaneously to sustain natural gas volumes that satisfy domestic energy demand, and help meet contractual export obligations.To manage a large fleet of CSG wells, operators rely on Petroleum and Surveillance Engineers to mitigate production issues and advise timely corrective actions. Current methods of monitoring CSG wells involve observing real-time trends and alarms from Supervisory Control and Data Acquisition (SCADA) systems. However, managing a large fleet of wells with a monitoring-only approach can be detrimental to AL operations. Methods such as Exception Based Surveillance have been used to improve engineers' workload, but such methods are informative at best. In addition, they do not provide early indications of changed downhole pump performance. To improve how AL systems are monitored in CSG operation, we propose a novel well surveillance method that can help mitigate pump failure and provide engineers with insightful information to take corrective actions.In this work, we will present an innovative time-series analytics approach that examines the performance of AL systems in near real-time and helps Well Surveillance and Production Engineers make timely decisions that aid in mitigating pump failures. We used time-series data from 448 CSG wells to build the streaming analytics methodology that autonomously detects various performance states of downhole pumps during CSG production. Furthermore, we successfully detected the onset of AL systems failures, such as solids build-up, gas intake, high torque and pump degradation. We validated our solution on a separate set of 428 wells and were able to show reliable detection of detrimental events on live data from producing natural gas wells. This solution is currently deployed by 2 CSG operators where real-time notifications aid Petroleum and Well Surveillance Engineers with proactively managing AL systems across multiple CSG assets.

Collaboration between Oil Development and Water/Power Consumption in High-Water-Cut Oilfields

Waterflooding is the main development technique used in the vast majority of oilfields in the world. However, as the waterflood oilfields enter the stages with (ultra-)high water cut, the water/power consumption per ton of oil remains unabatedly high. This paper presents a systematic analysis of the development stages and strategies of some typical waterflood oilfields in the world and proposes the necessity to establish a mode and technical system of collaboration between oil development and water/power consumption in mature oilfields with (ultra-)high water cut. Then, taking a pilot test area of an ultra-high-water-cut oilfield in northeastern China as an example, this paper investigates its development mode and water/power consumption; optimizes the technical strategies from the aspects of fine reservoir analysis, artificial lift system and surface gathering system; and predicts the application results. It is found that the optimizations of fine reservoir analysis and development plans effectively reduce the water consumption per ton of oil and have a certain but not remarkable contribution to the power consumption per ton of oil. Moreover, the optimizations of the artificial lift system and surface gathering system significantly reduce the power consumption per ton of oil. Under conditions of low production and low efficiency, the optimization of the artificial lift system greatly improves the energy-saving effect, which will be a focus of future research. Finally, this paper recommends measures for collaboration between oil development and water/power consumption in high-water-cut oilfields.

Work Flow, Advisory System Optimizes Intelligent Production Network

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205735, “A Digital Oil Field Comprehensive Study: Automated Intelligent Production Network Optimization,” by Aulia A. Naufal, SPE, and Sabrina Metra, Schlumberger. The paper has not been peer reviewed. _ Leveraging technologies from a flow-assurance simulator, a Python application programming interface (API) toolkit, open-source machine-learning (ML) packages in Python, and a commercial visualization dashboard, the complete paper proposes a series of work flows to simplify model deployment and set up an automatic advisory system to provide insight as a means of justifying day-to-day engineering decisions. The complete paper discusses this methodology and provides a case study of its implementation, although this synopsis concentrates on the former. Background The authors identify four steps necessary for a valid network model that can describe production-system fluid-flow behavior accurately and support day-to-day decision making. These four steps, detailed in the complete paper, include the following: - Well-model building and matching - Well-basis gas lift evaluation - Network modeling - Gas-lift-optimization scenarios Work Flow Objective The objectives of creating an automated, intelligent production-network-optimization work flow include the following: - Minimize risk for data-quality issues caused by human error - Quicken pre- and post-deployment stages of the work flow, thus saving time and resources - Increase the functionality of a digital-oilfield work flow, including adding a production-surveillance dashboard, extracting publicly available temperature data from a weather-service API, and adding an ML autocalibration work flow Theoretical Basis Multiphase Steady-State Flow Simulator. A commercial flow simulator is used to simulate multiphase flow simulation throughout the production system from the reservoir to the surface facilities to enable comprehensive production- (and injection-) system analysis. By the term “steady state,” the authors mean that the mass flow rate is conserved throughout the system, with no accumulation of mass in any system component. This simulator is used from design to the optimization period of the oil, gas, and water production and injection systems. It is most often used by reservoir, production, and facilities engineers to model well performance, design artificial-lift systems, model pipeline networks and facilities, analyze field-development plans, and optimize production. Network modeling is necessary if the interaction of different components (such as compressors, separators, and wells) producing into a common gathering system must be considered (Fig. 1); the wellhead pressure and the deliverability of any well are influenced by the backpressure imposed by the production system. Network modeling also allows engineers to determine the effects of adding new wells and compression, looping flowlines, and changing separation systems. To analyze all components, the network should be solved based on the boundary conditions set on each component. The network will be converged when the pressure balance and mass balance at each node are within the specified tolerance. Then, parameters along the flow path (profile) and at each node in the network will be output. The authors discuss simulation settings, a network optimizer, and a flow-simulation Python toolkit in the complete paper.

TUBING STRENGTH ANALYSIS AND FAILURE ASSESSMENT OF ELECTRICAL SUBMERSIBLE PUMP (ESP) WELL: A CASE STUDY ON PRODUCTION WELL “X”

This study will discuss the evaluation of tubing strength in Well X that using Electrical Submersible Pump as an artificial lifting method. The evaluation will be carried out to determine the risk of failure of production tubing due to erosional damage and the failure due to loads on tubing during production operation using Electrical Submersible Pump. Burst, collapse, and tension loads will be the main focus in evaluating the tubing load by considering the worst conditions that may be experienced during production operation. The calculation of the tubing load is done using Microsoft Excel. The result of tubing load calculation will be compared with the tubing rating based on tubing grade. Erosional damage prediction is carried out using software to determine the erosional velocity on the production tubing.This study will evaluate the production tubing used in Well X with an outer diameter of 3.5 inch and L-80 tubing grade. Tubing L-80 has a burst rating of 7240 psi, a collapse rating of 10533.92 psi, and a tension rating of 107581.11 lbf. Tubing is rating will be the limit that determines the integrity of the well during the production period. Based on the evaluation result, L-80 production tubing that using Electrical Submersible Pump as an artificial lifting method is able to withstand the burst load, collapse load, tension load, and the erosional effect of the produced fluid. Therefore, the Electrical Submersible Pump in Well X as an artificial lift system can be carried out without changing the grade of the existing tubing production.

Permanent Magnet Motors Help Reduce Carbon Footprint in Artificial Lift Systems

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209736, “Carbon-Footprint Reduction Using Permanent Magnet Motors in Artificial Lift Systems,” by Luis F. Ararat, Ronald F. Herrera, and Sergio A. Parra, SierraCol Energy, et al. The paper has not been peer reviewed. _ Permanent-magnet-motor (PMM) technology was evaluated and implemented in the different artificial lift systems in the Llanos Norte (LLN) and La Cira Infantas (LCI) fields in Colombia, aiming to find a more-efficient motor to generate energy consumption savings and reduce carbon footprint. The complete paper shares technical details of the evaluation of tests performed in the field to validate the implementation of PMM technology in the artificial lift systems, the calculation of reduction of tons of carbon dioxide (CO2), and the main challenges in its application as an energy-efficient solution for future projects. Field Background The Llanos Orientales basin has 482 installed electrical-submersible-pump (ESP) and 24 sucker-rod-pump (SRP) wells at the time of writing, at an average depth of 7,450 ft true vertical depth (TVD). LCI, the other field under study, is Colombia’s first producing field and has three different artificial lift systems to produce its wells: 215 progressive-cavity-pump (PCP) installations, 691 SRP installations, and 257 ESP installations. The average depth of the field is 3,500 ft TVD. Background for PMM Technology in the Operator’s Energy Fields In 2016, the first attempt to implement PMM technology for ESP equipment in the LLN and LCI fields was made. The project began in November of the same year with a trial test in LLN with the installation of PMMs in two ESP wells. During the next 2 years, the testing conditions were adjusted, resulting in an energy-savings average of 15%, which validated its large-scale implementation, with more than 250 installations in LCI and LLN. Given the results obtained with ESP installations, the implementation of PMMs was considered for the PCP systems on the surface. The trial test began in 2019 by installing PMMs in two PCP wells in LCI, resulting in a 35% energy savings. The promising results spurred large-scale implementation in PCP initial completions since 2021. At the time of the paper’s writing, 12 wells have been installed. The field trial for SRP systems ran from 2020 to 2021, seeing the installation of five wells in LCI with an average energy savings of 18%. Applications of PMM Technology in Artificial Lift Systems ESP PMM. The ESP PMM features permanent magnets mounted in the rotor. The rotor flux is supplied by the magnets and therefore does not require an electrical power supply to generate this magnetic field. Permanent magnets installed in the motor rotor provide key advantages: - By only using energy to generate the magnetic field in the stator, less energy is required for PPM operation. - Slippage in magnetic flux between rotor and stator is zero. - High efficiency (90–93%) over a wider operating range is achieved. - Higher power density is seen than in conventional rotors. - Electrical losses are reduced, a lower operating current is used, and less heat generation is experienced.

Technology Focus: Artificial Lift (March 2023)

Selecting artificial lift papers for the Tech Focus feature of JPT can be a daunting exercise when technologies and innovations abound, more so post-pandemic, with 157 submitted abstracts covering 2021–2022. In narrowing the offerings to three, the criteria of conformance to guidelines and novelty of information, technical equipment, and application were considered. Industry indicators and interest were also factors. Gas lift remains of high global interest, whether in long horizontal shale oil wells or vertical ones because of the cost to operate lower lifting. Declining production and high gas/oil ratios (GORs) present a challenge for conversion to secondary lift forms. Paper SPE 209721 provides an innovative solution combining gas lift with sucker rod lift to enhance and exploit low-productivity wells in high-GOR fields. Permanent magnet motors (PMMs) have made quite the technical splash in the industry over the past decade. PMMs are one-third shorter and result in higher power densities and power savings of up to 18% just by changing out the induction motor. PMMs are again grabbing attention for the direct 1:1 ratio of electrical to carbon footprint. Current environmental, social, and governance concerns are placing demands on all operators, and PMMs are positioned to help with carbon reduction as a low-hanging fruit in paper SPE 209736. In paper SPE 209763, we look at all-metal progressing cavity pumps (aka M2M), which consist of a metal rotor and metal stator. Incremental advances in geometry and materials continue to see operators use high-temperature fluids with low operational expenditure in mind. Reliability is always a concern, and now a novel condition indicator has been developed and tested that offers a better indicator than pump efficiency alone. Recommended additional reading at OnePetro: www.onepetro.org. SPE 206909 Successful Progressing Cavity Pump Reliability Improvement Project in an Oman Steamflood by Shauna Noonan, Oxy, et al. SPE 211782 Maximizing Marginal Fields Profitability Through Drilling Multilateral Wells To Reduce Well Count and Well Cost: Dual Lateral Well With Single ESP and Smart Lower Completion by Mahmoud Mohamed Abdelhay Mostafa, ADNOC, et al. SPE 209748 Gas Pump—A Gas-Driven Positive Displacement Pump Artificial Lift System by Stephen W. Turk, ELC Energy Services, et al.

Technology Focus: Formation Evaluation (February 2023)

The domain of formation evaluation explores how varied a reservoir could be. In the life cycle of a field, from exploration and production to development, as we hone our knowledge to understand the reservoir, we often explore various subdomains of this discipline at various scales. In this issue, we explore three such subdomains at three different scales. Heterogeneity of reservoir properties, as well as the associated uncertainty, from measured to predicted, is best captured when disciplines are studied at different scales, from concepts to models and, finally, to experiences. Paper URTeC 2021-5434 attempts to understand the dynamics of a basin. This research studies the Wolfcamp formation of the Delaware Basin, where quality of the source rock and thermal maturity is deeply governed by the basin tectonics. The western half of the basin, which was relatively stable through geologic time, shows higher maturity in the source rocks than the relatively active eastern half. This known and observed phenomenon has been reported in various works, from vitrinite reflectance studies to the higher gas/oil ratio in producing wells. The authors explore the possibility of higher resident heat flux from igneous activities in the western part of the basin during the Cenozoic that generated these conditions. This, in my opinion, is the absolute big picture. Knowledge like this helps comprehension of why we see what we see. This is not just an academic exercise; it helps address practical problems in constructing facilities, pipelines, and compressor stations when the field enters the development stage. Once basin-scale regional concepts are established, local reservoir-scale models provide the intellectual infrastructure for the perception of reservoir-scale heterogeneities. Models such as these seek answers from various spectra of measurements. From well logs to cores and from structural maps to production histories, the various subdisciplines all play a crucial role in subsequent hypotheses tests. Applying these conceptual models, then, to modern-day analogs provides justification or critiques of the process for the present and has time and again been the key to the past. In paper IPTC 21225, the authors explore the validity of constructing a variable-scale reservoir model of a submarine fluvial/deltaic system from multidisciplinary data sets. The authors integrate these measurements of various resolutions and granularity, enabling the analyses to pan and zoom on the scales of the heterogeneity. After 20-plus years of production in this field, the knowledge here is still invaluable for understanding the reservoir compartmentalization and, thus, determining infill locations. I am intrigued by the complex nature of these depositional systems and the efforts the authors make to understand them. Once the big picture has been established, it becomes time to put the figurative boots on the ground, or the knowledge to work, for drilling wells and producing fluids. The third choice for this issue, paper URTeC 2021-5410, discusses one of those aspects. Pore-pressure prediction is a crucial exercise in this respect, with a very tight margin for error. In early phases of exploration, when well data are limited if not scarce, safe drilling and well construction often rely on the precision of pore-pressure expectancy and prediction models. Subsequently, as the well matures, understanding changes in pore pressure helps design artificial lift systems, if necessary, to optimize production and maximize the life of the field. In this third paper, the authors challenge some of the practiced notions and empirical parameters that are widely used in pore-pressure-prediction models. One of those, the Biot’s coefficient, is hard to measure, rarely available from experiments, and grossly overgeneralized. The authors discuss the implications of these parameters and the resulting excursion from the true value that overassumptions could make. In my opinion, this is a must-read for any geomechanics enthusiast. I hope the readers appreciate the scales of heterogeneity with which formation evaluation is concerned. The purposes here are beyond purely academic, and research often is burdened by a lack of measured data. Uncertainties can be minimized, however, when knowledge is sought by cross-referencing complementary domains and exploring heterogeneity in variable scales.

Technology solutions and challenges for marginal development of heavy oil fields in CuuLong basin, offshore Vietnam

The production of heavy oil at Dong Do field located in CuuLong basin is a success in the application of advanced technologies. Dong Do field is a marginal project in Vietnam, so its development requires to overcome several challenges, such as high water-cut from early stage, highly unconsolidated sandstone reservoir, flow assurance problems of sour and viscous crude oil, high power artificial lift system, and complex crude treatment at topsides, among others. Over the past decades, production technology application in heavy oil production has been widely deployed in the industry. Apart from the thermal method, the combination of gaslift and ESP technology makes the remarkable advances by enlarging the draw-down created over the conventional pumping lift in heavy oil projects. In fact, heavy oil production with a high flow rate has appeared water-coning in near wellbore region that made the water breakthrough early and water-cut increased rapidly. The pilot test of injecting diesel into heavy oil wells has been applied to producers with the positive results while significantly reduced water-cut comparing before wells shutin. This paper provides a thorough analysis of the new technologies that are applied to Dong Do field, highlighting its key difficulties and how they were resolved through a successful pilot and testing of the cutting-edge advanced solutions, improving the project reliability and thus motivating the consortium to move on to the new field. Also, the updated new heavy oil field schedule is described, highlighting the challenges to be faced during the next projects of marginal development.

Evaluasi Pemilihan Electric Submersible Pump (ESP) Untuk Menggantikan Gas Lift (GL) Di Sumur X Lapangan Offshore Y

Well X is located in the offshore Y field, where there are 7 production wells, all of which use an artificial lift in the form of a gas lift. In this field, oil is produced from the N oil layer while the gas layer comes from the K layer. Well X was drilled in May 2013 with a target of N oil formation at a depth of 9,007 ft MD, slope (450) and 4-1/2" Liner completion. The initial production of well X was 1,632 BOPD; 5.3 MMSCFD; 0% BSW. Well X is the only well in the Y offshore field that does not penetrate the K gas formation, so gas production from nearby wells is used to produce oil from the N formation. well-to-well gas lift. Along with production time, the reservoir pressure in the N oil layer and K gas layer has decreased, so that oil production in well X has also decreased. With changes in company policy that optimize and increase gas production to increase gas sales to the industry around the company's operational areas since early 2017, the outgoing pressure on the Y platform has increased from 210 psi to 450 psi, causing a total oil well X could not pass through and produce due to high outgoing pressure on platform Y. Well X's last production data was on January 31 2017 with oil production of 179 BOPD and 1.25 MMSCD for gas production and gas lift injection of 0.75 MMSCFD, before finally shutting down. The selection of another artificial lift as a substitute for the gas lift has been carried out to revive well X later. Based on the alloy table made by Weatherford for the selection of artificial lifts for conditions on the Y field platform, ESP has many advantages and appropriate flexibility compared to other types of artificial lifts. The ESP type D1050N which is a mix flow ESP has been selected and after installation in well X in August 2019 it has successfully revived with a production test of 885 BFPD, 681 BOPD, and 23% water content on September 3 2019. ESP in well X has been in production for 2 years, until finally experiencing a leaky tubing problem in September 2021 and requiring a new tubing replacement job along with a new ESP replacement to revive the X well. Reference: Brown, E., Kermit, (1977). The Technology of Artificial Lift Method”, Volume 2a, Oklahoma; Pennwell Publishing Company. Brown, E., Kermit (1980). The Technology of Artificial Lift Method”, Volume 3a, Oklahoma; Pennwell Publishing Company. Data-data Lapangan Sumur X Lapangan Offshore Y. (2019-2021). Gabor, Takack. (2009). Electric Submersible Pump Manual Desingn, Operations and Maintenance. United States of America: Gulf Publishing Company. Weatherford. (2005). Artificial Lift System.