bluuebunny/crossref_metadata_2025_split huggingface dataset:
Full-Scale Validation Test of Liquid Assisted Gas Lift LAGL
Authors: Scott Amanda M. , Scott Stuart L. , Schwanitz Brian J. , Freeman Steven T. 
Published: November 2020

Abstract
A new and transformational gas lift method termed Liquid Assisted Gas Lift (LAGL) has been developed. LAGL utilizes the co-injection of liquid with lift gas to reduce surface pressure requirements for the kick-off of gas lift, simplify well completions and improve system reliability/flexibility. PetroleumETC executed a Shell GameChanger project to demonstrate the delivery of LAGL for well unloading and kick-off of gas lift. Qualification testing was performed at a university test facility utilizing a 2,788 ft TVD test well with 5 ½-inch casing and 2 7/8-inch tubing. Air and water were the test media. In-well measurements were available bottomhole and mid-string for both the annulus and the tubing. The test well was successfully unloaded in 2 hours with a maximum pressure of 535 psig using manual operation of the module. Two automated tests were successfully conducted; one requiring 2 hours (670 psig max pressure) and one requiring 1 hr and 24 min (724 max pressure). Many lessons were learned, effectively de-risking the technology for field application. A new sliding-sleeve orifice valve was also tested with water, air and under multiphase flow conditions. The larger orifice sizes provided by the 2 7/8-inch sliding sleeve slim valve provides for faster unloading using the LAGL process. The paper provides an update on advances in the value case for the new LAGL technology. LAGL utilizes a single G-L valve, which reduces system costs versus the traditional use of multiple G-L valves and mandrels and dramatically reduces the risk of multi-pointing. LAGL provides the advantage of High-Pressure Single Point Gas Lift (HPSPGL) without the need for high pressures on the well pad, changing surface piping and a high pressure compressor.
Liquid Removal to Improve Gas Production and Recoverable Reserves in Unconventional Liquid-Rich Reservoirs by Subsurface Wet Gas Compression
Authors: Nader Lukas , Biddick David , Artinian Herman , Kulkarni Pandurang , Van Hoy Bob , Zdan Steve 
Published: November 2020

Abstract
Unconventional oil and gas development revolutionized the energy sector in North America and has been transforming the world's energy markets. Notwithstanding the enormous potential, unconventional resource development presents unique challenges to production and long-term hydrocarbon recoveries. As market dynamics are shifting, technologies are advancing, opening up new opportunities in areas once considered out of reach. This paper describes a new technology, a subsurface compressor system, which simultaneously removes liquids, increases gas production, and improves recoverable reserves in gas wells. The subsurface compressor can reverse the vicious cycle of liquid loading, which decreases gas production from a gas well and leads to premature abandonment, by creating a virtuous cycle of increased gas and condensate production. The complete process from well analysis, performance projection, deployment, commissioning to operation are discussed. A recently completed the world's very first field trial in an unconventional shale gas well supports the mechanism of subsurface gas compression and its impacts and benefits on unconventional gas production.
Improvement of the Well Intervention Index by the Implementation of Alternative Conventional Rod with Modified Pin in Artificial Lift Systems with Progressive Cavity Pumps Systems in Deviated Wells
Authors: Labrador Jimenez Laura Soraya , De Sales Bastos Paola Andrea , Arambulo Aviles Jenifer Alejandra , Antolinez Wilson Vasquez , Valderrama Arias Luisa Fernanda , George Brian , Molina Jaimes Jesus Oberto , Garcia Contreras Antonio Jose , Florez Góomez Saul Fernando 
Published: November 2020

Abstract
The progressive cavity pumps system (PCP) are very successful in Colombian oil fields, however, wells operated under severely deviated conditions such as abrupt changes in deviation, high dogleg severity (3-6°/100 ft), and/or inclination angles up to 60° have generated between 3 and 5 interventions per year. These high-intervention wells are considered as critical, representing high operating costs and losses of production due to well-stop periods. The wells are typically of medium depths around 3,500 feet, have fluid rates up to 800 BFPD (BS&W &gt; 80%), are influenced by water flooding, and operate at average speeds of 200 rpm to 300 rpm. For these critical wells we have worked to identify alternatives to reduce the repetitive failures (rods and broken tubing).
As part of an integral strategy to produce these wells with high production and high failure rate, this paper describes different operational processes and design considerations. The following topics will be discussed:
Design of wells with PCP as the artificial lift system Failure analysis Lifting Cost Challenge of artificial lifting Redesign of sucker rod string configuration
This problem represents high lifting costs for a barrel of oil including the additional costs associated with well services and production losses due to closure periods.
As part of the solutions, a drive-rod test with modified pin was performed to improve the rod resistance and decrease the contact loads which allowed greater areas of flow, decreased flow restrictions, and less wear between tubing and rods. This change increased the run life by five times, allowing for the installation on a larger scale in a Colombian field. According to the previous results, the test was started in an additional field, confirming the success of the application in critical wells. This has provided ECOPETROL a significant economic benefit versus the conventional rods previously used in these wells under the same conditions. More than 30 wells have been selected to apply these different rods with successful results. All wells interventions regarding rods and tubing failures were reduced significantly (60% average) along with a decrease in production losses due to the associated downtime.
Experimental Evaluation of a Prototype Centrifugal Packer-Type Downhole Separator
Authors: Sharma Ashutosh , Iradukunda Platin , Karami Hamidreza , McCoy J. N. , Podio A. L. , Teodoriu Catalin 
Published: November 2020

Abstract
With the ever-increasing trend of oil production from lower pressure wells, application of artificial lift techniques is becoming inevitable. Beam pumps and electrical submersible pumps are two of the most common artificial lift methods for low and high oil production rates. But these techniques are susceptible to high gas-oil ratios, particularly at lower wellbore pressures causing gas break-out and possible gas lock. Various types of downhole separators have been recently designed upstream of the pump to resolve this issue and improve the pump efficiency. The objective of this study is to construct a state-of-art experimental facility and simulate the flow in an oil well with varying gas-oil ratios. The facility is then used to evaluate the performance of a centrifugal downhole separator.
The experimental multiphase flow setup is designed, fabricated, and constructed in an efficient and automated way to simulate a typical horizontal wellbore. The well trajectory includes a 31-ft horizontal section, inclinable to ±10o, followed by a 27-ft vertical section. The casing ID is 6-in., and a 2-in. ID tubing is placed with end-of-tubing at the bottom of vertical section. The casing and tubing streams are each led to a return column, where gas and liquid flows are metered. Automated and modulated control valves are used to monitor the pressure and production from casing and tubing streams. Five Coriolis flow meters quantify density and flow rate of different fluid streams. All of the equipment is connected to a control computer via DAQ cards.
The experiments are performed with air, supplied by a screw-type compressor, and water, supplied by a moyno pump. The experiments are conducted with different gas (Qg = 30-230 Mscfd) and liquid (QL = 17-700 bpd) flowrates to simulate the cases with both rod pump and ESP operations. The air-water ratio is increased for fixed water rates to identify the ranges of separator effectiveness. The tested downhole separator is an innovative design, applying gravity and centrifugal effects to perform the separation. The results indicate that average gas separation efficiency of the separator is 93% and average liquid separation efficiency is 96% over a wide range of operating conditions, as measured by return line flow meters for casing and tubing streams. The characteristics of multiphase flow in horizontal and vertical sections of the setup are observed and evaluated using surveillance cameras. The separator can be used widely in oil fields to improve gas-liquid separation and artificial lift performance.
The application of pumping artificial lift methods in high GOR wells can help significantly improve the production from a wide range of volatile oil and condensate wells. This illustrates the value of utilizing innovative downhole separation strategies. This paper presents one such centrifugal downhole separator and studies its performance in enhancing the production.
Magnetic Coupling in ESP Applications
Authors: Xiao J. J. , Ejim Chidi , Badr Hassan Mohamed , Abido Mohamed Ali , Khulief Yehia Abel 
Published: November 2020

Abstract
This paper presents a feasibility assessment of eliminating the protector of an electric submersible pump (ESP) by transferring the torque from the motor to the pump using a magnetic coupling, thereby allowing the motor to be hermetically sealed from the wellbore fluids in the operating environment. The paper also briefly discusses means of handling the motor oil expansion as well as the pump axial thrust.
The industry seeks to enhance ESP reliability by designing protectorless ESPs. This requires new techniques to handle torque transfer, motor oil volume change and pump axial thrust, critical functions that a typical protector section performs. Magnetic coupling is a potential method to handle motor/pump torque transfer. For ESP applications, a radial magnetic flux type of coupling is considered. Finite Element software is used to identify the appropriate magnet materials, estimate the coupling dimensions, and predict the coupling performance under transient loads. A sensitivity study is also included to evaluate dimensional variations for different power requirements under different pump rotational speeds.
The analysis identifies two permanent magnet (PM) materials to be appropriate for the magnetic coupling. The length of the coupling is determined for three values of the transmitted power (100, 200 and 300 HP) when operating at three different speeds (3500, 6000 and 10000 rpm). The results show that the magnetic coupling length ranges from 0.95 m to 3.7 m for the considered power range (100 to 300 HP) when operating at a speed of 3500 rpm. The length of the coupling is found to be in the range from 0.65 m to 2.55 m for the speed of 6000 rpm and from 0.4 m to 1.8 m for the speed of 10000 rpm. Mechanical integrity analysis shows that only the case of 100 HP/10000 rpm operates at a subcritical condition, where the predicted total eccentricity has a permissible value. All other operating conditions are supercritical and the whirling deflections of the shaft are likely to exceed the available space within the air-gap. To make the coupling design feasible for these operating conditions, the use of intermediate radial bearings are necessary, which can be challenging in the mechanical implementation and assembly.
This study represents the first systematic and comprehensive attempt in the ESP industry to investigate and assess the feasibility of using a magnetic coupling to replace the conventional protector section of an ESP system. It shows that under low power requirement and high operational speeds, a magnetic coupling is feasible. For other conditions, additional challenges need to be addressed to stabilize the coupling and achieve longevity with the coupling design.
Intermittent Gas Lift for Liquid Loaded Horizontal Wells in Tight Gas Shale Reservoirs
Authors: Croce Daniel David , Zerpa Luis Eduardo 
Published: November 2020

Abstract
The production from horizontal tight gas wells is affected negatively by the accumulation of liquids in the bottom of the well (i.e., liquid loading), to the point that additional hydrocarbon production is not possible. In this work we propose an artificial lift method for liquid-loaded horizontal wells, in tight gas shale reservoirs, based on intermittent gas lift principles. An experimental loop was built to test a prototype of the system and explore the operating envelope that determines the optimal liquid removal results. Experimental results are presented in terms of the liquid removal capacity of the device, as a function of the gas injection rate and the Eotvos (Eo) number. Liquid removal values (produced liquid volume / stagnant liquid volume) of up to 75%, and a volumetric efficiency (volume of liquid produced / volume of gas injected) of up to 78% was obtained for the lowest Eotvos number tested (12) at the lowest gas injection rate (0.25 cf/min). Both the liquid removal and the volumetric efficiency behaved inversely proportional to the Eo number and the gas injection flowrate. Reducing the ID of the line, proved to be an efficient approach to reduce the Eotvos number. Using this option resulted in better sweep, but in an increase of the frictional pressure drop. The improved liquid sweep effect of the Taylor bubble at lower Eo is related to a larger radius of the Taylor bubble and a change on the shape of its nose.
Sucker Rod Pump Downhole Valve Selection for Wells with High Sand Production: Laboratory Test Results
Authors: Del Pino Jessica , Garzon David , Nuñez Walter , Gómez Juan , Renteria Daniel , Sarmiento Dayana 
Published: November 2020

Abstract
Erosion and impact tests were performed on downhole valves with different materials to determine the best valve configuration for the field conditions.
Due to premature failures (less than 1 year of operation) in three wells caused by erosion of the valves, a complete investigation was conducted. First, the history of rod pumps installed in Caño Limón Field was analyzed to obtain configuration statistics of valves installed since 2005. Six different configurations were analyzed, including valves installed in failed and running wells. These configurations included six different ball metallurgies and two different seat metallurgies, combined in double valve setups installed in the pumps. The six valve setups were compared with the average run life and reservoir conditions to determine the best configuration for Caño Limón field. The statistics alone were not clear enough to determine the best configuration for the field, so a laboratory bench was designed to test the different ball and seat metallurgy configurations.
Silicon nitride balls were selected due to their resistance to abrasion, fluid cutting, and impact. The statistics showed good performance when installing silicon nitride balls with tungsten carbide seats, combined with titanium balls and tungsten carbide seats. But when installing single or double silicon nitride balls with tungsten carbide seats, the run time was less than 100 days. The laboratory tests were performed for titanium carbide, silicon nitride, and 440C balls, all of them with tungsten carbide seats. The erosion and wear tests were performed simulating the flow of a slurry around the ball. Silicon nitride balls showed less erosion than titanium carbide and 440C balls. The impact test was performed simulating the downhole pumping action, where the ball is impacted against the seat in a slurry made of water, polymer, and frac sand. Silicon nitride balls showed less wear than titanium carbide and 440C balls, but the seat working with silicon nitride ball showed higher wear than the other metallurgies. When installing single or double silicon nitride balls, the seat wear was higher than when combined when another metallurgy. It was possible to correlate the lab test results with the pump failures to determine the best configuration for the application.
When selecting the valve assembly's metallurgy, it is important to take into consideration not only the properties of the materials, but the effect of combining different metallurgies. Before standardizing an equipment change, field trials and lab tests should be performed.
Effect of Constant Pressure Boundary on Gas Lift of Horizontal Wells
Authors: Uzunoglu Harun , Fan Yilin , Pereyra Eduardo , Sarica Cem 
Published: November 2020

AbstractGas lift has been widely used for unconventional reservoirs, especially during recent years. Most of the previous experimental studies on gas lift were conducted at a constant mass flow rate boundary condition. The current study presents an experimental study that investigates gas lift performance at similar field conditions in which the production rates are driven by the formation pressure.The experiments were conducted in a large-scale experimental facility to study gas lift operations in a toe-down gas lift well. Gas was injected at various rates through casing and tubing annulus to the end of the tubing. The formation gas was supplied by a gas tank regulated at two pressure conditions, which correspond to no production and the last stable production point, respectively. Water was used as the formation liquid phase and injected at the toe. Two liquid flowing conditions were investigated, which were a constant liquid flow rate and constant liquid permeability.As expected for a production system with constant pressure boundaries, formation gas production rate increases first with increasing gas lift injection rate until it reaches a maximum, beyond which flow in the tubing becomes frictional-dominated, and gas production rate starts to decrease. It is found that gas lift affects the flow behavior at the upstream of the injection point. The total liquid inventory reaches a minimum at the point where the maximum gas production rate is observed. The impact of gas lift on system stability was also analyzed. Gas lift can help the well to produce when it is already dead at naturally flowing conditions. However, insufficient gas injection can kill the well faster than natural flow.
Evaluation of an Innovative Hybrid Gas Lift Technique
Authors: Khan Sikandar , Karami Hamidreza , Wang Chengbao , Joshi Mahendra , Reeves Brian , Van Dam Jeremy , Johnson Curtis 
Published: November 2020

Abstract
Improvements on existing wells' potential are crucial towards ensuring an economically viable project. Among various artificial lift techniques, gas lift is considered as one of the most efficient when associated gas capacity is available, and well production parameters are favorable. Also, jet pumps are specifically favorable for horizontal wells due to the relative ease in downhole installation. This paper combines these two techniques to introduce and evaluate an innovative hybrid method. It provides optimum operating windows for its design and application.
This study aims to introduce and benchmark a newly proposed hybrid lift techniques for horizontal wells. Some features of this method are: 1) The operating Gas Lift Valve (GLV) is installed at the bottom of vertical. 2) The jet pump is installed below the GLV. 3) The power fluid and gas are injected through the casing-tubing annulus. 4) The pressure of gas, provided by the compressor, is used to push the power fluid through the jet pump nozzle and into the tubing. An analytical model is applied to simulate this hybrid lift technique through nodal analysis, combining models for reservoir inflow, flow through jet pump, and two-phase flow in wellbore.
A sensitivity study is conducted to understand the effects of depth, API gravity, water cut, reservoir pressure, gas-liquid ratio (or gas injection rate), nozzle pressure, and nozzle and throat area ratio (R ratio) on the proposed hybrid lift's performance. A hybrid lift operating window is defined as the conditions that result in higher production rates than gas lift alone. The largest operating window is present for shallower wells with larger tubing diameters. The R ratio effects are variable throughout the cases and an optimal R ratio design is needed for each specific case. The required optimal GLR is observed to be always lower for the hybrid lift system compared to gas lift, making it relatively easier and cheaper to achieve. Overall, the operating window for application of hybrid lift is: 1) larger tubing size, 2) higher water cuts, 3) shallower wells, 4) lower required GLR's, 5) heavier oils, 6) higher nozzle pressures, 7) depleted reservoir pressures, 8) higher R ratios (if the well can handle the friction). Additional economic considerations are necessary to better evaluate this technique and determine its optimum operating window.
This innovative hybrid gas lift technique can be widely applied towards increasing well's performance, life, and economic viability. It shows its true merit in seemingly less promising and difficult cases with higher water cuts and lower reservoir pressures by increasing benefit throughout the life of the well.
A Non-Intrusive Condition Monitoring and Vibration Control System for Electric Submersible Pumps
Authors: Badkoubeh Amir 
Published: November 2020

Abstract
This paper addresses a condition monitoring and resonance mitigation method for electric submersible pumps (ESPs) based on motor intelligence. Condition monitoring has been an integral part of surface pump applications. Nonetheless, the majority of ESPs may only have a motor phase current and a process-related measurement, which do not directly indicate the operation efficiency and mechanical reliability. This gap is mainly due to the harsh operating environment for ESPs. We propose a condition monitoring method based on the motor intelligence available at the wellhead to detect the electrical, mechanical and process related issues. The proposed resonance mitigation method is based on adaptive tuning of the control parameters in the electric drives and is described in this paper. Finally, a case study is included supporting the validity of the condition monitoring method on detecting the electrical and mechanical faults on a VSD driven submersible pump.