New Stage of Rodless Artificial Lift Operation: the First Field Application of Submersible Motor Cable Plug with Electric Submersible Progressing Cavity Pump in CNPC

2020 ◽  
Author(s):  
Shijia Zhu ◽  
Zhongxian Hao ◽  
Lixin Zhang ◽  
Eryang Ming ◽  
Quanbin Wang
Keyword(s):  
Field Application ◽  
Artificial Lift ◽  
Submersible Motor

Technology Focus: Artificial Lift (October 2021)

2021 ◽  
Vol 73 (10) ◽  
pp. 53-53
Author(s):  
Michael C. Romer
Keyword(s):  
Predictive Analytics ◽  
Idea Generation ◽  
Field Application ◽  
Advanced Materials ◽  
Artificial Lift ◽  
Sucker Rod ◽  
China National Petroleum Corporation ◽  
Submersible Motor ◽  
Shale Reservoirs ◽  
Gas Lift

What, a second artificial lift focus feature this year? What’s going on? Well, maybe I can answer your questions with another round of questions: Do you know how many of your organization’s wells are artificially lifted? Or, more importantly, do you know what fraction of your production volumes are dependent on artificial lift? I would wager that the percentages are higher than you would expect, and I encourage you to seek out that information and share it. Share it with your asset team, share it with other asset teams, share it with other functions, share it with your management, shout it from the rooftops! Seriously, though, this information can be quite useful to you and your organization. Did you ever wonder if someone else could be struggling with the same artificial lift selection, installation, operation, or reliability challenges that you are? The answer you’re looking for may be in the SPE archives, or it may be just down the road with a colleague in a different part of the region, country, or world. Do you have a novel new technique, system, or invention that you want to try out? Why not leverage the knowledge that others in your company could also benefit from? Maybe they would even like to participate and strengthen your pilot with a broader range of test conditions. Do you need more personnel or technical or financial support for artificial lift in your asset? Show precisely what those electrical submersible pumps (ESPs), rod pumps, gas-lift valves, and plungers (among others) are lifting to the flowline. Sometimes a step back to a higher-level view can motivate and reinforce the people behind the day-to-day efforts to extend the time between failures and chase optimum performance. I’m certain that you are now a (possibly unwilling) expert at videoconferencing. That’s why I would like to encourage you to attend the 2021 SPE Electric Submersible Pumps Symposium, to be held 4–8 October in The Woodlands, Texas. Of course, the technical presentations will be well worth it, but you may gain even more value from the networking, collaboration, and idea generation that happens between the events listed in the program. Not an ESP person? Do gas and sand separators, power cables, advanced materials, and downhole sensors apply to other lift methods or well systems in general? How about applied artificial intelligence, reliability studies, and predictive analytics? Maybe they don’t for you right now, but they could. I hope to see you there. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201153 - Intermittent Gas Lift for Liquid-Loaded Horizontal Wells in Tight Gas Shale Reservoirs by Daniel David Croce, Colorado School of Mines SPE 202668 - Insert Sucker Rod Surface-Controlled Subsurface Safety Valve: A Step Ahead To Improve the Well Integrity for Sucker Rod Artificial Lift Retrofitting by Salvatore Pilone, Eni, et al. SPE 201136 - New Stage of Rodless Artificial Lift Operation: The First Field Application of Submersible Motor Cable Plug With Electric Submersible Progressing Cavity Pump in CNPC by Shijia Zhu, China National Petroleum Corporation, et al.

Understanding ESP Performance Under High Viscous Applications and Emulsion Production

2021 ◽  
Author(s):  
Luiz Pastre ◽  
Jorge Biazussi ◽  
William Monte Verde ◽  
Antonio Bannwart
Keyword(s):  
High Viscosity ◽  
Field Application ◽  
Oil Field ◽  
Two Phase ◽  
Water Emulsion ◽  
Technical Requirements ◽  
Artificial Lift ◽  
Controlled Environments ◽  
Oil Water ◽  
Field Deployment

Abstract Although being widely used as an artificial lift method for heavy oil field developments, Electrical Submersible Pump (ESP) performance in high viscous applications is not fully understood. In order to improve knowledge of pump behavior under such conditions, Equinor has developed stage qualification tests as part of the technical requirements for deploying ESPs in Peregrino Field located offshore Brazil and has funded a series of research efforts to better design and operate the system more efficiently. Qualification tests were made mandatory for every stage type prior to field deployment in Peregrino. It is known that the affinity laws don´t hold true for high viscosity applications. Therefore, extensive qualification tests are required to provide actual stage performance in high viscous applications. Test results are used to optimize ESP system design for each well selecting the most efficient stage type considering specific well application challenges. In addition, the actual pump performance improves accuracy in production allocation algorithms. A better understanding of ESP behavior in viscous fluid application helps improving oil production and allows ESP operation with higher efficiency, increasing system run life. Shear forces inside ESP stages generate emulsion that compromises ESP performance. Lab tests in controlled environments have helped Equinor to gather valuable information about emulsion formation and evaluate ESP performance in conditions similar to field application. Equinor has funded studies to better understand two-phase flow (oil-water) which allowed visualization and investigation of oil drops dynamics inside the impeller. In addition, experimental procedures were proposed to investigate the effective viscosity of emulsion at pump discharge and the phase inversion hysteresis in the transition water-oil and oil-water emulsion. In addition to qualification tests and research performed to better understand system behavior, Equinor has developed and improved procedures to operate ESP systems in high viscous applications with emulsion production during 10 years of operation in Peregrino field. Such conditions also impose challenges to ESP system reliability. Over the years, Equinor has peformed failure analysis to enhance ESP system robustness which, combined with upper completion design, have improved system operation and reliability decreasing operating costs in Peregrino field.

Sand Handling Solutions Through the Use of Low Geometric Index Progressing Cavity Pumps, La Hocha Field, Colombia

2021 ◽  
Author(s):  
Jorge Alberto Martinez Lozano ◽  
Ediberto Cruz Torres ◽  
Nadia Maoly Hernandez Castro ◽  
Jorge Alberto Coronel Avila ◽  
Tim Soltys ◽  
...  
Keyword(s):  
Oil And Gas ◽  
High Efficiency ◽  
Cost Effective ◽  
Helix Angle ◽  
Field Application ◽  
Sand Production ◽  
Cross Sectional ◽  
Positive Displacement ◽  
Geometry Design ◽  
Artificial Lift

Abstract A solution for extend run life with no intervention in a high sand cut and high viscous fluid application for La Hocha field (Huila, Colombia) is presented through the installation of Progressing Cavity Pumps (PCP) designed with aggressive geometries including low rotor swept angle and minimum geometry index concepts. This application has 100-300 BFPD flow rate, sand cut up to 40%, 16°API fluid and 850 cp @ 100°F. This document shows the methodology applied in the selection of well candidates with high frequency of interventions due pump failures associated to sand production and well sanded. The effect of the PCP geometry design, cross sectional area, pitch length, helix angle, pump fit, and elastomer were evaluated consistently as selection criteria in order to verify their impact on PCP run life for sand production applications. The document aims to validate the PCP theoretical design principles with the statistic and results gathered from field during the past 3 years in La Hocha field application. The "Fat Boy project" resulted in less intervention, well services, minimizing production delays and associated costs. The project started on mid-2012, due to successful results has been expanded and nowadays represents the 85 percent of the wells in La Hocha field. This is all part of a combined effort looking for reliable and cost-effective solutions for challenging applications. Progressing Cavity Pumps are used in a variety of oil and gas applications where their beneficial characteristics such as positive displacement, high efficiency, low internal shear rates and pulseless flow provide advantages over other artificial lift systems. PC pumps are available in several geometries which determine their suitability for specific applications assuring optimal performance and extended run life.

Fully Retrievable ESP: A New Artificial Lift Concept

2013 ◽  
Author(s):  
S. Spagnolo ◽  
S. Pilone ◽  
L. Corti ◽  
G. Liantonio ◽  
G. Rizza ◽  
...  
Keyword(s):  
Artificial Lift

ESP Optimization Goes Further: Operating Frequency Beyond 60 Hz

2020 ◽  
Author(s):  
A. Muklas
Keyword(s):  
Circuit Breaker ◽  
Load Level ◽  
Operating Frequency ◽  
Well Test ◽  
Acceptable Range ◽  
Artificial Lift ◽  
Harmonic Filter ◽  
Electrical Submersible Pump ◽  
Motor Load ◽  
Frequency Changes

Optimization in brown field developments is always challenging in terms of cost. One of it is XY Field, Rimau Block, South Sumatera with more than 70% of artificial lift is Electrical Submersible Pump (ESP). At ESP wells that are already running at maximum operating frequency of 60 Hz, some are still having problems to optimize their potential. The option to replace the pump with a higher rate is less of an option due to high cost. This leaves an opportunity to gain oil production by increasing frequency above 60 Hz. Upon discussion with the ESP Principal on the risks and possibilities, a trial was then planned for 3-wells. Candidates are selected from the list of ESP wells with the following criteria such as already operated at 60 Hz, still have sufficient fluid submergence, and based on simulated motor load at 70 Hz is still at safe motor load level. Frequency was increased gradually while continuously monitoring ESP Parameters (motor load, voltage and harmonic). It is also necessary to monitor the cable temperature as it is directly affected by the frequency changes. For each frequency increment, a well test is also performed to monitor the production changes. The trial was done on 3-wells (XY-364, XY-370 and XY-378), with the following promising results. XY-364 and XY-378 successfully reached the targeted 70Hz, while XY-370 stopped at 65Hz due to a cable temperature issue. Oil gain from this optimization was 48 BOPD with 1,043 BLPD and similar BS&W profile. ESP operation still normal until present day with all parameters at acceptable range. There were, however, challenges found during the trial. Cable temperature of XY-364 increased at junction box and found cable scun loosen. The problem was solved by replacing the cables. For XY-370, found temperature increment at moulded case circuit breaker during trial at 65 Hz. It was decided to hold at existing frequency. Unbalanced motor load at XY-364 and broken capacitor at XY-370 occurred at Harmonic Filter. The problem was solved by replacing the capacitor. The trial proves that we can operate ESP higher than base frequency (60 Hz) and resulted in decent oil gain. This opens an opportunity in ESP optimization above 60 Hz at an even larger scale.

Unlocking Oil Resources without Artificial Lift Using Testing Barge in Tambora Gas Field

2020 ◽  
Author(s):  
J., A. Anggoro
Keyword(s):  
Oil Recovery ◽  
Gas Field ◽  
Artificial Lift ◽  
Oil Resources ◽  
Cumulative Production ◽  
Inspection And Maintenance ◽  
Routine Inspection ◽  
Prime Condition ◽  
Safety Operation ◽  
Mahakam Delta

Tambora field is a mature gas field located in a swamp area of Mahakam delta without artificial lift. The main objective of this project is to unlock existing oil resources. Most oil wells could not flow because there is no artificial lift, moreover the network pressure is still at Medium Pressure (20 Barg). Given the significant stakes, the option to operate the testing barge continuously as lifting tool is reviewed. The idea is to set the separator pressure to 1-3 Barg, so that the wellhead flowing pressure could be reduced to more than 15 Barg which will create higher drawdown in front of the reservoir. The oil flows from the reservoir into the gauge tank, where it is then returned to the production line by transfer pumps. The trial was performed in well T-1 for a week in November 2017 and successfully produced continuous oil with a stable rate of 1000 bbls/d. What makes this project unique is the continuous operation for a long period of time. Therefore, it is important to ensure the capacity of the gauge tank and the transfer pump compatibility with the rate from the well, the system durability which required routine inspection and maintenance to ensure the testing barge unit is in prime condition and to maintain vigilance and responsiveness of personnel. This project started in 2018 for several wells and the cumulative production up to January 2020 has reached 158 k bbls and will be continued as there are still potential oil resources to be unlocked. Innovation does not need to be rocket science. Significant oil recovery can be achieved with a simple approach considering all safety operation, production and economic aspect.

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