Quadrant Mapping Artificial Lift Concept

2021 ◽  
Author(s):  
A. F. Rohman ◽  
C. Febriana ◽  
S. Sany ◽  
R. E. Hanggoro
Keyword(s):  
Production Performance ◽  
Pump Efficiency ◽  
Program Optimization ◽  
Design Problems ◽  
Artificial Lift ◽  
Production Run ◽  
Sucker Rod ◽  
Electrical Submersible Pump ◽  
Four Quadrant ◽  
Monitoring Performance

Abstract This paper outlines a concept for monitoring performance of artificial lift performance such as electrical submersible pump (ESP), hydraulic pumping unit (HPU), sucker rod pump (SRP) and progressive cavity pump (PCP), for a large number of wells. The objective is to generate simplified monitoring performance of artificial lift with a huge number of wells on one page by creating quadrant mapping consisting of two coordinates with x axis representing pump efficiency and y axis showing pump submergence. We made a four-quadrant limit by pump efficiency (50%) and submergence (200 m). Optimum wells will show on range pump efficiency above 50% and submergence below 200 m, and 3 other quadrants are classified as artificial lift problems, well potential and sizing/design problems. By using the quadrant mapping concept, we can generate performance of artificial lift for 1500++ wells in one page, and this mapping consists of four quadrants (quadrant 1, quadrant 2, quadrant 3 and quadrant 4), quadrant 1 (Submergence above 200 meter and lifting efficiency below 50%) showing wells which have artificial lift problem, quadrant 2 (Submergence is above 200 meters and efficiency is above 50%) showing well which have potential to increased production, quadrant 3 (Submergence is below 200 meters and efficiency is above 50%) showing the optimum wells operation and quadrant 4 (Submergence is below 200 meters and efficiency is below 50%) showing the wells which required to re-sizing/re-design artificial lift. This quadrant mapping can be shown to Engineers, manager's and shareholder to show overall performance and classification detailed problems to create a troubleshooting, optimization program to increased oil production, run life artificial and result in better production performance. This mapping also helps petroleum engineers to get a better field view and create priorities and program optimization based on the quadrant mapping result and classification.

Quadrant Mapping Artificial Lift Concept

2020 ◽  
Author(s):  
A. F. Rohman
Keyword(s):  
Production Performance ◽  
Pump Efficiency ◽  
Program Optimization ◽  
Design Problems ◽  
Artificial Lift ◽  
Production Run ◽  
Sucker Rod ◽  
Electrical Submersible Pump ◽  
Four Quadrant ◽  
Monitoring Performance

This paper outlines a concept for monitoring performance of artificial lift performance such as electrical submersible pump (ESP), hydraulic pumping unit (HPU), sucker rod pump (SRP) and progressive cavity pump (PCP), for a large number of wells. The objective is to generate simplified monitoring performance of artificial lift with a huge number of wells on one page by creating quadrant mapping consisting of two coordinates with x axis representing pump efficiency and y axis showing pump submergence. We made a four-quadrant limit by pump efficiency (50%) and submergence (200 m). Optimum wells will show on range pump efficiency above 50% and submergence below 200 m, and 3 other quadrants are classified as artificial lift problems, well potential and sizing/design problems. By using the quadrant mapping concept, we can generate performance of artificial lift for 1500++ wells in one page, and this mapping consists of four quadrants (quadrant 1, quadrant 2, quadrant 3 and quadrant 4), quadrant 1 showing wells which have artificial lift problem, quadrant 2 showing well which have potential to increased production , quadrant 3 showing the optimum wells operation and quadrant 4 showing the wells which required to re-sizing/re-design artificial lift, this mapping can be shown to Engineers, manager’s and shareholder to show overall performance and classification detailed problems to create a troubleshooting, optimization program to increased oil production, run life artificial and result in better production performance. This mapping also helps petroleum engineers to get a better field view and create priorities and program optimization based on the quadrant mapping result and classification.

Improves Sucker Rod and Tubing Lifetime Applying the Wear Predict 99 Equation

2021 ◽  
Author(s):  
Teguh Rachman Hidayat ◽  
Fajar Kurniawan ◽  
Jalu Waskito Aji Nugroho ◽  
Aris Tristianto Wibowo ◽  
Panji Ikhlasul Amal ◽  
...  
Keyword(s):  
Oil And Gas ◽  
Preventive Measures ◽  
Oil Field ◽  
Production Performance ◽  
Service Work ◽  
Efficient Technology ◽  
Work History ◽  
Artificial Lift ◽  
Sucker Rod ◽  
Electrical Submersible Pump

Abstract Finding new oil and gas that can be developed economically is getting more difficult and challenging today. To meet the oil and gas demand, it is therefore important to focus on the existing and already developed assets by applying new and more efficient technology and optimizing the use of existing equipment to increase production performance of the asset thus better recovery. Sangasanga Field as mature oil field of Pertamina EP is producing its oil by the assistance of artificial lift. The artificial lifts applied in Sangasanga field are Sucker Rod Pump (SRP), Electrical Submersible Pump (ESP) and Hydraulic Pumping Unit (HPU) where SRP dominates with 84 units installed while ESP and HPU are 25 units and 15 units respectively. According to the data of well service work history from 2018 to 2020, the failure of SRP and HPU was quite high. The main problem observed were the occurrence of leaking tubing and broken sucker rods. The study gathered the occurrence of failure and a method so called "WEAR PREDICT 99" was created to estimate SRP's buckling point and lifetime. WEAR PREDICT 99 is a correlation derived from comparing neutral point calculated from formula with actual leak data of broken pipe or suction rod. The correlation then used for predicting the buckling point that represents the probable location of the leaking pipe or damaged suction rod. This correlation allows to predict when and where the sucker rod will leak or break, therefore preventive measures to increase the lifetime of the SRP and HPU wells can be taken.

scholarly journals OPTIMASI PRODUKSI SUMUR EC-6 DENGAN MEMBANDINGKAN PENGANGKATAN BUATAN GAS LIFT DAN ELECTRIC SUBMERSIBLE PUMP

PETRO ◽  
2019 ◽  
Vol 8 (1) ◽  
pp. 8
Author(s):  
Jonathan Jonathan ◽  
Sisworini Sisworini ◽  
Samsol Samsol ◽  
Hari Oetomo
Keyword(s):  
Production System ◽  
Gas Injection ◽  
Pipe Diameter ◽  
Submersible Pump ◽  
Reservoir Stimulation ◽  
Artificial Lift ◽  
Sucker Rod ◽  
Electrical Submersible Pump ◽  
Gas Lift ◽  
Electric Submersible Pump

<em>In the world of oil is very common in the production system. This production system produces oil from wells after drilling and well compressions. Over time, the production of a well may decrease due to several parameters of pressure drop and the presence of clay which makes the pipe diameter narrower. There are several methods used to increase the decrease in production including adding artificial lifts such as sucker rod pump, electric submersible pump and gas lift, reservoir stimulation and pipe cleaning if the pipe diameter is reduced due to clay. The well has been installed an artificial lift is a gas lift and this well need an optimization to increase its production. The EC-6 well optimization is planned by comparing the lift-up scenario of the gas lift by adjusting the rate of gas injection and deepening the orifice injection and also an installation of electrical submersible pump. Best percentage of optimization production from EC-6 Well, last scenario is chosen which is new installation artificial lift ESP from gas lift (existing) and gaining 18.52% form existing production</em>

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.

scholarly journals A comprehensive review of sucker rod pumps’ components, diagnostics, mathematical models, and common failures and mitigations

2021 ◽  
Author(s):  
Sherif Fakher ◽  
Abdelaziz Khlaifat ◽  
M. Enamul Hossain ◽  
Hashim Nameer
Keyword(s):  
Mathematical Models ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Gas Industry ◽  
Holistic View ◽  
Comprehensive Review ◽  
Artificial Lift ◽  
Sucker Rod ◽  
Sucker Rod Pump

AbstractIn many oil reservoirs worldwide, the downhole pressure does not have the ability to lift the produced fluids to the surface. In order to produce these fluids, pumps are used to artificially lift the fluids; this method is referred to as artificial lift. More than seventy percent of all currently producing oil wells are being produced by artificial lift methods. One of the most applied artificial lift methods is sucker rod pump. Sucker rod pumps are considered a well-established technology in the oil and gas industry and thus are easy to apply, very common worldwide, and low in capital and operational costs. Many advancements in technology have been applied to improve sucker rod pumps performance, applicability range, and diagnostics. With these advancements, it is important to be able to constantly provide an updated review and guide to the utilization of the sucker rod pumps. This research provides an updated comprehensive review of sucker rod pumps components, diagnostics methods, mathematical models, and common failures experienced in the field and how to prevent and mitigate these failures. Based on the review conducted, a new classification of all the methods that can fall under the sucker rod pump technology based on newly introduced sucker rod pump methods in the industry has been introduced. Several field cases studies from wells worldwide are also discussed in this research to highlight some of the main features of sucker rod pumps. Finally, the advantages and limitations of sucker rod pumps are mentioned based on the updated review. The findings of this study can help increase the understanding of the different sucker rod pumps and provide a holistic view of the beam rod pump and its properties and modeling.

Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

2021 ◽  
Author(s):  
Mohd Hafizi Ariffin ◽  
Muhammad Idraki M Khalil ◽  
Abdullah M Razali ◽  
M Iman Mostaffa
Keyword(s):  
New Technology ◽  
Lessons Learned ◽  
Oil Fields ◽  
Submersible Pump ◽  
Large Space ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

Corrosion Challenges on Electrical Submersible Pump Wells in the North Kuwait Field

2021 ◽  
Author(s):  
Abdullatif Al-Majdli ◽  
Carlos Caicedo Martinez ◽  
Sarah Al-Dughaishem
Keyword(s):  
Submersible Pump ◽  
Stray Current ◽  
The North ◽  
Artificial Lift ◽  
Steel Tubing ◽  
Electrical Submersible Pump ◽  
Historic Data ◽  
Corrosion Resistant Alloy ◽  
Galvanic Couples ◽  
Sweet Corrosion

Abstract Oil production in North Kuwait (NK) asset highly relies on artificial lift systems. The predominant method of artificial lift in NK is electrical submersible pump (ESP). Corrosion is one of the major issues for wells equipped with ESP in NK field. Over 20% of the all pulled ESPs in 2019 and 2020 in NK field were due to corrosion of the completion or the ESP string. With an increase in ESP population in NK, a proactive corrosion mitigation is essential to reduce the number of ESP wells requiring workover. Historic data of the pulled ESPs in NK revealed that most of the corrosion cases were found in the tubing as opposed to the ESP components. Although there are multiple factors that can cause corrosion in NK, the driving force was identified to be the presence of CO2 (sweet corrosion). Corrosion rates have been enhanced by other factors such as stray current and galvanic couples. In this paper, multiple methods have been suggested to minimize and prevent the corrosion issue such as selecting the optimal completion and ESP metallurgy (ex. corrosion resistant alloy), installing internally glass reinforced epoxy lined carbon steel tubing, and installing a sacrificial anode whenever applicable.

Experimental Study and Modeling of Heating Effect in Electrical Submersible Pump Operating With Ultra-Heavy Oil

2018 ◽  
Author(s):  
Jorge Luiz Biazussi ◽  
Cristhian Porcel Estrada ◽  
William Monte Verde ◽  
Antonio Carlos Bannwart ◽  
Valdir Estevam ◽  
...  
Keyword(s):  
Heavy Oil ◽  
Critical Factor ◽  
High Viscosity ◽  
Inlet Temperature ◽  
Outlet Temperature ◽  
Heating Effect ◽  
Submersible Pump ◽  
Oil Viscosity ◽  
Artificial Lift ◽  
Electrical Submersible Pump

A notable trend in the realm of oil production in harsh environments is the increasing use of Electrical Submersible Pump (ESP) systems. ESPs have even been used as an artificial-lift method for extracting high-viscosity oils in deep offshore fields. As a way of reducing workover costs, an ESP system may be installed at the well bottom or on the seabed. A critical factor, however, in deep-water production is the low temperature at the seabed. In fact, these low temperatures constitute the main source for many flow-assurance problems, such as the increase in friction losses due to high viscosity. Oil viscosity impacts pump performance, reducing the head and increasing the shaft power. This study investigates the influence of a temperature increase of ultra-heavy oil on ESP performance and the heating effect through a 10-stage ESP. Using several flow rates, tests are performed at four rotational speeds and with four viscosity levels. At each rotational speed curve, researchers keep constant the inlet temperature and viscosity. The study compares the resulting data with a simple heat model developed to estimate the oil outlet temperature as functions of ESP performance parameters. The experimental data is represented by a one-dimensional model that also simulates a 100-stage ESP. The simulations demonstrate that as the oil heat flows through the pump, the pump’s efficiency increases.

Overcoming Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field

2021 ◽  
Vol 73 (03) ◽  
pp. 46-47
Author(s):  
Chris Carpenter
Keyword(s):  
Heavy Oil ◽  
Oil Field ◽  
Primary System ◽  
Artificial Lift ◽  
Short Period ◽  
Production History ◽  
Electrical Submersible Pump ◽  
Water Cut ◽  
Available Information ◽  
Offshore Oil

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201135, “Challenges in ESP Operation in Ultradeepwater Heavy-Oil Atlanta Field,” by Alexandre Tavares, Paulo Sérgio Rocha, SPE, and Marcelo Paulino Santos, Enauta, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition - Americas, 10-12 November. The paper has not been peer reviewed. Atlanta is a post-salt offshore oil field in the Santos Basin, 185 km southeast of Rio de Janeiro. The combination of ultradeep water (1550 m) and heavy, viscous oil creates a challenging scenario for electrical submersible pump (ESP) applications. The complete paper discusses the performance of an ESP system using field data and software simulations. Introduction From initial screening to define the best artificial-lift method for the Atlanta Field’s requirements, options such as hydraulic pumps, hydraulic submersible pumps, multiphase pumps, ESPs, and gas lift (GL) were considered. Analysis determined that the best primary system was one using an in-well ESP with GL as backup. After an initial successful drillstem test (DST) with an in-well ESP, the decision was made, for the second DST, to install the test pump inside the riser, near seabed depth. It showed good results; comparison of oil-production potential between the pump installed inside a structure at the seabed—called an artificial lift skid (ALS)—and GL suggested that the latter would prove uneconomical. The artificial lift development concept is shown in Fig. 1. ESP Design ESP sizing was performed with a commercial software and considered available information on reservoir, completion, subsea, and topsides. To ensure that the ESP chosen would meet production and pressure boosts required in the field, base cases were built and analyzed for different moments of the field’s life. The cases considered different productivity indexes (PI), reservoir pressures, and water production [and consequently water cut (WC)] as their inputs. The design considers using pumps with a best efficiency point (BEP) for water set at high flow rates (17,500 B/D for in-well and 34,000 B/D for ALS). Thus, when the pumps deal with viscous fluid, the curve will have a BEP closer to the current operating point. Design boundaries of the in-well ESP and the ALS are provided in the complete paper, as are some of the operational requirements to be implemented in the ESP design to minimize risk. Field Production History In 2014, two wells were drilled, tested, and completed with in-well ESP as the primary artificial lift method. Because of delays in delivery of a floating production, storage, and offloading vessel (FPSO), the backup (ALS) was not installed until January 2018. In May 2018, Atlanta Field’s first oil was achieved through ATL-2’s in-well ESP. After a few hours operating through the in-well ESP, it prematurely failed, and the ALS of this well was successfully started up. Fifteen days after first oil, ATL-3’s in-well ESP was started up, but, as occurred with ATL-2, failed after a short period. Its ALS was successfully started up, and both wells produced slightly more than 1 year in that condition.

Artificial Lift Optimization for Shallow Carbonate Magwa and Ostracod Formations with Massive Propped Fractures

2021 ◽  
Author(s):  
Nasser AlAskari ◽  
Muhamad Zaki ◽  
Ahmed AlJanahi ◽  
Hamed AlGhadhban ◽  
Eyad Ali ◽  
...  
Keyword(s):  
Production Performance ◽  
Shallow Depth ◽  
Production Rates ◽  
Field Development ◽  
Artificial Lift ◽  
Geological Conditions ◽  
Fracture Fluid ◽  
Reservoir Potential ◽  
Gas Lift

Abstract Objectives/Scope: The Magwa and Ostracod formations are tight and highly fractured carbonate reservoirs. At shallow depth (1600-1800 ft) and low stresses, wide, long and conductive propped fracture has proven to be the most effective stimulation technique for production enhancement. However, optimizing flow of the medium viscosity oil (17-27 API gravity) was a challenge both at initial phase (fracture fluid recovery and proppant flowback risks) and long-term (depletion, increasing water cut, emulsion tendency). Methods, Procedures, Process: Historically, due to shallow depth, low reservoir pressure and low GOR, the optimum artificial lift method for the wells completed in the Magwa and Ostracod reservoirs was always sucker-rod pumps (SRP) with more than 300 wells completed to date. In 2019 a pilot re-development project was initiated to unlock reservoir potential and enhance productivity by introducing a massive high-volume propped fracturing stimulation that increased production rates by several folds. Consequently, initial production rates and drawdown had to be modelled to ensure proppant pack stability. Long-term artificial lift (AL) design was optimized using developed workflow based on reservoir modelling, available post-fracturing well testing data and production history match. Results, Observations, Conclusions: Initial production results, in 16 vertical and slanted wells, were encouraging with an average 90 days production 4 to 8 times higher than of existing wells. However, the initial high gas volume and pressure is not favourable for SRP. In order to manage this, flexible AL approach was taken. Gas lift was preferred in the beginning and once the production falls below pre-defined PI and GOR, a conversion to SRP was done. Gas lift proved advantageous in handling solids such as residual proppant and in making sure that the well is free of solids before installing the pump. Continuous gas lift regime adjustments were taken to maximize drawdown. Periodical FBHP surveys were performed to calibrate the single well model for nodal analysis. However, there limitations were present in terms of maximizing the drawdown on one side and the high potential of forming GL induced emulsion on the other side. Horizontal wells with multi-stage fracturing are common field development method for such tight formations. However, in geological conditions of shallow and low temperature environment it represented a significant challenge to achieve fast and sufficient fracture fluid recovery by volume from multiple fractures without deteriorating the proppant pack stability. This paper outlines local solutions and a tailored workflow that were taken to optimize the production performance and give the brown field a second chance. Novel/Additive Information: Overcoming the different production challenges through AL is one of the keys to unlock the reservoir potential for full field re-development. The Magwa and Ostracod formations are unique for stimulation applications for shallow depth and range of reservoirs and fracture related uncertainties. An agile and flexible approach to AL allowed achieving the full technical potential of the wells and converted the project to a field development phase. The lessons learnt and resulting workflow demonstrate significant value in growing AL projects in tight and shallow formations globally.

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