Wireline Retrievable ESP Deployment: Observation, Challenges and Intervention

2021 ◽  
Author(s):  
Fadzlan Suhaimin ◽  
Nasir Oritola ◽  
Bo Jun Fang ◽  
Hing Kheong Cheong ◽  
Yung Khiong Chan
Keyword(s):  
High Risk ◽  
Selection Process ◽  
Cost Advantage ◽  
Value Proposition ◽  
Pilot Performance ◽  
Operating Period ◽  
Artificial Lift ◽  
Start Up ◽  
Offshore Field ◽  
Gas Lift

Abstract The Offshore Field X Project comprises of greenfield scope to expand the Waterflood scheme towards delivering the peak production levels similar to those achieved in the 1990s. Although various artificial lift systems have been successfully deployed in Brunei Shell Petroleum, offshore ESP installation, especially on this scale, is a first and a new journey for the company and its Offshore Assets in which gas lift was predominantly the artificial lift method. The first offshore ESP well was only installed and kicked off in 2017 as part of the Field X Project. As wells are located offshore, cost, resources and logistics remain a challenge for well interventions. With a high workover cost associated with conventional ESP change out, a technology trial was embarked upon to install wireline retrievable ESP systems. A total of 4 out of the 22 ESP wells were approved to be installed and completed with wireline retrievable ESP system on a pilot basis. The business goal was to prove the production deferment reduction and cost advantage for a failed ESP replacement. A critical selection process was followed as well as FAT/industry benchmarking in order to land on WRESP decision for the pilot. System installation and commissioning of the wells was completed by June 2019, however a series of start-up problems were encountered, leading to an intervention requirement to rectify 1 well. Job planning for this intervention was not straight forward and was classified as a high-risk job requiring regulator's approval. Rigorous logistics planning, integration of various vendors, detailed workflow analysis, intervention equipment stack up and modifications were among the planning scope conducted. This paper captures details of the deployment value proposition, case success definition and challenges faced in ensuring all the installed WRESPs are up and running to enable the pilot performance proper evaluation. As no full workover has been executed yet due to the limited operating period, a lifecycle comparison between WL retrievable and conventional ESPs has not been done yet. Once sufficient performance data is available, a detailed study will be conducted to assess the performance of the WRESP system. This analysis will then conclude the technology trial and may change the future of ESP wells in BSP and Shell global.

Artificial Lift Project in Bekapai Field, A Comprehensive and Challenging Selection Process for Mature Offshore Field

2021 ◽  
Keyword(s):  
Selection Process ◽  
Production Model ◽  
Screening Process ◽  
Artificial Lift ◽  
Natural Flow ◽  
Term Evaluation ◽  
Offshore Field ◽  
The Impact ◽  
Gas Lift

Bekapai field was discovered in 1972, production commenced in July 1974 and the peak production was achieved in June 1978. This paper presents a challenging and comprehensive artificial lift selection process in mature offshore field, after produced by natural flow for more than 40 years. The screening process is a very important step for the long term profitability of the field. During the initial screening process, several aspects of subsurface characteristic and surface limitation have been studied to find the feasible artificial lift method. It shows that electric submersible pump (ESP) has several critical limitations to be implemented in this field. A long term evaluation then performed to evaluate the impact of any subsurface and surface variations on the performance of artificial lift. Integrated production model was used to predict the long term performance and ultimate recovery, either naturally or using gas lift and ESP. This model is a numerical simulation to describe the reservoir behavior, production system and find the optimum production strategy by integrating the reservoir models, well models and the surface network model. Impact of any variations in reservoir, well condition and surface parameters are evaluated until end of life or economical limit of this field. Based on this evaluation, gas lift and ESP have higher recovery factor than natural flow condition. The production cumulative is expected increase by more than 40% for the next 10 years. In this simulation also observed that gas oil ratio (GOR) is increasing by time, it’s a critical limitation for ESP. By performing long term evaluation and economical evaluation, it’s confirmed that gas lift is the most feasible artificial lift method for Bekapai field. This comprehensive selection process also ensures the long term profitability of the field.

First Digital Intelligent Artificial Lift Production Optimization Technology in UAE Dual-String Gas Lift Well - Business Case and Implementation Plan

2019 ◽  
Author(s):  
Ahmed Alshmakhy ◽  
Khadija Al Daghar ◽  
Sameer Punnapala ◽  
Shamma AlShehhi ◽  
Abdel Ben Amara ◽  
...  
Keyword(s):  
Business Case ◽  
Production Optimization ◽  
Implementation Plan ◽  
Artificial Lift ◽  
Gas Lift

scholarly journals Innovation in Start-Up Business Model in Energy-Saving Solutions for Sustainable Development

Energies ◽  
2021 ◽  
Vol 14 (12) ◽  
pp. 3583
Author(s):  
Bogdan Wit ◽  
Piotr Dresler ◽  
Anna Surma-Syta
Keyword(s):  
Sustainable Development ◽  
Local Government ◽  
Energy Saving ◽  
Business Model ◽  
Value Proposition ◽  
Sustainable Business ◽  
Business Model Canvas ◽  
Start Up ◽  
Sustainable Value ◽  
Research Questions

Socially expected innovations are innovations considering sustainable development. The subject of the paper focuses on the business model of a start-up providing energy saving services to local government units using smart technologies of Industry 4.0 in the aspect of low touch economy. A methodical critical literature review including quantitative and qualitative assessment, stakeholder analysis and business modeling techniques using Business Model Canvas and Triple Layer Business Model Canvas (TLBMC) was conducted. In addition, an in-depth analysis of a start-up case study was conducted. The research questions are related to the interpretation of the organization’s business data and methods of interpreting Sustainability 3.0 business solutions. The research questions were directed to the challenges regarding the creation of the organization’s sustainable business model architecture and the Business Sustainability 3.0 sustainable business imaging concept. The research objective is to design a sustainable business model of a start-up providing energy-efficient services to local government units, whose value proposition refers to an extended sustainable value that meets the economic, social and environmental needs of society. The integration of sustainability in the sustainable business model of the start-up allowed to achieve the research objective of designing a sustainable value proposition that meets the economic, social and environmental needs of society.

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

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.

scholarly journals Gas Injection Optimization to Increase Oil Production at MRA PT. PHE ONWJ

2021 ◽  
Vol 2 (2) ◽  
pp. 75
Author(s):  
Harry Budiharjo Sulistyarso ◽  
KRT Nur Suhascaryo ◽  
Mochamad Jalal Abdul Goni
Keyword(s):  
Gas Injection ◽  
Economic Feasibility ◽  
Feasibility Analysis ◽  
Offshore Platforms ◽  
Total Production ◽  
The North ◽  
Artificial Lift ◽  
Production Wells ◽  
Java Sea ◽  
Gas Lift

The MRA platform is one of the offshore platforms located in the north of the Java Sea. The MRA platform has 4 production wells, namely MRA-2ST, MRA-4ST, MRA-5, and MRA-6 wells. The 4 production wells are produced using an artificial lift in the form of a gas lift. The limited gas lift at the MRA Platform at 3.1 MMSCFD makes the production of wells at the MRA Platform not optimal because the wells in the MRA Platform are experiencing insufficient gas lift. Optimization of gas lift injection is obtained by redistribution of gas lift injection for each. The results of the analysis in this study indicate that the optimum gas lift injection for the MRA-2ST well is 0.5552 MMSCFD, the MRA-6 well is 1.0445 MMSCFD, the MRA-5 well is 0.7657 MMSCFD, finally the MRA-4ST well with gas injection. lift is 0.7346 MMSCFD. The manual gas lift in the MRA-4ST is also replaced based on an economic feasibility analysis to ensure that the gas lift injection for each well can be kept constant. The redistribution of gas lift carried out by the author has increased the total production rate of the MRA Platform by 11,160 BO/year or approximately USD 781,200/year. Keywords: Gas lift; Insufficient; Optimization

scholarly journals Optimasi Intermittent Gas lift Pada Sumur AB-1 Lapangan Brownfield

2018 ◽  
Vol 2 (1) ◽  
pp. 32
Author(s):  
Mia Ferian Helmy
Keyword(s):  
Pressure Gradient ◽  
Production Rate ◽  
Flow Rate ◽  
Oil Recovery ◽  
Gas Injection ◽  
Production Method ◽  
Production Flow ◽  
Injection Volume ◽  
Artificial Lift ◽  
Gas Lift

Gas lift is one of the artificial lift method that has mechanism to decrease the flowing pressure gradient in the pipe or relieving the fluid column inside the tubing by injecting amount of gas into the annulus between casing and tubing. The volume of  injected gas was inversely proportional to decreasing of  flowing  pressure gradient, the more volume of gas injected the smaller the pressure gradient. Increasing flowrate is expected by decreasing pressure gradient, but it does not always obtained when the well is in optimum condition. The increasing of flow rate will not occured even though the volume of injected gas is abundant. Therefore, the precisely design of gas lift included amount of cycle, gas injection volume and oil recovery estimation is needed. At the begining well AB-1 using artificial lift method that was continuos gas lift with PI value assumption about 0.5 STB/D/psi. Along with decreasing of production flow rate dan availability of the gas injection in brownfield, so this well must be analyze to determined the appropriate production method under current well condition. There are two types of gas lift method, continuous and intermittent gas lift. Each type of gas lift has different optimal condition to increase the production rate. The optimum conditions of continuous gaslift are high productivity 0.5 STB/D/psi and minimum production rate 100 BFPD. Otherwise, the intermittent gas lift has limitations PI and production rate which is lower than continuous gas lift.The results of the analysis are Well AB-1 has production rate gain amount 20.75 BFPD from 23 BFPD became 43.75 BFPD with injected gas volume 200 MSCFPD and total cycle 13 cycle/day. This intermittent gas lift design affected gas injection volume efficiency amount 32%.

Cable Thru Downhole Insert Safety Valve: A New Paradigm

2021 ◽  
Author(s):  
Kuswanto Kuswanto ◽  
Oka Fabian ◽  
Orient B Samuel ◽  
Mohd Yuzmanizeil B Yaakub ◽  
Chua Hing Leong ◽  
...  
Keyword(s):  
Safety Valve ◽  
Cost Effective ◽  
Submersible Pump ◽  
New Paradigm ◽  
Reservoir Properties ◽  
Technology Application ◽  
Artificial Lift ◽  
Water Cut ◽  
The Right ◽  
Gas Lift

Abstract The B Field is located in the South China Sea, about 45 KM offshore Sarawak, Malaysia, in a water depth approximately 230 ft. Its structure is generally regarded as a gentle rollover anticline with collapsed crest resulting from growth faulting. The reservoirs were deposited in a coastal to shallow marine with some channels observed. Multiple stacked reservoirs consist of a series of very thick stacked alternating sandstone and minor shale layers with differing reservoir properties. The shallow zones are unconsolidated, and the wells were completed with internal gravel packs. Wells in B Field mostly were completed in multi-layered reservoirs as dual strings with SSDs and meant to produce as a commingled production. The well BX is located within B Field and designed as oil producer well with a conventional tubing jointedElectrical Submersible Pump (ESP) system which was installed back in 2008. Refer to figure 1, the initial completion schematic is 3-1/2″ single string that consist of the single production packer, gas lift mandrel, tubing retrievable Surface Controlled Subsurface Safety Valve (SCSSV) and ESP. The production packers equipped with the feed thru design to accommodate the ESP cable and the gas vent valve as part of the ESP completion design. The gas lift mandrel was installed in the completion string as a backup artificial lift method to receive the gas lift and orifice valve in the event of the conventional ESP failed. Hence the well still able to produce by introducing the gas thru the annulus to activate the gas lift valve. Eventually throughout the end of the the field life, the well would depend on the ESP system for the primary lifting method due to gas lift depth limitation and the gas supply. The conventional ESP failed after seven years of operation which is above the average ESP lifetime. The well last produced at a flow rate with 28 % water cut, however the well is not at the end of the field life. Based on the economical study with the right technology and cost efficient approach, the well still economicaly profitable. The Thru Tubing (TT) ESP technology is approached as cost effective solution compare to fully well workover. Despite a couple of operational challenges, for example, setting the cable hanger, maintaining downhole barrier requirement, the Thru Tubing Electrical Submersible Pump Cable Deployed (TTESP CD) and Cable Thru Insert Safety Valve (CT-ISV) was successfully installed. Several post-installation findings have uncovered some problems which are requiring some additional technical and operation improvement for future similar applications. This paper will highlight the deployment of the Cable Thru Insert Safety Valve (CT-ISV) that was successfully installed as pilot, which is the first application in the world, and also highlights the success, lesson learnt and improvement for future requirement for the CT-ISV application as one of the solution for retrofitting completion application without jeopardizing the well integrity. This achievement is collaboration between Company and service partner as the technology and deployment under the proprietary scope. Further technology application, the replication of this insert safety valve was conducted and successfully deployed on other three wells.

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.

Innovations of Gas Lift in Prolific, Long-perforations, and Multilayered Wells, Case Study in Sudan

2016 ◽  
Author(s):  
Xueqing Tang ◽  
Lirong Dou ◽  
Ruifeng Wang ◽  
Jie Wang ◽  
Shengbao Wang ◽  
...  
Keyword(s):  
High Water ◽  
Water Breakthrough ◽  
Start Up ◽  
Production Wells ◽  
Decline Curves ◽  
High Water Cut ◽  
Water Cut ◽  
Gas Lift

ABSTRACT Jake field, discovered in July, 2006, contains 10 oil-producing and 12 condensate gas-producing zones. The wells have high flow capacities, producing from long-perforation interval of 3,911 ft (from 4,531 to 8,442 ft). Production mechanisms include gas injection in downdip wells and traditional gas lift in updip, zonal production wells since the start-up of field in July, 2010. Following pressure depletion of oil and condensate-gas zones and water breakthrough, traditional gas-lift wells became inefficient and dead. Based on nodal analysis of entire pay zones, successful innovations in gas lift have been made since March, 2013. This paper highlights them in the following aspects: Extend end of tubing to the bottom of perforations for commingled production of oil and condensate gas zones, in order to utilize condensate gas producing from the lower zones for in-situ gas lift.Produce well stream from the casing annulus while injecting natural gas into the tubing.High-pressure nitrogen generated in-situ was used to kick off the dead wells, instead of installation of gas lift valves for unloading. After unloading process, the gas from compressors was injected down the tubing and back up the casing annulus.For previous high water-cut producers, prior to continuous gas lift, approximately 3.6 MMcf of nitrogen can be injected and soaked a couple of days for anti-water-coning.Two additional 10-in. flow lines were constructed to minimize the back pressure of surface facilities on wellhead. As a consequence, innovative gas-lift brought dead wells back on production, yielding average sustained liquid rate of 7,500 bbl/d per well. Also, the production decline curves flattened out than before.

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