bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field
Authors: Al-Janabi Mohammed Ahmed , Al-Fatlawi Omar F. , Sadiq Dhifaf J. , Mahmood Haider Abdulmuhsin , Al-Juboori Mustafa Alaulddin 
Published: December 2021

AbstractArtificial 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.
Optimizing Location of CO2 Recovery Units
Authors: Dutt Indrajit , Allamaraju Jagannathrao 
Published: December 2021

Abstract
In line with ADNOC Sustainability policy, reduction of GHG emissions, AGP has initiated projects for recovery of CO2 from existing plants. The extracted CO2 is planned to be used for Enhanced Oil Recovery. The current paper highlights method used for evaluation of various location and technology options for implementation of the new CO2 recovery units, considering existing plants flow schemes along with their interfaces and associated challenges.
Key Performance Indicators (KPIs) were identified based on Inherent Safety, Economics, Technology Maturity, Product Quality, Operability / Flexibility, Constructability. Identified options were further developed and subsequently evaluated based on preliminary economic analysis and available technical information. Accordingly, weighted scores of the KPIs developed for option selection. Major criteria used for ranking were unit cost of CO2 product, adherence to required H2S and COS specifications, technology maturity and deployment in industry.For one location, the options considered included installation of new Acid Gas Removal Unit (AGRU) upstream of existing AGRU, revamp of existing Acid Gas Enrichment Unit (AGEU), new AGEU, and direct feed of Acid gas to new CO2 recovery unit to supplement falling upstream reservoir profile.For another location, the options included new CO2 recovery plant upstream of existing Sulphur Recovery Unit (SRU) or downstream of existing Tail Gas Treatment Unit (TGTU), compression of TGTU gases upstream of proposed CO2 recovery unit, installation of new unit downstream of existing incinerators, combination of CO2 recovery units of both plants, were also assessed.In addition, new CO2 Dehydration and Compression units considered to meet CO2 product specifications and B/L requirements.
Based on project requirements, physical methods of CO2 removal like membranes and molecular sieves deemed unsuitable. Further to discussions with various licensors, emphasis remained on chemical and physical solvent technologies. Based on assessment, solvent swap for AGEU (upstream of existing SRUs) with reduced lean solvent temperature at one location, solvent swap in TGTU followed by a new polishing unit at another location combined with common high pressure compression facility, was selected for engineering development.
Drilling Automation – Benefits of the New Drilling Model
Authors: Heredia Jorge , Tengesdal Jan Egil , Hobberstad Rune , Marck Julien , Kleivenes Harald , Ngueguim Marcel Emile 
Published: December 2021

Abstract
A pilot program for automated directional drilling was implemented as a part of the roll out plan in Norway to drill three dimensional wells in an automated mode, where steering commands were carried out automatically by the automation platform. The rollout plan also targeted the use of remote operations to allow personnel to be relocated from the rig location into remote drilling centers.
The goal of the program was to optimize the directional drilling performance by assessing the benefits of automation using the latest rotary steerable system technologies and machine learning smart algorithms to predict and manipulated the BHA performance, as well as the ability to predict the best drilling parameters for hole cleaning.
The automation was implemented on three different rigs and the data was compared with the drilling performance from the last two years, with three dimensional wells drilled in the conventional method.
The main benefits between drilling wells in the conventional method versus drilling wells with the new drilling automation model include the following.
Reduce the overall cost per meter –  Improve the rate of penetration –  Improve running casings Consistence process adherence –  Reduce human errors –  Reduce POB without sacrificing lost of technical experience Optimize workforce resources –  Allows continuity of service (COVID-19 restrictions)
Drilling automation can drill smoother wells by reducing the friction factors and tortuosity. This is translated in direct cost savings per meter and reduction in the overall well delivery time, with the advantage of performing the execution and monitoring of the well performance remotely.
This new drilling model open the door of new opportunities, especially for the challenges where the work force resources, and drilling performance is a priority for the operations.
Upgrade of Plate Heat Exchanger at Optimal Cost Through Core Pack Plate Welding Modification
Authors: Al Khoujah Khaled M. Mazen , Medina Antonio - , Al Qaydi Juma Rashid , Kaleem Jawwad , Al Mansoori Fatima Hassan , Nisar Muhammad , Lentz Markus 
Published: December 2021

Abstract
An innovative design was implemented as a solution for the repetitive failure of a plate heat exchanger installed at Gas Processing Facilitates due to weld cracking, the new design was introduced for the first time in the facility, demonstrating the novelty of utilizing new technologies and enhanced designs in Heat Exchangers used for gas processing. The main challenges were in accommodating various operating modes and ensure the prevention of reoccurrence of the failures. The success was achieved through the collaboration between the operating company and Industry experts in heat transfer equipment to replace the existing design at the gas processing Facilitates with no change in piping layouts, hence, performing the replacement at optimal cost and maximum benefit.
Maximize Asset Utilization by Effectively Identifying and Removing Bottlenecks
Authors: Nagwani Dheeraj , Al Katheeri Sara 
Published: December 2021

Abstract
ADNOC Gas Processing Ruwais NGL Fractionation plant receives and fractionates the NGL produced in upstream gas processing plants. After operation of newly designed upstream NGL plants, composition of NGL feedstock has become richer in Ethane and Propane. Consequently, nameplate capacity were reduced by~25%. In view of future increased NGL production, nameplate capacity of fractionation trains needs to be re-instated. Alternatively, a new fractionation train needs to be installed to accommodate additional NGL.
To explore the opportunity for maximum utilization for existing trains, in line with the ADNOC strategy of enhancing profitability and asset utilization, a technical study was conducted to increase the processing capacity back to original nameplate capacity with lighter NGL composition. This was to identify the potential bottlenecks in the facility and suggest debottlenecking options with a reasonable investment.
The Technical study covers the following activities:
Simulation:
Rigorous process simulation including the licensor units of DEO/Propane amine units
Adequacy checks and identification of bottlenecks: Line sizing adequacy check and detailed hydraulic evaluation of the major piping Equipment adequacy check Relief & blowdown and flare system adequacy check Proprietary equipment/design evaluation of licensed units Adequacy check for In-line instruments like control valves, flow elements/transmitters, thermowells Rotating equipment adequacy checks performed with the concurrence from OEMs. Licensor Endorsement: Obtained the endorsement of AGRU licensor (Shell) for the increased flow rate with revised contaminant levels with recommendations of removing identified bottlenecks. Bottlenecks mitigation: Various options for bottleneck mitigation was studied and most optimum solution was selected to remove the identified bottleneck.
The study has concluded that current capacity limitation was mainly due to bottlenecks in Ethane loop. Therefore, by mitigating the identified bottlenecks (i.e. replacing lines with bigger size, providing high performance trays, high performance internals, replacing few equipment's with new one etc.), the original nameplate capacity can be re-instated.
The study concludes that increased NGL forecasted flow with lighter composition could be processed in existing Ruwais fractionation trains by doing minor modifications (as compared to new train).
A capacity increase of ~25% was achieved with minimum investment and requirement of new fractionation train could avoided.
If extensive adequacy studies are carried out to identify the bottlenecks, the capacity enhancement in existing facilities can be achieved with minimum investment and major cost for new plants/trains can be avoided.
A Comparative Emissions Assessment - Drill Cuttings Treatment Alternatives
Authors: Innes Gareth , Nesse Steinar , Eia Jan Thore 
Published: December 2021

Abstract
The offshore industry has for many years been cognisant of its impact on the marine environment. Since 1991, strict regulations relating to oil-based drill cuttings discharge have been in force in the signature countries to the OSPAR (Oslo/Paris) Convention. As the impact of greenhouse gas (GHG) emissions on climate change has become better understood, global carbon dioxide (CO2) emission reduction targets and how to meet them have risen up operators’ agendas. Offshore operations, which involve marine logistics, are also subject to limits on nitrogen dioxide (NOx) emissions, an indirect GHG that's toxic to humans and contributes to soil and water acidification. The choices that operators make today in how they operate, including the disposal of drill cuttings, must therefore address an increasing number of environmental and climate targets, in addition to health, safety and cost.
This paper will outline the results of a comparative study between the offshore processing of drill cuttings and relevant conventional alternatives, including skip and ship, bulk transfer and cuttings reinjection (CRI). It is the first paper to show a direct emissions comparison between offshore processing and all other alternative methods for drill cuttings processing. The study assessed the carbon footprint and NOx emissions for each of the different alternatives for the treatment of drill cuttings. The values were then used to create an interactive emissions calculator that can be easily applied to specific projects to clarify the actual potential for emissions reduction within the drilling waste management process.
A number of case studies were then run, comparing the different alternatives. For the examples run, the comparative assessment showed that wellsite thermal processing technology was the favourable alternative in terms of emissions, with an emission reduction in the order of 14 - 48%, compared with the onshore alternatives. Emissions of the alternatives, skip and ship and bulk transfer, were highly dependent on sailing and road transport distances, as well as power source for the onshore treatment facility. The assessment showed that CRI has the highest emissions of CO2 per tonne of cuttings. Alternatives involving onshore treatment had the highest NOx emissions when sailing distance was high, however this was highly dependent on the machinery and fuel source of the transport vessel - and for the offshore alternatives, the on-site energy production solution.
First Successful Smart Liner Deployed in a Side-Tracked Gas Well, Offshore Abu Dhabi
Authors: Ladmia Abdelhak Mohamed , Alhammadi Hamdan A , Draoui Dr. Elyes , Mogensen Dr. Kristian , Al Hosani Fahad Mohamed.M , Edmonstone Graham , Aldhanhani Ahmed Mohamed , Ballaith Faisal Jamaan , Mohamed Ayman , Juvarajah Navindran 
Published: December 2021

AbstractThis paper presents a summary of the deployed Smart Liner- SL equivalent to the Limited Entry Liner- LEL as lower completion for the first time in a sidetracked Gas well, Offshore Abu Dhabi. R-1 is subdivided into several sub-layers, the reservoir properties are characterized by low porosity & low permeability (Tight). Reservoir quality in the Upper part is better in terms of porosity & permeability than the lower part. The gas production is mainly from top part of R-1 reservoir, no contribution from Lower part. In 2017, Data gathering was conducted on well A-1 (Coring, Logging & Pressure Points). Actual Gas production Offset wells are restricted from optimal production due to Well Integrity Sustainable Annulus Pressure, to compensate the restricted aged wells due to Well Integrity, Gas production can be increased to 3 times using SL as a stimulation method.The Smart Liner was selected as a lower completion and as a stimulation method for better flow distribution, improved well performance, effective Acid stimulation, also to ensure hole accessibility, allowing aggressive bullhead stimulation at high rate/pressure and high acid concentration at less time ~ 1.5days/job, in addition to eliminating high risk and high cost Coiled Tubing (CT) intervention for stimulation.The first step was to design the SL Completion Workflow with a representative well trajectory for the selected well to be fed and reservoir properties to be extracted from the dynamic model, and then to create a representative stimulation model utilizing property numerical software with all possible scenarios; open hole that represents PPL and suggested SL compartmentalization and holes distribution based on reservoir parameters along the lateral. Once the well model is created, different scenarios for different completion designs are to be run versus different acid concentrations and volumes till achieving the optimum results from stimulation point of view in addition to formation and facilities limitations. Drilling operations were very challenging; fortunately, we succeed to deploy the SL after final adjustment based on FMI Natural Fractures. The Smart Liner as stimulation has proved to be a cost-effective solution for gas wells comparing to advanced stimulation methods in addition to eliminating the high risk and high cost of the Coiled Tubing (CT) intervention for stimulation a huge savings in well construction with maximizing performance.
How a Single Field Development is Becoming a Hub
Authors: Felappi Francesca , Giovannini Simone , Giuliani Giovanni Matteo 
Published: December 2021

Abstract
The work presented in this paper shows how a single development evolved in a main Production Hub to unlock stranded resources, fast tracking subsequent marginal gas discoveries, by improving the flexibility of the subsea and treatment facilities. The approach was supported by a coherent activity about exploration program in the area, JV partnership and contracting strategy.
During the Execution phase of a subsea development, a new discovery was made in deep water, 35 km from the Floating Production Unit (FPU). Following this discovery, given the potential for further developments in the area (stranded gas reservoirs and further new gas discoveries), the decision of considering the FPU as a future Production Hub has been taken and FPU has been converted accordingly. The inlet facilities have been designed to guarantee the possibility of receiving well fluids at different pressure levels (high pressure for the new developments and low pressure for productions in depletion) with high production flexibility.
Several verifications have been performed to maximize the production flowrates at different pressure values, according to the envelope of data from exploration activities, via adequate arrangements for future expansion. These verifications considered the FPU as it is and with the implementation of minor and major modifications (including retrofitting offshore of new process modules). Design and timing of new equipment as minor/major brownfield modification have been set-up to cope with the modulate field profiles to keep FPU operating flowrate to its maximum value for longer time. In particular, the choice of new booster gas compressors has been planned, in order to select the best configuration for the most recent Hub development plan and to install them at the right time.
Converting a barycentric infrastructure in a Hub ensures a significant reduction of CAPEX for future developments (limited to subsea tie-backs only), allowing to reconsider projects previously evaluated economically unsustainable. Moreover, the Hub shall guarantee a long-term gas production by continuous addition of new discoveries in the area, making it an essential facility for the energy future of the Country.
The Benefits of Real Time Monitoring Application Artificial Lifting Parameter for Surveillance, Optimization, and Cost Reduction in Mature Field, Case Study Prabumulih Field
Authors: Fansuri Taufik , Miftah Akhmad , Parsaulian Sakti , Giyatno _ , Riviana Rina , Yanuardi Ayi , Mesia Putri Latissa , Taufik Suherman Andri 
Published: December 2021

Abstract
Prabumulih Field was located in South Sumatra, Indonesia. It has been developed as an oil field since 1920n (It was categorized as a mature field). At the end of 2019, the amount of oil well production was 149 wells (93% of the producing wells installed artificial lifting). As a consequence, to maintain production, artificial lifting surveillance activities must be a major concern and be managed properly. However, there are some challenges for surveillance, for instance, the location of well spread over a large area, the condition of the access road, and limited human resources.
Surveillance activity itself carried out manually required both much time and many human resources, however, acquired data was only once in a week for one well. That condition always emerged undesired occurrence because engineers who were in the headquarter did not obtain notification when producing wells were in trouble or suddenly off producing. In addition, there was a delay in time for evaluation and intervention, which resulted in decreased oil production. Nowadays, application, in order to accelerate the data retrieval process, was much needed, especially real-time acquisition and it could be monitored in several kinds of devices.
This paper will be presented about the benefit of real-time monitoring application in mature field, especially for artificial lifting well (ESP and Rod Pump). It has been installed since December 2019. There were several benefits obtained after installing this technology, those were related to surveillance and optimization. For instance, reducing time and human resources needed to obtained pump parameter data, engineers who are in the headquarter could observe everyday using both laptop/personal computer and smartphone, engineers obtained notification immediately when there were wells in a trouble, decision making for optimization and or intervention was faster, increase pump run life, and reducing well service program. Besides, there was another benefit that related to cost reduction, for instance saving rig costs for well service of 350,578 USD in a year because the amount of well service decreased from 49 times to 36 times, and obtained additional gross revenue of 547,945 USD for one year (cost for real-time monitoring for a year is 116,438 USD) because production deferment reduced from 19,577 STB to 5,105 STB. Based on those data, real-time monitoring could increase the economic condition of the mature field, so it was worth applying in a mature field.