bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving Water Injection Pump (WIP) Reliability through Integrated Water System Evaluation in XYZ Field
Authors: Priambudi Aris , Machfud Adam Aliyya 
Published: October 2023

Abstract
XYZ Field in Central Sumatra is the largest waterflood operation in Southeast Asia. Water Injection Pump (WIP) is the critical equipment to enable this waterflood operation to maximize the oil production process. Based on WIP performance evaluation in Jan 2017 – Jun 2018, it was found that the average WIP reliability was 92.5% and average Loss Production Opportunity (LPO) was 268 BOPD. The contributing factors for this poor WIP performance were not only from the internal WIP unit but also from its external system.
Integrated Water System Evaluation was introduced to improve WIP performance to its desired level and to minimize LPO impact. From the internal system, the evaluation was started by analyzing the failure mode for each 78 WIP's, finding root causes, and developing mitigation plans to prevent failure from re-occurring in the future. It was found that there were 8 WIPs in low-efficiency condition and 7 WIPs operating outside the Best Efficiency Point (BEP). The evaluation was continued to the external system which consists of water injection line network and water injection well (WIW). It was found that the WIP discharge pressure was increasing from 700 PSIG up to 780 PSIG in all XYZ field areas. The main root causes were unbalanced water distribution and several WIW's being off due to various reasons.
Based on comprehensive analysis of the XYZ Field water system, it was recommended to perform the following actions to improve the WIP Performance: 1) Perform a proactive overhaul program for 8 WIPs with low-efficiency issues, 2) Adjust the Control Valve opening to ensure WIP operates within BEP, 3) Develop recommended discharge pressure setting range for each WIPs, 4) Re-POI (Put on Injection) inactive WIWs, 5) Perform fluid dispatching to balance water distribution in XYZ Field areas, such as transfer 100,000 Barrels Fluid Per Day (BFPD) from Area 4 to Area 6, transfer 55,000 BFPD from Area 5 to Area 4, and isolate interconnection between Area 1 and Area 3.
After implementation, there are some improvements as follows: 1) The range of WIP within BEP was increased from 37% to 62%, 2) WIP Reliability was increased from 89% (Jan 2017) to 96% (Jul 2018), 3) LPO due to WIP failure was decreased from 268 BOPD to 42 BOPD, 4) Average WIP discharge pressure was decreased from 780 PSIG to 700 PSIG. To sustain these improvements, the WIP performance monitoring flow process and tools have been developed. In recent years, when Company established aggressive programs to increase oil production, we experienced a similar condition that impacted WIP performance. But by having the sustained flow process and tools, we can manage the situation well and prevent major LPO and reliability incidents.
Well Design for Sustainable Field Development Plan Towards Achieving Net Zero Carbon Emission by 2050
Authors: Musa Muhammad Idham Adli , M Dan Iliyas , M Garib Nurul Iffah , M Safari Lai Harni Farihah 
Published: October 2023

Abstract
New field development operation and hydrocarbon production have been one of the main contributors to global carbon emission. With the introduction of carbon tax, the cost of developing new fields and hydrocarbon production is expected to increase significantly if no serious action is taken to address the carbon footprint from such activity, especially in the high Carbon Dioxide (CO2) field. This paper will share on the sustainable development concept undertaken by PETRONAS to address the future of Net Zero Carbon Emission (NZCE) by 2050 during field development planning of a high CO2 hydrocarbon reservoir and the approach in realizing the plan.
Surface facility is designed to filter all the CO2 in the hydrocarbon production at offshore CPP (Central Processing Platform) and re-inject it back into the formation via a dedicated gas injector well. The well placement is carefully analyzed to be located at area where the injected CO2 gas can enhance the hydrocarbon recovery by maintaining the reservoir gas cap pressure. CO2 gas also can be used as a source of gas for oil producer wells that require gas lift. PETRONAS had established a process flow during well detail engineering design to guide the project team that consists of Subsurface and Facilities to find the right balance in addressing the risk of CO2 related well integrity issues and project economics outcome. Part of the process flow involves the sensitivity analysis of reinjection gas specification downstream surface compressor at CPP impact towards well casing and tubing material selection, CO2 plume migration and estimating reservoir condition at the end of field life.
This established process flow managed to effectively guide the FDP (Field Development Plan) team to come out with the best cost-effective development concept that able to realize both company ambition of sustainable field development plan toward net zero carbon emission and projecting positive economic result.
This paper would provide more insight into the study and analysis to be considered during designing new wells in a field that integrate development wells producing hydrocarbon and Carbon Capture & Storage (CCS) CO2 wells with lesson learnt and best practices that are valuable for future project with similar scope.
Chemically Enhanced Carbon Dioxide Geosequestration Using Nanofluids
Authors: Jha Nilesh Kumar , Kitagawa Hirotake , Abe Masashi , Sonoda Takashi , Murakami Satoru , Farrokhrouz Mohsen , Keshavarz Alireza , Iglauer Stefan 
Published: October 2023

Abstract
Carbon dioxide (CO2) sequestration in the subsurface porous geological media is the most favored large-scale climate change mitigation technique to achieve a net-zero target. The efficiency of CO2 subsurface storage depends on its rock's wetting ability, which affects its flow efficiency and residual or structural trapping. Reported laboratory investigations have shown that nanoparticle formulations have great potential for altering the wettability to more water-wet conditions favoring CO2 trapping potential. However, the compatible nanoparticles tailored for CO2 sequestration under temperature, pressure, and salinity conditions have not been reported, as per our knowledge. Therefore, this article demonstrates how modified silica nanoparticles affect the rock's surface and help enhance CO2 trapping potential under storage conditions using wettability, IFT, and CT coreflooding experiments.
Several silica nanoparticles were fabricated for this purpose. The fabricated silica nanoparticles were modified, given the unfavorable formation brine salinity and ionic compositions affecting their stability. The resulting modified silica nanoparticles were diluted to 0.5 wt% with synthetic brine and observed for brine resistance at 50 °C for one month. They were further tested for wettability alteration of the organic acid-aged sandstone rock representative substrate in the presence of supercritical CO2 at 50 °C and 10 MPa by contact angle method. Furthermore, we evaluated their performance by computed tomography (CT) coreflooding experiments using Fontainebleau sandstone core plugs.
These nanoparticles altered the wettability of the organic acid-aged sandstone rock representative substrate sample from intermediate wet (advancing brine contact angle - 90-108°) to strongly water wet (advancing brine contact angle - 33-49°). Modified silica nanoparticles also show high brine resistance. Therefore, up to 24.2% reductions in IFTs were observed using nanoparticles. Moreover, CT coreflooding test results shows good performance of novel nanofluids treatment on CO2 trapping potential through evaluation of initial and residual trapping. Therefore, up to 80.6 % and 55.8 % increments were observed using nanoparticles in initial and residual scCO2 saturations, respectively.
We are reporting the use of novel modified silica nanoparticles for CO2 sequestration in sandstone formation for the first time, as per our knowledge. We expect these specialty nano-materials to enhance CO2 storage capacity through nanofluid injections as one of the emerging techniques for achieving net zero.
Casing Conductor Installation with Auger Drilling to Secure Uncompacted Surface Formation
Authors: Gibran Kemal , Ritamawan Radianto , Saragih Anggi Muhammad Sabri , Wicaksono Nuring Tyas , Malik Mahamy Abdul , Prestywa Ryan Hera , Khasbianto Fuji 
Published: October 2023

Abstract
There are two main hazards in surface hole section in Mutiara and Pamaguan fields, loss circulation and shallow gas. Blowout incident due to both hazards occurred in Pamaguan in 2012. While influx was moving, the conductor shoe was unable to withstand the differential pressure and cracked due to influx coming up through weak area around conductor shoe (broaching). Hence conductor must be set deeper to make sure the shoe is strong enough to withstand the pressure in case any occurrence of unscheduled events.
Independent Well Integrity Assessment Team (IWIAT) recommends minimum conductor depth is 250 ft. In Mutiara and Pamaguan Fields, conductor piling limited to 250 blow/ft can reach an average depth of 50 ft below ground level. It is either additional surface casing must be run or new method must be used. One of the methods that might potentially be used is auger drilling which has been used in construction industry to install conductor as a base foundation until 450 ft depth with max 59″ diameter. To implement this in field with loss circulation and shallow gas hazard (later known as dual hazards), modification of procedure is needed by adding sequences before auger drilling. Pilot slim hole drilling complete with diverter, kill mud and LCM were prepared to mitigate these dual hazards prior to enlarge the hole with auger.
Auger drilling with above mitigation is well proven and thus most reliable method to reach minimum 250 ft in depth. It is the safest method since pilot slim hole is drilled using mini diverter prior to enlarge hole with auger. Auger drilling method also eliminates surface loss circulation during rig operation in shallow and uncompacted formation, casing collapse due to driven to refusal in order to reach required depth, and other subsequent well NPT that might happen in surface section. Using auger drilling to install conductor can eliminate the needs to drill additional surface section and set additional surface casing by rig to strengthen the conductor section. Saving 1 section means 3 days faster on drilling operation which means cost reduction, eliminate operational risk in surface section, and opportunity to reach deeper TD. With this saving days, one additional well can be delivered in one-year operation in Mutiara and Pamaguan Field.
Economic Evaluation for Potential CCUS Integration Project Between Ammonia Plant and Oil Field Tertiary Recovery Using CO2 Injection in Indonesia
Authors: Raksawiguna Matahari Dewa , Wirananda Mohammad Farrel , Yasmin Kharisma Asri , Chandra Steven 
Published: October 2023

Abstract
Indonesia is committed to reducing global greenhouse gas emissions, especially in the industrial and energy sectors. One of the big opportunities is implementing carbon capture, utilization, and storage (CCUS) in Ammonia production as it has the lowest overall CCUS cost and geographically the existing ammonia plant is strategic to the potential oil field. This paper discusses the economic evaluation for the CCUS integration project between an ammonia plant and oil field tertiary recovery using CO2 injection, along with the sensitivity analysis of the economic variables. The selection process of a potential oil field that will be injected is based on the characteristic of its reservoir and its production performance. Furthermore, the distance between the oil field and the existing ammonia plant is also considered to minimize the transportation cost of CO2. The study of economic model contract for ammonia plant constructed by cashflow analysis. While for the Oilfield CO2 Injection project refers to Indonesia's existing oil and gas contract model, which is the Production Sharing Contract (PSC) cost recovery and gross split. In addition, several economic variables sensitivity was performed, such as oil price, oil production rate, capital expenditures, operation expenditures, and CO2 price.
Economic evaluation from ammonia plants and oil fields shows fairly good economic indicators. The economic parameter for the ammonia plant gives 13.54% of IRR, 661.95 MMUSD of NPV, and 6.19 years of pay-out time. On the oil field side, the PSC Cost Recovery scheme offers the contractor 18.82 % of IRR, 0.33 MMUSD of NPV, and 4.85 years of pay-out time. In comparison, the PSC Gross Split scheme offers 19.55% of IRR, 0.40 MMUSD of NPV, and 5.48 years of pay-out time. For this study, the result indicates PSC Gross Split scheme gives a better economic parameter than PSC Cost Recovery. The sensitivity analysis shows that oil prices and capital expenditure are very significant on economic parameters. Therefore, government policies are required to give contractors more attractive economic parameters. Based on the economic evaluation, implementing CCUS in the small field gives a fairly good result for economic parameters. Furthermore, this paper provides a comprehensive assessment based on an economic evaluation of the ammonia plant and oil field that could give additional information to the government as the policy maker to accelerate the implementation of CCUS integration, particularly in small fields in Indonesia.
Mini-ROV Utilization for Banyu Urip FSO Underwater Inspection and Maintenance
Authors: Jayatra Kharisma 
Published: October 2023

Abstract
The objective of this paper is to evaluate the use of a mini-ROV (Remotely Operated Vehicle) for conducting intermediate Underwater Inspection in Lieu of Dry-Docking (UWILD) surveys as well as various underwater inspection & maintenance works in the Floating Storage & Offloading (FSO) Gagak Rimang (turret-moored FSO) operated by ExxonMobil Cepu Limited (EMCL).
UWILD is divided into Intermediate Survey & Special Survey which differs in scope. Intermediate UWILD Survey consists of General Visual Inspection, Cathodic Protection (CP) readings on offshore vessel's hull, weld inspections, and marine growth assessments. Meanwhile, Special Survey includes all the Intermediate Survey scope with additional sea-valves internal & external examination and operational test. Typically, the UWILD inspection utilizes conventional method by using divers and/or work-class ROV which require dive support vessel. With two underwater campaigns every five year – it is considered an operational challenge for offshore vessel to optimize cost since in many countries the drydock / UWILD requirements are tied with government regulation.
EMCL demonstrate initiative of mini-ROV utilization for Intermediate UWILD Survey on FSO vessel, namely Gagak Rimang. The mini-ROV was trialed as it has the capability to perform comprehensive inspection as well as cleaning with minimum cost.
The use of the mini-ROV was successful in completing the intermediate UWILD survey pioneered in 2022. The ROV was able to access and inspect areas that would have been challenging or implausible for divers to reach, such as the underside of the platforms and tight spaces between structures. In addition, the use of the ROV eliminated the need for divers to enter the water, improving safety and reducing the cost and logistical challenges of diver-based surveys.
Compared with conventional methods, the utilization of mini-ROV has provided significant cost saving until the end of facility life. The first mini-ROV implementation in EMCL has demonstrated that its use is a feasible and effective alternative to conventional method for intermediate inspections of offshore vessels. Mini-ROV also provides one-stop solution by allowing mount-ability of certain attachment tools to enable cleaning & measurement works. The use of mini-ROVs can improve safety and reduce cost and logistical challenges, making them a valuable tool for the maintenance and integrity management of offshore assets.
Success Story of Pressure Network Optimization Application on Multi-Problem Surface and Subsurface Facilities Ardjuna Field
Authors: Setiawan Muchamad Agus , Saputra Diarista Toma , Abdul Goni Mochamad Jalal , Yusup Irvan Sopandi , Arifin Muhamad , Arifin Wirdan 
Published: October 2023

Abstract
Gas lift consumption and pressure need to be controlled so that oil and gas production in a well can be optimum. The 2020 FGS result shows tubing leaks in the MB-2 wells. Therefore, the gas lift injection cannot be optimum. Also, the MB-2 Production Separator is experiencing corrosion, and the operating pressure is only 74 psig. Oil wells in MB-2 Onshore will be optimum between 2,880 – 3,000 BFPD with gas lift pressure of 430 – 470 psig. However, when the pressure rises to 490 psig, production will drop to 2,640 BFPD, and when gas pressure drops to 400 psig, the oil production will only 2,568 BFPD. The operating pressure limit in the Production separator makes the Main Gas Line (MGL) operate below at 72 psig
The FGS results show that tubing leak/tubing communication conditions in the MB-2 well, the optimum injection gas lift is 4 MMSCFD with a pressure of 430 – 470 psig for all MB-2 wells. Currently, the MB-2 wells only installed Merla valves, making it difficult to maintain the stability of gas injection. Pressure networking optimization in the upstream part of the well is carried out by installing PCV on the MB-2 incoming gas lift. By applying Nodal Analysis simulation result, we get the data MB-2 production in November 2021 increase after PCV installation. The second pressure networking optimization uses Network Modelling Software simulation to determine the optimum pressure along the Main Gas Line (MGL) from the well to the compressor. MMF Turbine Gas Compressor speed increased from 93% to 96%, so the Main Gas Line (MGL) from the well to the compressor operates below 50 psig. This operating mode results in the low FTP (Flow tubing pressure) of each well and no back pressure on the MM wells. Moreover, the Production Separator's operating pressure can be kept below 72 Psig.
The pressure networking optimization by installing PCV at upstream MB-2 wells is proven to keep gas lift injection into each well stable in terms of flow rate and pressure. Furthermore, keeping the Main Gas Line (MGL) pressure below 72 psig can prevent the backpressure to the well and the operating pressure limit of the Production Separator is not exceeded. Pressure networking optimization can save gas lift consumption by 2 MMSCFD and increase production of MM oil and gas wells by 10% (27 billion rupiah per year). Stable injection gas lift & low Main Gas Line (MGL) pressure can increase the production of the MM well and achieve the annual production target.
Chemical Stimulation Success Stories – A New Integrated Process to Support Massive Aggressive Strategy in Complex Operation of World Largest Steam Flood Field
Authors: Terosela Andro , Etri Yulmi , Efendi Faried , Pramono Wasis 
Published: October 2023

Abstract
Drainage Field is the largest active steam flood in the world comprising 7,000 active producing wells, 1,250 steam flood patterns and encompassing 21,000 acres in the Sumatra, Indonesia. The Drainage Field produces 60,000 BOPD and 10,000 optimization jobs are executed annually to support base production. Drainage produces rich carbonate formation water and high asphaltene oil which generates solid deposition inside the wellbore due to high temperature exposure as an impact of steam flooding. Solid deposition extracted into carbonate scale and congealed oil would lead to plugging effect on influx from the reservoir into the wellbore, causing faster production decline. Chemical stimulation well intervention plays main role to improve well productivity by removing solid deposition in the wellbore. Aligning with the massive and aggressive strategy in Drainage Field, there are too many challenges in increasing the execution level like artificial lift assurance, location preparation, resource optimization, plant operation, and sampling analysis capability.
This aggressive scenario requires an excellent and integrated process in delivering effective well intervention program which managed by the following improvements:
Artificial Intelligence (AI) assisted well intervention candidate selection process. A systematic value-based well intervention schedule and prioritization process. Artificial lift assurance process. Effective well site readiness & preparation, include mitigating rainy season challenges. Comprehensive monitoring dashboard. Synergic resources support, i.e.: rigs, chemical pump, surface unload tank, vacuum truck, and heavy equipment support. Pre and post job fluid analysis supported by dedicated lab to optimize chemical unloading process. An integrated web-based tool to monitor the overall process of chemical stimulation well intervention job. Lookback process.
Value creation:
Multi-function collaboration effort i.e.: increased success rate by 70 %, reduced suspended execution by 70%, idle time by 30%, increase plant acceptance rate by 60%, and shorten acid unloading time by 50%. Increased job execution rate to ~200%. Improve Drainage field base production decline rate, ~15% better. Provides additional ~3.000 BOPD annual production gain correlates to 77 MMUSD additional revenue.
The effort contributes a significant impact in the way of company should run a massive activity strategy as well as providing an important value to company in optimizing performance.
Analysis of the Oil Distribution and Evolution Characteristics of Gulong Shale Oil Plays Using Nuclear Magnetic Resonance (NMR)
Authors: Xu Fei , Jiang Hanqiao , Zhou Kaihu , Wang Yong , Zhang Miao , Liu Ming , Li Junjian 
Published: October 2023

Abstract
The Gulong shale oil plays is a shale reservoir characterized by well-developed fracture bedding planes. To study the distribution and evolution characteristics of Gulong shale oil, namely, the size of the oil-bearing pores, the content of oil in organic and inorganic pores, and the oil distribution evolution during gas displacement, could contribute to the development of shale oil. In this study, the one- and two-dimensional NMR spectra were used for the above studies.
Two Gulong shale dry cores with different fracture bedding characteristics were tested in the experiments. NMR T1-T2 and T2 maps of the cores are scanned under dry and kerosene-saturated conditions. Gas displacement experiments were conducted under different injection pressures. NMR scans were taken at the end of each displacement stage. The oil distributions in the organic and inorganic pores were characterized through the T1-T2 maps. The oil distribution evolution under gas displacements in the shale cores were characterized by NMR T2 distributions of all stages.
The T1-T2 map results showed that the oil in organic and inorganic pores was presented in two distinct regions with different T2 value intervals. The oil in the organic pores were residual heavy oil components and saturated kerosene, which were distributed in small T2 value interval and different T1/T2 value interval. The oil located in the inorganic pores was mainly saturated kerosene. Mobile oil exists in the inorganic pores and was presented in the largest T2 value interval of all oil phases. The T2 distributions showed that there was a threshold pressure for gas displacement in the shale cores. The higher the gas injection pressure, the more oil could be displaced. However, once the pressure reached a certain value, further increasing the pressure would not further improve the oil recovery. Finally, it was found that the threshold pressure of shale cores without developed fracture beddings was higher, and the more developed the fracture was, the lower the threshold pressure was and the higher the oil recovery would be.