bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pursuing 1 % Loss Production Mature Oil Field Using Artificial Intelligent
Authors: Silaban Meita , Hasan Wahyuda Nur , Wibawa Ramdhan Ari , Ichsan Chairul , Alamsyah Yunus 
Published: October 2023

Abstract
Pursuing One percent Loss Production Opportunity with Artificial Intelligence in Mature Field X
Loss of Production is inevitable process of oil and gas operation including field X. Field X is a mature field that operates for over 50 years and currently operates with about 4% production loss due to well down. Most of well down or off due 2 major reasons: proactive job or intentional programs to improve well performance such as pump replacement, workover or stimulation and reactive job or unintentional well down due to pump failure, power outage, pipe leak, etc.
Current condition most of loss production is contributed from reactive well down due to pump failure. In fact the current failure rate is relatively low about 0.2/ year or in other words in average pump failure happens once in 5 years or about 1600 mean time between failure (MTBF).
Since the production in field X is part of top producers in Indonesia, 4% of loss is relatively intriguing since volume of oil loss is almost as big as production of a field in Indonesia. Historically, the 4% itself is a result of the long journey of effort and improvement. With high oil demand, will 4% is low enough or will 1% is achievable?
Simple method to assess the opportunity is to do comparative studies with analogue fields around the globe and statistical approach to review historical performance of field X including wedges for each reason of failure. A novelty method to assess the opportunity is by developing loss oil model with simple model and Artificial Intelligence approach. Artificial Intelligence Model is selected since the field already has historical big data that makes it visible to run. The result of assessment is then verified with its "doability", what kind of the circumstance or operation condition required to meet the potential improvement compare with existing condition is assessed and calculate the economic trade off.
Results show that field X shows possibility to achieve 1% with certain condition and surely extra cost and potential redundant resources. The economic assessment with future dynamic oil price will define true "doability" of getting 1% loss or answering the questions, should the company pursuing the 1%?
Maximizing Gas Resources and Monetization Through Gas Cap Blow Down - A Late Field Life Strategy for Sustainable Gas Supply in Peninsular Malaysia
Authors: Azman Mohd Fairuz , Mohamad Ruzlan Nur Syaffiqa , Basri A Hakim , Kumar Sanjeev , Tunku Kamaruddin Tunku Ahmad Farhan , Kosnon Nur Khairina , Salleh Khiril Shahreza 
Published: October 2023

Abstract
Field A is producing from natural depletion drive oil reservoirs with large gas cap. The field was under production curtailment, governed by gas-oil-ratio (GOR) limit to preserve the reservoir gas cap size. As the field continues to produce, the oil rate has declined while GOR increased exponentially. The reservoirs were at risked of being idle when the existing producers were forced to be shut-in due to GOR limit. This paper provides an insight of a late field life strategy in turning reservoir management constraints into business opportunity for more sustainable and economical domestic gas supply in Peninsular Malaysia.
Firstly, a temporary GOR relaxation was obtained with an objective driven data acquisitions were in place to monitor the reservoir performance. Concurrently, a Recovery Factor (RF) benchmarking study has also been conducted to identify for any infill oil development potential. A network model comprises reservoir, well and surface facilities constraints was developed, validated and history matched using the latest production and reservoir pressure data obtained. Subsequently, production sensitivities analysis was conducted at various GOR limit including gas cap blow down (GCBD) option, evaluated at different abandonment pressure to determine the best integrated field optimization opportunity.
Reservoir performance analysis during the temporary GOR relaxation confirms the oil production was not significantly impacted, the water cut remains stable, and the pressure depletion was minimal. The field RF has also exceeded the benchmark from other reservoirs with similar complexity and drive mechanism within the region. Hydrocarbon in-place validation suggests that neither oil infill development nor behind casing opportunity presence as the reservoirs has reached its optimum recoverable volume. Producing the field without GOR limit increases the RF of gas by 10% and continues oil monetization by another 2%, without risked the reservoir from being idle. In view of reservoir performance and critical high gas demand in Peninsular Malaysia, a decision was made to revise the production strategy to GCBD mode.
A prudent reservoir management demands a continuous, integrated, and dynamic process to maximize value from a reservoir over time. Production strategy should be revised upon new data becomes available from reservoir surveillance. The findings are critical in making timely recommendations on subsurface exploitation to deliver business needs for maximum value creation.
Investigating Water Trapping Effects During Tertiary Gas Injection in Mixed-Wet Rocks
Authors: W Razak W N Adyani , Kechut Nor Idah , Krevor Samuel 
Published: October 2023

Abstract
Gas trapping induced oil recovery has been explored in the past and has known to have occurred particularly in water-wet systems during tertiary gas injection. As the gas is the most non-wetting phase in a three-phase system (water-wet), the gas notably has the highest capacity to get trapped within the pore space. However, trapping of the intermediate wetting phase (i.e., water in a mixed-wet system during three-phase flow) is also possible and can be quite substantial under certain circumstances.
In this work, we have carried out three displacement experiments on mixed-wet Berea rocks utilizing X-ray microtomography to assist visualization of pore scale mechanisms and fluid occupancies in order to illuminate the potential trapping of the intermediate wetting phase during tertiary gas injection. The experiments began with waterflooding followed by gasflooding and another waterflood on mm-scale sandstone cores. Mixed-wet rocks were aged with crude oil for 40 days and were initialized with different connate water saturation ranging between 0.15 to 0.18 fraction. The oil-water contact angle measured manually during waterflooding ranged around 100 to 130 degrees.
During gasflooding in mixed-wet rocks, water occupied all pore sizes, instigated by the double displacement mechanism of gas displacing oil, that in turn displaces water. We also observed a significant water trapping in large pores, leading to the gas invading the pores via squeezing in between oil and water phases. Water trapping also increases the oil recovery. Hence, an engineering design to optimize the water trapping during tertiary gas injection will significantly stimulate the incremental oil recovery in field development projects. The outcome of this research will influence the method to model the hysteresis of water relative permeability for mixed-wet rocks.
A New analytical Model for Production Data Analysis in Horizontal Wells of Tight Gas Reservoirs
Authors: Li Zhe , Hu Lianbo , Xie Yonggang , Zhou Changjing , Ma Zhanguo , Liu Jiaxin , Sun Zhankun , Li Gexuan , Dong Peng 
Published: October 2023

Abstract
The evaluation of estimated ultimate recovery (EUR) in tight gas reservoirs holds paramount significance within the domain of unconventional oil and gas development. However, the accuracy of EUR prediction using traditional decline models is hampered by the complexity of the percolation environment after the compaction of tight sandstone and the limitations of commonly employed models.
This paper proposes a new and rapid EUR evaluation method for tight gas reservoirs based on production data analysis (PDA). First, an improved model is utilized to fit the production dynamic history, enabling the determination of reservoir and fracture parameters. The introduction of the rate-normalized pressure (RNP) technique reduces the occurrence of multiple solutions during parameter inversion, simplifies the calculation of the linear flow parameter [(LFP= total fracture area × square root of permeability)], and facilitates the estimation of EUR through productivity simulation. Secondly, to validate the reliability of the proposed method, an application analysis is conducted using the Sulige gas field as a case study.
The results demonstrate that the LFP and EUR of the JA well are 1196.09 m2·md0.5 and 3.17×107 m3, respectively. Furthermore, the EUR range of four representative wells is examined, revealing an actual range of 1.98×107 m3 to 4.77×107 m3, while the EUR range obtained through linear analysis is 2.00×107 m3 to 5.07×107 m3, with relative errors of 1.10%, 3.50%, 6.30%, and 1.05%, respectively. The average error remains within 5%. Additionally, correlation analysis conducted with over ten typical wells confirms a positive correlation LFP with EUR. In conclusion, this paper presents a novel and efficient methodology approach for predicting production and estimating ultimate recoveries in shale gas wells. By overcoming the limitations of traditional decline models, the proposed method offers improved accuracy and reliability in EUR evaluation.
These findings enhance our understanding of EUR estimation in tight gas reservoirs and contribute to informed decision-making in the development of these valuable energy resources.
Attic-Oil Zone Redevelopment to Improve Oil Recovery in Almost Watered-Out Reservoirs: Baturaja K-S Case
Authors: Arnold Richard , Malau Aldani , Ardan Cesti , Ultra Dian , Saib Elsa Fitrani , Aryanto Agus , Lazuardi Hilman , Hidayat Azis , Hidayat Saras Noer 
Published: October 2023

Abstract
The reservoirs developed in this work, BRF-KS, are giants in size, complex, highly mature, carbonate reservoirs undergoing waterflood. Given the long history of production and waterflood into the reservoirs, a key focus in the development philosophy was to maximize oil recovery using existing wells. Prior to this initiative, BRF-KS had reached a recovery factor of 38% with an already very high watercut of 98%. Due to being almost watered-out, a breakthrough was of utmost importance to extend the field’s life. It was predicted that many of the existing wells still have significant low-hanging oil behind casing, especially in the attic zone.
The key to rejuvenating these dark-brown reservoirs was through the redevelopment of the attic zone by performing shift-up and change-layer workovers. The campaign was started with a successful saturation logging job that located the presence of attic oil in Well-188, resulting in a production rate of &gt; 200 BOPD after the zone was opened. This milestone was followed by a comprehensive and structured geological, petrophysical, engineering, and well integrity review of hundreds of the existing wells. Overall, 28 primary candidates were identified and proposed. To date, twenty-six jobs have been conducted, yielding encouraging results.
In general, the project was able to locate and unlock the attic oil, resulting in exceptional oil gain. The most phenomenal gain was achieved in Well-222, which produced an initial oil gain of more than 1200 BOPD after unlocking the preserved attic oil. Another historic output was observed in Well-362, where the watercut reduced from 99% to ~0%, resulting in an oil gain of more than 200 BOPD. In other wells, production enhancement was achieved while maintaining a relatively constant watercut. Overall, the ongoing campaign has enabled a production improvement with a maximum gain of 1210 BOPD, average initial well-by-well gain of 63 BOPD, and a reserve addition of 3.81 MMSTB. The remaining candidates are expected to contribute to these figures.
This paper elaborates on the journey of the past two years of the attic oil redevelopment campaign conducted in BRF-KS. The fit-for-purpose approach reported is applicable to a wide range of reservoir conditions, especially in brownfields at a very high watercut stage and under a low-oil price environment.
An Experimental Method for Measuring the Three-Phase Relative Permeability of Oil, Gas and Water By Nuclear Magnetic Resonance
Authors: Chang Jiajing , Song Zhaojie , Ji Bingyu , Han Xiao , Song Yilei , Pu Wanfen 
Published: October 2023

Abstract
The three-phase relative permeability of oil, gas, and water place a significant practical emphasis in the study and evolution of compact sandstone condensate gas traps. However, most investigations on itare relied on forecast patterns that make an effort to appraise it from the relative permeability of two phases. We have measured it of artificial dense sandstone core by online NMR tests.
Firstly, the extracting of tight sandstone condensate gas reservoirs was mimicked using a steady-state flow toward, and crude oil, nitrogen and formation water were injected into tight sandstone simultaneously at room temperature according to the variation mechanism of reducing gas injection, and increasing water and oil injection. Secondly, the three-phase saturations were obtained by the different partition of oil-water phases in the 2D T1-T2 spectrum and the volume balance method. Finally, the relative permeability of three phases under various saturations was determined based on Darcy's formula.
The findings indicated that in the 2D T1-T2 spectrum, the aqueous phase was mainly concentrated at the position where the T1/T2 ratio was 1, and the oil phase was mainly concentrated at the position where the T1/T2 ratio was greater than 1. Compared with the T2 spectrum, the T1 spectrum could effectively distinguish the oil and water phase, and their boundary was about 10 ms at the T1 relaxation time. The relative permeability of each phase exhibited a trend toward decreasing over time as gas injection decreased and water and oil injection increased. The relative permeability of the water phase dropped, albeit not as much as that of the oil-gas phases. The relative permeability curve of three phases was convex to the point where the oil saturation was equal to 1.
As a result, the relative permeability of the gas-oil phases will be significantly impacted within the mining period of tight sandstone condensate gas accumulations when a little amount of condensate water arrives in the reservoir. Therefore, it is necessary to take measures to reasonably control the precipitation of water in condensate gas reservoir. In order to better understand the three-phase relative permeability, an innovative study has been conducted. And its results can more accurately predict and guide the production of condensate gas reservoirs.
Compositional Modelling of Enhanced Oil Recovery Using Dimethyl Ether-Enhanced Carbon Dioxide Water-Alternating-Gas Process
Authors: Choi Yoojin , Seo Kwangduk , Lee Kun Sang 
Published: October 2023

Abstract
This study investigated the effect of dimethyl ether (DME) that was mixed with CO2 to improve of oil recovery in the heterogeneous reservoir. Dykstra-Parsons’ coefficient (VDP) was used to quantitatively represent the heterogeneity of reservoir. Changes in vertical sweep efficiency and displacement efficiency were observed through oil viscosity, swept area, and oil saturation. When the same volume of solvent injected, the slope of the front of the swept area increased by about 1.6 times when the DME content is 20% compared to only CO2 is used for the homogeneous reservoir and increased by about 1.4 times for the most heterogeneous reservoir, VDP=0.79. At breakthrough, the swept area increased by up to 17% for the homogeneous reservoir and up to 7% for the most heterogeneous reservoir, confirming that the more heterogeneous the reservoir, the lower the sweep efficiency increase effect of DME. At the end of the WAG process, the area in which the remaining oil saturation was 0.6 or more increased significantly in the heterogeneous reservoir. Oil recovery improved by about 21% from 58.4% when only CO2 was injected, to 70.5% when the DME content was 20% for the homogeneous reservoir and improved by about 11% from 40.5% when only CO2 was injected to 45.1% when the DME content was 20% for the most heterogeneous reservoir. Since DME is an expensive solvent, the NPV maximization scenario was calculated in consideration of different oil prices and solvent reuse. Without considering solvent reuse, if the oil price is $30/bbl, NPV is negative due to the high DME price even though the oil recovery is high if only DME is used. When the oil price is 90$, NPV has a maximum value of $571,071 when the DME content is 1%, and when the DME content is 20%, it has a maximum value of $852,054 when the DME content is 20%. Considering solvent reuse, NPV is maximum at $884,751 when DME is 38% in homogeneous reservoirs for oil price $90/bbl and maximum at $581,986 when DME is 16% in most heterogeneous reservoir.
Multi-Dimensional Acid Fracturing on Deep Carbonate Reservoirs of Yanchang Oil Field: A Case Study
Authors: Liu Gang , Ma Zhongguo , Huang Deshun , Zhao Zhoumin , Wang Zichao , Gao Yamei 
Published: October 2023

Abstract
Acid fracturing is an essential technology for the efficient development of oil and gas reservoirs containing carbonate. However, in the case of deep and ultra-deep marine carbonate oil and gas reservoirs, existing acid fracturing technologies are unable to create a complex fracture network due to engineering and geological characteristics.
To efficiently and economically develop carbonate reservoirs in the Majiagou Formation of Yanchang Oilfield (China) and achieve efficient three-dimensional development of deep carbonate reservoirs in Yanchang Oilfield, the difficulties in acid fracturing such reservoirs are revealed based on the engineering geological characteristics of deep marine carbonate reservoirs in China. With the goal of achieving efficient three-dimensional development of this type of oil and gas reservoir, the concept of multi-dimensional acid fracturing is proposed, taking full advantage of technologies such as spatial fracture-network-formed fracturing and deep acid fracturing. The technical connotation is clarified, and the key technologies involved are described in detail. After field application of this technology, breakthroughs have been achieved in both acid fracturing technology and high post-frac production effectiveness. The research results of this paper indicate that:
The multi-dimensional acid fracturing involves three aspects: selecting the appropriate acid deep penetration technology based on the reservoir type to fully fracture the reservoir, creating complex acid fracturing fracture bodies with high conductivity under high closure pressure, and strategically deploying acid fracturing fracture bodies along long well sections to maximize well productivity in the wellbore direction.
This paper presents research on multi-dimensional acid fracturing technology based on reservoir characteristics in the Majiagou Formation. This includes building a 3D acid fracturing geologic model based on analysis of logging data and laboratory testing to predict effective etched fracture length, optimizing high slow-reacting acid, controlling acid etching fracture morphology, optimizing acid fracturing parameters, and developing uniform acid distribution technology for long interval reservoirs in horizontal/highly deviated wells. The proposed acid fracturing technology for the Majiagou Formation of the Yanchang Oilfield has significantly better field application effects than previous acid fracturing technologies and is of important guiding significance to the stimulation and production of carbonate reservoirs in the Yanchang Majiagou Formation.
Artificial Intelligence based High GOR Well Control Process Technology
Authors: Panuganti Sai Ravindra , Khanifar Ahmad , Wei Tan Nian , Castillano Eugene , Law Hiu Ying , Thant Maung Maung Myo , Sahak Muhammad Zakwan B. M. , Lin Catherine Tang Ye 
Published: October 2023

Abstract
The aim of this work is to develop and perform proof of concept on a digital process technology for real time gas production control from wells with gas coning or high gas oil ratio (GOR) problem. If proven successful based on the pilot trial designed here, full field deployment on all candidate oil wells will be carried out with this technology in a later phase of the project.
This Artificial Intelligence based High GOR Well Control (acronym iGOR), technology encompasses the following. Design of a real time well GOR control system based on smart algorithm. The control solution will prevent high GOR/gas breakthrough, thus minimizing gas production without or minimal impact to oil production rates.Optimize well performance by executing real time well control considering changing well condition. The control solution allows for early detection and response to changing well conditions, and thus maximizing liquid production.
The fundamental technology of measuring pressure drop across a restriction and using it to control flow stream is not new. However, the application of this for controlling well production, GOR and sub-surface drawdown is unique. Hence the need to prove iGOR technology for robustness before integrating with existing infrastructure. The current operation in Field B is presented and gas breakthrough control concept is explained. The closed loop process control narrative of iGOR is presented with the AI advisory. The ability of iGOR technology to control GOR in production against several case scenarios is validated using dynamic process simulation in candidate wells. For pilot trial, functional specifications are defined.
The iGOR technology supports upstream oil and gas industry initiatives to deploy digital and automation technology in achieving operating expenditure reduction, unplanned production deferment prevention and maximizing production from fields.
PHR WK Rokan Digital Transformation Journey
Authors: Setiabudi Triatmojo Rosewanto , Firdaus Mohammad 
Published: October 2023

Abstract
Upstream business digital transformation is critical in managing PT. Pertamina Hulu Rokan (PHR) Wilayah Kerja (WK) Rokan also known as Rokan field’s operation and production. PHR WK Rokan oil fields consist of brownfield areas with thousands of wells. Major initiatives and operations took place in arresting production decline and increasing productions with infill drilling programs, workover[CT1], well interventions, and future Enhance Oil Recovery (EOR) projects. Operation challenges nowadays could be answered, one of them, by capturing digital solutions from current technology disruptions.
Industry 4.0[CT2][MF3] opens the opportunity to improve decision making, business optimization, cost efficiency, and operational excellence (Rinalducci 2023). Applying advanced technology such as Artificial Intelligent Machine Learning, Data Science, Robotic Process Automation, Mobility, Web Applications, Data Integration, Data Foundation, Agile approach, etc., to transform conventional upstream business processes to digital based process is crucial to keep upstream business stay competitive.
PHR team currently is on a journey to digitalize business process on each function from Drilling Completion, Asset Development and Exploration, Facility Engineering, Operation, Maintenance to Hydrocarbon Transportation, along with all supporting functions as whole business value chain. This digital journey addressed business driver thru people, process, and technology that applied to key area of digital oilfield which are: application and data management, workflow automation, remote sensing technology, collaboration, governance, and visualization.