bluuebunny/crossref_metadata_2025 huggingface dataset:
Self-Degradable Loss Control Pill to Arrest Fluid Loss During Workover of Wells in Depleted and Naturally Fractured Reservoirs
Authors: Qamruzzaman Mohammed , Roy Dhirendra Chandra , Raman Ravi
Published: October 2023

Fluid loss during workover of subhydrostatic wells is a major concern while servicing the wells in brown/matured fields. Excessive fluid loss results in delayed well activation, formation damage and extra cost due to extra rig days. Loss control by placing a loss control material (LCM) pill has been a well-practiced method to control the fluid loss within desirable limits. However, presence of natural fractures or vugs in the reservoir prevents the formation of filter cake and significantly hampers the performance of these pills. Additionally, heavy use of conventional loss control pills results in formation damage which significantly compromises the productivity of well post workover and requires stimulation job for its restoration. This paper presents a novel self degradable loss control pill consisting of a multi modal distribution of polylactic acid (PLA) in powder, fiber and granular form that is highly effective for plugging/sealing the natural fractures and minimizing the fluid loss. With time and under the downhole conditions, the pill slowly undergoes self degradation and hydrolyze into completely water-soluble products thus minimizing the formation damage. The degradation behavior of the pill has been evaluated and filter cake buildup and aging studies have been performed through core flooding to optimize the particle size distribution of the PLA powder. The filter cake properties have been evaluated through HPHT filter press and results have been compared with the conventional pill. Flow back studies have been carried out to evaluate the cleaning efficiency of pill post activation. Finally, the proportion of PLA powder, fiber and granules has been optimized through fracture plugging studies as per API RP 13I. Application of PLA based LCM pill for loss control during workover is relatively newer concept with limited number of publications describing its intricacies including the loss control material, particle size distribution and pill design. This paper contributes by bridging the existing gaps and providing important guidelines for design and execution of self degradable loss control pill.
Increasing 11,000 BLPD on Bekapai Mature Field with Minimum Facility Modification Using the Inter-Platform Gas Lift Combined with Integrated Gas Lift Optimization (PROSPER & Macro-Excel)
Authors: Suseno Alfiza Danistya , Rusdi Runi Kusumaning , Guciano Muhammad Fauzan , Garmana Iqbal Aprian
Published: October 2023

Bekapai field has been producing for almost half a century, entering the depletion of reservoir pressure phase without adequate artificial lift facility. The biggest challenge faced by Bekapai as a mature field was aging facility in coupling with depleted reservoirs pressure. Other artificial lift methods such as ESP, PCP or other pumps are not suitable for this field due to limited space, no power source and sandy well characteristics. In-situ gas lift injection method is then applied to boost oil production. But not every active platform has high pressure wells that can be used as gas lift source. Ideally, a well intervention (WLI) job will be performed to provide a gas lift source for each active platform. Since no WLI barge dedicated to Bekapai, it can only rely to the available gas lift source instead of intervening new wells candidates.

At the beginning of 2023, a new ultra deep well (BX-2.G1) located at MWP-BX platform has been found and successfully Put On Production (POP) with production parameters: WHFP = 100 bar, WHFT = 72°C, Qg = 7.5 MMscfd, Qo = 25 BOPD, Qw = 232 BWPD. Rely on its high pressure, BX-2.G1 was utilized as a gas lift source well to inject weak wells only at MWP-BX. Unfortunately, there is no gas lift source on the neighbor MWP-BY platform, which prevents weak wells from producing at their best.

To address this common challenge, a suggested approach is the implementation of inter-platform gas lift. This technique involves utilizing a gas lift source situated on a single platform to infuse wells located across various platforms. This leverages the pre-existing pipeline infrastructure that interconnects these platforms. The facility integrity assessments and engineering modifications is needed for activating inter-platform gas lift in mature field with aging facility. Inter-platform gas lift utilizes 6 inch of BX - BY production trunkline to become a gas lift distribution pipe apart from a redundant 12 inch trunkline.

After all inter-platform gas lift requirements have been met, gas lift optimization is required to ensure optimal well injection performance. An integrated optimization of gas lift injection rate is performed on a monthly well test and updated using PROSPER and a visual basic tool (macro-excel). The well is then redesigned with gas lift valves, which is timed to coincide with the well intervention campaign. These innovations increased Bekapai's liquid production by more than 11,000 BLPD.

Inter-platform gas lift is the best way to enhance oil production in the Bekapai field by utilizing the existing aging facility and low cost installation. In the future, this method is expected to be applied in other company fields.
A Decade of Learning from Design and Operations of the First Subsea Automated Pig Launcher (SAPL)
Authors: Sulong Mohd Faizal , Nasri Huang Farah Julieana
Published: October 2023

This paper will outline the key features, design considerations and technology qualification program of the first Subsea Automated Pig Launcher (SAPL) installed and operated in a shallow water field development since a decade ago.

Field K is located in one of offshore Malaysian gas fields. The average water depth at the subsea location is around 80 meters. The field deliver non-associated gas since 2012 to a Central Processing Platform (CPP). SAPL was designed to accommodate the frequent pigging requirement for the purpose of efficient pipeline liquid management in the gas condensate system. The pigging operations are also critical to facilitate batch application of corrosion inhibitor to protect its 24-inch Carbon Steel pipeline. SAPL was selected as the preferred technology since it allows for single pipeline configuration from the subsea wells, as compared to dual loop pipeline that would impose additional CAPEX for the development. Pigging operation via downline from the vessel was eliminated due to less economically attractive proposal.

For the past 10 years, SAPL technology has proved to be one of the cost-effective solutions for subsea field developments that require frequent operational pigging. This paper will highlight the key learnings on application of SAPL technology for pipeline pigging operation. It will also provide some insights on the recommended engineering, construction, operation and intervention practices of the novel technology solution that could pave the way for reliable and cost attractive solutions for pigging operation in shallow water and deep water development in future.
Performance Assessment of Enhanced Geopolymer Cement Technology for CO2-Rich Well
Authors: Razak Ahmad Amirhilmi A , Sazali Yon Azwa , Zulkarnain Nurul Nazmin , Rahman Siti Humairah A , Amir Muhammad Syafeeq Ebining , Habarudin M Firdaus , Riyanto Latief , Hamid Afif Izwan A , Medvedev Anatoly , Yakovlev Andrey
Published: October 2023

The unique characteristics of Portland cement in terms of properties, availability and cost does not allow it to be replaced in many cases. However, there is a certainty about the properties of Portland cement in the long term because of thermodynamical instability of cement in the environment. These fundamental limitations of cement have prompted us to search for and study new materials with improved properties. According to a number of criteria, geopolymers were chosen as the most promising material. In this paper, the geopolymer formulations with 15 ppg density was prepared in the laboratory and the properties of the set geopolymers were investigated before and after exposure to an aggressive CO2 atmosphere. Results of 4-, 10- and 24-weeks exposure of geopolymers were compared with 15 ppg G cement and slag cement samples in the same conditions. Geopolymers demonstrated superior stability over G cement and slag cements at acidic conditions.
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

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

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

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

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

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 > 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

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

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

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

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

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.
AI-Optimization of Lithium Recovery from Reservoir Operations - An Adapted Volve Field Study
Authors: Katterbauer Klemens , Al Shehri Abdallah , Al Qasim Abdulaziz , Yousef Ali
Published: October 2023

Lithium has become a valuable resource for a variety of applications, such as for batteries, in the quest for greater sustainability of the utilization of resources. These challenges have led to the demand for enhanced field operations and making the operations more sustainable while maintaining production levels. The 4th Industrial Revolution is having enormous impact on the oil and gas industry, and with the rise of the demand for lithium for battery and energy technologies, hydrocarbon reservoirs have become an attractive source for these valuable resources. Several reservoirs around the world have been demonstrated to contain significant quantities of lithium in their produced brines.

In this work, we present a new AI optimization approach for the optimization of lithium recovery from reservoir operations while maintaining reservoir oil production targets. The approach is novel in the both the AI framework utilized as well as its integration into a global optimization approach based on genetic algorithm to optimize both oil production and lithium recovery. The AI framework incorporates a deep learning LSTM algorithm for estimating oil, brine and lithium recovery based water injection levels. The deep learning model is then incorporated into a global optimization framework to optimize the water injection levels to maximize lithium recovery while maintaining reservoir oil production levels.

We provided a new AI optimization framework for lithium recovery from reservoir brine from an oil and gas reservoir. The framework enables optimization of lithium recovery while maintaining hydrocarbon recovery rates. The framework was successfully demonstrated on the Volve field, outlining the potential significant increase in lithium recovery rates from an optimized injection process. This framework may provide significant opportunities in enhancing reservoir brine utilization, and contributed subsequently to enhancing sustainability in reservoir operations.
Integrity Management Pass Panel Review Form: A Tool for Reviewing Critical Topside Pressure System Anomaly in an Offshore Normally Unmanned Installation During Drilling and Well Intervention Activities
Authors: Harmantoro Akhmad Tutus
Published: October 2023

Normally Unmanned Installation (NUI) is a facility with less severe human consequences because of its minimum manning during normal operations, i.e., 1-3 persons per visit. However, the number of manning increases drastically during well intervention activities. Tens of people dwell in the accommodation building on the liftboat or drilling rig that resides above the NUI platform. This circumstance raises safety issues, especially for the NUI platform with a critical wall thinning in its topside pressure systems since the boat or the rig does not have complete safety protection against the topside hydrocarbon release.

Pertamina Hulu Energi Offshore North-West Java (PHE ONWJ) has an Integrity Management Pass (IMPASS) business process to manage the integrity issue during well interventions in NUI. IMPASS requires collecting the integrity status in the respective NUI, highlighting and reviewing the critical pressure system integrity anomaly, and implementing recommendations established in the review. The liftboat or drilling rig may sail heading to the NUI if the relevant parties approve the IMPASS and implement the recommendations.

Reviewing the pressure system anomaly is the critical step in IMPASS. The reviewers shall ensure the effectiveness of hydrocarbon leak prevention and readiness to mitigate the probable leak occurrence. A custom programmed spreadsheet form, named IMPASS PREVIEW form, supports the review process to maintain consistency of the review results.

IMPASS PREVIEW form summarizes integrity anomaly data, collects operating conditions and existing safety protection system data, and applies process safety and risk-based concept to assess the protection system and establish recommendations. It classifies safety protection into prevention, engineering, and procedural control. Then, it automatically recommends stringent additional measures to the existing safety protection for pressure systems with more severe integrity conditions. It also predicts probable hazardous hydrocarbon events as the basis for the emergency drill plan.

IMPASS PREVIEW has been utilized to support approximately 100 well interventions. It promotes a shared understanding among relevant parties that allows early and consistent data collection. It also applies a consistent approach in every review with relatively shorter review duration. Since the recommendations can be immediately acquired, it allows early remediation action to set facilities ready to receive the liftboat and the rig in safe condition.
Strengthening Learning Culture in WK Rokan Through Digitalized Knowledge Management Supporting Dynamics Challenges of Drilling & Completion Operations
Authors: Hoviari Muhammad Abdunnasir , Dahlil Irwan , Rizki Freddy Frinly , Fikri Bima Surya Khoirul , Misnawati _ , Rahman Aznil Arif , Prawira Muhammad Riza , Lengkong Jane Serafin Theodora
Published: October 2023

Operational Excellence is paramount in oil & gas industries. Various efforts were made to achieve incident free while promoting efficient operation. However, in massive operation activities, the challenges become even greater because of the Short of Service Employee (SSE). The aggressive in increasing number of Rigs creates a high number of newcomers with limited skill, competence, and experience. Nevertheless, dynamics challenge operations are not an excuse to fail. Operation must be run safely for business continuity. Appropriate solutions are figured out to bridge the condition and applying Knowledge Management (KM) is one of them.

Drilling & Completion Rokan believes that learning culture is a strong foundation in achieving the vision and mission of the organization. The learning process has been carried out from the management level to the Business Partner's frontliners under learning group called D&C Learning Club - DCLC. Information and knowledge sharing is always delivered face-to-face or via online meetings. Digital technology such as social media has proven to be practical, easy to do and accelerates the learning process. However, this application has limitations for use in very massive and complex environments. Therefore, D&C Rokan has developed a KM platform that is more robust and provides better value.

The development research begins with the mapping process for the required knowledge. This mapping is scoped on Drilling operation and Engineering support. Then SWOT and TOWS analyzes were carried out to support the decision-making process in selecting applications for the KM platform. Decisively, team decided to choose "SharePoint" application because of its superiority in security, infrastructure availability, memory capacity and ability to provide an environment for community interaction, transforming knowledge based on a knowledge creation model, known as SECI - Socialization, Externalization, Combination, and Internalization.

The KM application, which is called KM&L, consists of 3 main parts: discussion platform, digital library, and learning calendar. The learning community remains a major factor in the success of achieving a learning culture. Activeness in questions and answers, discussion to find solutions, challenging each other and involving Subject Matter Experts (SME) will accelerate the process of creating knowledge, which is documented in a digital library. KM&L is expected to become One Stop Shop Learning. The expectation is not only to accelerate the learning curve for SSE, but also to retain knowledge for communities. These will eventually become one of the competitive advantages for D&C Rokan in achieving operational excellence: incident free operation and world class reliability & efficiency.
Low Cost Alternate Solution to Produce the Shallowest Productive Low-Quality Reservoir in WK Rokan
Authors: Afif Ikhsani Muhammad , Putra Azarico , Rafi Muhammad , Alfajrian _ , Barezzi Muhammad , Jati Nugroho , Sunjaya Rizky
Published: October 2023

Low Quality Reservoir in WK Rokan is quite famous as a large volume of remaining recoverable resource, where TLS Formation owned the biggest share (~51%) of the total Low-Quality Reservoir potential additional reserves. This formation develop widely in Central Sumatra Basin with range ~600 ft TVDSS depth and the deepest productive reservoir in ~4000 ft TVDSS.

The 600ft TVDSS TLS Reservoir is identified as the most challenging Low-Quality Reservoir in term of its subsurface and operation since this formation has been producing for decades. This Reservoir located in BLSO field in Riau Province, Central Sumatra, Indonesia approximately 140 km Northwest of Pekanbaru or 50 km northwest of the DRI field. The field is a large elongated anticlinal structure bounded on the southwest by a major high-angle reverse fault. The shallowest productive TLS in WK Rokan has a minimum recovery factor with a low reservoir quality which has permeability range of 20-300 MD due to the thin overburden barrier (shallow structure), reservoir complexity (low reservoir permeability, low sand connectivity) that led to limitation of completion strategy resulted in low oil recovery. It is found in 1972, and commercially produced as an oil-producing well with a reservoir depth of 800 - 1000 ft TVD with current recovery factor only 8%. The drive mechanism in this reservoir is shown as a weak water drive reservoir.

The old-fashioned development strategy from this shallow low-quality reservoir is by having hydraulic fracturing with cased hole completion which will be driven a high-cost development scenario if we want to increase oil recovery in this reservoir. The alternate solution in developing this shallow reservoir is by optimizing productive section interface, and Open Hole Screen Liner is coming out as solution with lower investment to add more recovery with average production 49 BOPD and low average water cut (51%).

This paper will talk about in how we develop well candidacy to apply open hole screen liner completion method, the result and future development plan to improve oil recovery in shallowest low quality reservoir in WK Rokan.
Unlocking High CO2 Wells - Strategy for Achieving Optimum Gas Blending Ratio
Authors: Mohd Fauzi Nurul Adlina , A. Rahim Nurul Afiqah , Gazali Muhammad Yusri , Giri Emelia , Mohd Nawi Mohd Shakir , Raja Azman Raja M. Rafiyudeen
Published: October 2023

Platform X has four (4) Non-Associated Gas (NAG) wells with total production rate of 75 MMscfd. Due to their high CO2 content ~ 10-13 mol%, NAG production were capped at production operating philosophy of 30 MMscfd. They were produced thru blending them with Associated Gas (AG) wells (ratio 50:50) to meet 8 mol% CO2 limit at pipeline from Platform X to gas processing hub (Platform Y). In a normal production, only two (2) NAG wells flowing, two (2) NAG wells remain idle causing a loss in production opportunity. The study was conducted to further unlock NAG potential by revisiting the blending NAG:AG ratio. Few steps were outlined for the study workflow; surface facilities readiness, data collection on-site CO2 gas sampling and flaring monitoring, data analysis thru Aspen HYSYS model simulation for theoretical and sensitivity data, and risk assessment for revised blending ratio. From the study, Platform X gas production can be optimized up to 55 NAG: 45 AG blending ratio. Actual on-site sampling dictates CO2 mol% at pipeline from Platform X to Platform Y to be around 7.5 mol%. It is comparable to Aspen HYSYS simulation result indicating a good model tuning. Sensitivity analysis generated from the model implies that the higher AG production, the higher NAG production as more gas can be blended with low CO2 content of AG well. Risk assessment stated overall risk-rating is low. Platform X is allowed to flow continuously with the revised blending ratio provided that wells flow rates not exceed the blended CO2 limit. Additional gas yielded is 7 to 8 MMscfd, daily estimated revenue ranges from RM 188,000 to RM 215,000. Flaring is able to sustain ~0.4 MMscfd, below Platform X limit of 1 MMscfd.
Improving Drilling Efficiency Using Intelligent Decision System for Drilling in Bohai Oilfield Based on Big Data
Authors: Xie Tao , Hou Xinxin , Huo Hongbo , Lin Hai , He Ruibing , Xu Dongsheng , Zhang Lei , Liu Hailong , Li Wenlong , Liu Xun
Published: October 2023

Making use of data generated from drilling process are challenging in oil industry, an intelligent decision system for drilling based on big data has been established to improve efficiency and reduce drilling cost of more than 400 wells are being drilled in Bohai oilfield every year. The data acquisition standard of offshore drilling and completion is formed, and the data are transformed and stored in database system. Based on the analysis of regional geological, seismic, logging and drilling data, various risks of the design well are evaluated to achieve the best drilling and completion design scheme. Meanwhile, real time intelligent prediction models with machine learning methods, such as Artificial neural network, Convolutional neural network, K nearest neighbor, etc, are established to predict and avoid pipe stuck, lost circulation, gas kick events. Moreover, a continuous improvement system is established to improve drilling efficiency through drilling parameters optimization. An intelligent decision system for drilling with the core of "pre drilling rehearsal-risk assessment-parameter optimization" has been formed. This technology has been successfully applied in 50 wells, the average well construction time has been reduced by 4.5 days compared with previously drilled wells. Bohai oilfield is accelerating digital transformation pace of drilling and completion, and the filed application show that digitization and big data technology can greatly help increase efficiency and reduce cost, which can also be a reference to other oilfield.