bluuebunny/crossref_metadata_2025_split huggingface dataset:
Near Wellbore Cement Integrity of CO2 Geologic Storage in Mature Gas Field, Malaysia
Authors: Leem Junghun , Sazali Yon Azwa , Riyanto Latief , Ebining Amir Muhammad Syafeeq 
Published: October 2023

Abstract
Appraising CO2 leakage risks and ensuring the long-term CO2 containment integrity of existing and new wells are key factors in guaranteeing the sustainability of potential CO2 geologic storage in a depleted mature gas field. Particularly, considering CO2 leakage through cement itself (i.e., sheath and plug) and cement interfaces with casing is critical in assessing the CO2 leakage risks and the long-term containment integrity sustainability.
To estimate CO2 leakage through cement sheath/plug and cement-casing interfaces, two separate work scopes were identified and addressed. First, a corrosion-based cement damage model was developed to assess CO2 leakage risks through cement sheath/plug based on the stress corrosion crack theory, which implies mechanical and chemical corrosion effects on mechanical materials (i.e., chemical-mechanical coupling). Thus, the stress corrosion-based cement damage model can account for corrosion effects on cement due to CO2 exposure in a CO2 geologic storage and assess CO2 leakage through the damaged cement sheath/plug.
Later, a cement interface debonding model was developed to estimate CO2 leakage risks through cement-casing interfaces. The interface debonding model is based on conventional static failure criteria, as well as analytical hydraulic fracturing methods simulating interface debonding as small-scale hydraulic fracturing caused by CO2 injection. The cement interface debonding model can be applied for cement-casing bond integrity analysis to estimate CO2 leakage risks and rates through the debonded interfaces.
Process and Lessons Learned Using Hollow Glass Spheres for Drilling Depleted Fields
Authors: Rylance Martin , Sherishorin Vitaly 
Published: October 2023

Abstract
Two major mature oilfields with multiple rigs (&gt; 150) delivering hundreds of thousands of drilled metres annually, suffered from severe induced losses during their ongoing development and also redevelopment phases. These events of course significantly impacted the overall drilling performance, leading to substantial production issues and poor economics. Although the fundamental underlying nature of the losses varied; proven success in both cases was to significantly reduce the mud weight. Additionally, in both cases, the key to achieving this needed to be a solution using low-cost, minimal rig modification approaches while at the same time retaining the well productivity at equivalent levels.
The applied solutions Team both identified and screened a number of approaches for achieving an effective MW reduction, and this process resulted in the proposal for the use of Hollow Glass Spheres (HGS) as the preferred methodology. A thorough study of the available literature and previous industry experience had demonstrated that HGS potentially met all of the requirements. In order to confirm the compatibility of the HGS, a series of laboratory tests were planned and performed; followed by a set of structured field trials, confirming the suitability of this technology. These results were then collated into a Basis of Design (BoD) for a drilling fluid system utilising HGS for drilling through target zones with abnormally low pore pressures, capturing lessons learned from all stages of their application.
This paper will describe the details of the screening for the available solutions; as well as performing the feasibility study through laboratory tests and field trials. It will report on the phased approach taken for piloting the technology, describing the challenges and risks that were assessed, faced, and mitigated during both the testing and trialling stages. A review of the post-deployment lessons learned, techniques used, and approaches corrected during subsequent trial period(s) will be presented. A summary of the economic assumptions made, and their evolution will be covered; and then discussed with regards to technology upscaling and the further proposed developments and enhancements.
The results of the HGS technical solution have greatly exceeded the original expectations and continuous improvement of the technology indicates much more to come. Discussions of the possible modifications and improvement to the HGS fluid system are ongoing and involve formulation, HGS type, logistics, strategy of HGS mud utilisation … etc. The use of HGS on these two oilfields has been novel and has resulted in a generally greater interest and appetite within the industry for this area of application.
Digital Champion: A Self-Voluntary Program That Brings Vast Impacts in EMCL’s Digitalisation Journey
Authors: Silvana Annisa , Chairunissa Cindy , Prasetyawati Bramanty , Oktafian Yuan 
Published: October 2023

Abstract
Digitalisation has been a significant enabler in most industries in improving business process and delivering value in recent years. The oil and gas industry is one of the industries that has been adopting digitalisation as part of their strategy to continue to bring innovations in most areas of the business. ExxonMobil Cepu Limited (EMCL) recognized the growth of digitalisation demand in the business while availability of internal local resources with digital skills were still very limited. This prompted EMCL to find alternative ways to manage the growing digital needs within local capabilities. The idea of having internal local business resources as Digital Champions was established to bring in more digital energy.
Digital Champion is a self-voluntary program, which distinct the program with other resource planning initiatives. When the program was launched in 2021, there were 45 people that joined as Digital Champion from cross-functions, showing the appetite of EMCL organization to digitalisation. Further, as the work progresses to 2022, the number has increased up to 80 Digital Champions, making 11% of EMCL population. Digital curriculum is tailored and prepared to answer business needs and feasibility as part of individual digital upskilling. The curriculum includes Data Literacy, Digital Tools and Agile Adoption.
In its two-year journey, the program has continuously delivered values to the company. Many improvements to the business process which resulted in optimization and an increase in productivity have been delivered. Individual impacts have also been noticeable, by way of each Digital Champion manage to level up their digital skills. The program also nurtures collaborative environment and enable synergy cross-functionally as a team.
Without limiting the boundaries of the Digital Champion program just as an enabler of digitalisation in the organization, this program is also designed for the sustainability of delivered digitalisation results and continuous improvements. It is believed that although the organization will have more capacity of dedicated resources for digitalisation, the self-voluntary Digital Champion program will remain to be valuable not just for the organization but also for the individuals.
Revival of an Oil Well with Successful Water Shut Off by Novel Placement Technique of Exclusively Optimized Cross-Linked Polymer
Authors: Pandit Vikrant Daksh , Gupta Vinod Kumar , Betanabelli Nagiresu , Sutaria Ishaq , Saklani Diksha 
Published: October 2023

Abstract
Excessive water production is a major problem worldwide for petroleum industry as it increases operating and production cost in terms of lifting and processing cost per barrel of oil. Presence of micro channels behind the casing due to poor cementation, which sometime become irreparable by secondary cementation, are common cause for water entry into the well bore. The problem was addressed with exclusively designed organic polymeric gel system with its novel placement.
To find out the reason of high water production, the well was analyzed comprehensively and methodically with the help of structural contour map, conventional well log data, production performance, SBT-USIT log, VDL, pulsar test and work over history. Low viscous deep penetrating polymer was optimized in the laboratory. Further the optimized polymer was cross-linked with organic cross linkers to achieve well specific polymeric gel system to invade into micro channels and block them. The Polymeric gel system was placed into the micro channels with the help of shale layers through appropriate job designing and execution.
The well K-X of "K" Field (India) faced high water production in its early stage of production. The initial production rate in the well was Qo: 170 m3/d with 10% water cut. Within one week of production, water cut started rising and reached to 100% in a month. High water cut in the well was found due to entry of extraneous water and bottom water into the well bore from upper and lower part of perforations through micro channels behind the casing which could not be repaired with two attempts of secondary cementation. The task of curtailing extraneous water and bottom water entry into the well bore was successfully accomplished by water shut off job execution using organic cross-linked polymeric gel system and its novel placement in the reservoir. On activation after water shut off job, the well was put on sustained production of 63 m3/d oil along with negligible water production. The well flowed with its peak production of 81m3/d with 3.5 % water cut after job and resulted in incremental oil gain of more than 35,000 m3 in two years.
The novelty of this job lies in the approach of repairing of cement behind casing with polymeric gel system when attempts of secondary cementations become unsuccessful. Novelty also exists in optimization of well specific gel system and ensuring their penetration into micro channels with appropriate designing of job plan and its execution.
New Pillar of Mature Field Production Strategy: A Success Story of ESP Upsizing Pilot Project
Authors: Aryanto Agus , Malau Aldani , Hidayat Azis , Nugroho Muhammad Hasto , Yassin Chaidir , Lazuardi Hilman 
Published: October 2023

Abstract
Electric Submersible Pump (ESP) upsizing project has historically an effective tool to optimize oil production. As a mature field, KS field currently was producing with average 97% water cut. Most of the ESPs installed in SK field were designed to produce 1,000 to 2,500 BLPD. Meanwhile, the potential maximum liquid rate of some wells is much higher than the current ESP rate, ranging from 8,000 to 17,000 BLPD. The oil production can then potentially be increased 3 to 5 times higher by upsizing the ESP. Hence, the objective of this study is to accelerate oil recovery from un-optimum oil well.
This optimization can be achieved in 2 ways, either drill new big bore well or optimize existing well. By optimizing existing wells through ESP upsizing pilot project, we can save estimated USD 1.5 MM compared to drill a new well. The ESP upsizing project is planned into 3 phases; phase-1 pilot (2 wells), phase-2 implementation (8 wells) and phase-3 and phase-4 full-scale (33 wells). KS-XXX1 and KS-XXX2 were selected for the pilot project and upsized using ESP pump with recommended operating range 3,500 – 10,500 BLPD at 60Hz. The reservoir simulation, fractional flow evaluation, production network modelling, well performance and nodal analysis were conducted prior phase-1 execution to increase project confident level. To operate these high-rate wells, some improvements in electrical system, flowline safety devices and well test procedure are also required. Therefore, multidiscipline team was involved in this project.
The pilot project phase-1 has successfully executed and currently producing 476 BOPD from initial rate 80 BOPD without significantly increasing of water cut. Estimated cumulative oil gain of these wells are 567 MBO.
The successful phase-1 ESP upsizing will unlock the potency of phase-2, 3 and 4. Through maximizing liquid production and reducing number of active ESP wells, oil production is expected to increase with lower operating cost (by reducing well count). Estimated oil gain from full scale implementation is 4.93 MMBO.
This paper will describe a production optimization in mature field by ESP upsizing. Increasing liquid production is established technology to improved oil recovery in mature reservoir. Application of upsizing in high water cut wells has been proven to improve production decline using low expenditure.
Development of a Unified PVT Model for a Large Heavy Oil Field in Kuwait
Authors: Alali Yacob , Verlaan Marco 
Published: October 2023

Abstract
Field X is an extensive heavy oil field in the North-West of Kuwait with 4 reservoir zones and extensive variation in heavy oil composition and physical properties (10-18 °API). Historically, various PVT models have been developed for various parts of the Field X for different modeling purposes. These models - often developed by different engineers - are not consistent and add another layer of complexity to the understanding of reservoir performance for different regions of the Field. The objective of this study is to develop a unified PVT model for use in the dynamic thermal simulation for the whole Field X.
The model follows the standard procedure for PVT modelling for heavy oil. In this case, however, due to abundance of PVT data, the challenge is selecting/disregarding PVT samples to be used for tuning a global Equation of State (EOS). Most recent, reliable PVT samples (18 samples out of 155) over the whole range of densities with possible different locations were selected. The most complete set of PVT data was used for construction of an EOS which was tuned using the selected 18 samples.
A single 4 component EOS model was regressed on a selection of 18 PVT samples distributed over Field X area. This model matches Saturation Pressure ±14%, GOR ±8%, Oil Density ±0.2%. These models are exported to CMG STARS format to be used in Field X life of field dynamic modelling study. Separately a viscosity model was developed using the Yarranton approach and that matches oil viscosity in all 155 samples with an average deviation of ±17%. To test the robustness of the model, an additional set of 11 samples has been selected in a wider area of the Field X including samples in the South, South-West and West area. The model matches the saturation pressure, GOR and density values reasonably well, with a bit more scatter than the samples used in the model tuning.
The PVT study revealed a strong correlation between the mole fractions of pseudo components and the in-situ oil viscosity and bubble point pressure. This enables calculation of initial oil composition in the dynamic model based on interpolated viscosity maps.
Complex Fluid of South Mahakam: A Fluid Synthesis Case Studies with Overpressure and Gas Striping Phenomena, of Multilayer Reservoirs for Marginal Offshore Gas Field Development in the Manpatu Field
Authors: Fajar Dendy Surya , Rushatmanto Mochamad , Utama Fia Adhi 
Published: October 2023

Abstract
Manpatu Field was discovered in 2022. It will provide a transition to green energy supply for the future capital of Indonesia, which will be located in the same region of East Kalimantan. A fluid synthesis studies methodology of the retrograde gas-condensate with gas striping phenomena on the overpressure multilayer reservoir fluid vertical distribution was introduced to rectify volumetric calculations in both static and dynamic geomodel simulation. This was done to justify the economics of the offshore marginal gas field development.
The new approach is based on generating a specific fluid model - EOS pseudo component methodology for Gas Striping that is in agreement with the geochemistry analysis. It involves integrating the surrounding panel with exploration well data to control the fluid model based on Gas Liquid Ratio (GLR) and hydrocarbon column occurrence in the overpressure vertical distribution of the Manpatu Field compared to other panels of the South Mahakam Field. The aim is to provide a base-minimum-maximum case scenario in reducing uncertainties of the fluid, in order to economically justify the volumetric hydrocarbon calculation in static and dynamic simulations.
A fluid model with 5 pseudo components, following a specific trend based on the geochemistry analysis of the hydrocarbon with gas stripping phenomena, was generated to match all the fluid behavior from the PVT samples. However, this is only half of the journey. Saturation pressure and GLR vertical distribution from the available samples taken from the exploration wells are not sufficient to determine fluid evolution with the overpressure regime in the Manpatu Field. Therefore, combining the data with the surrounding produced panel is taken into account. The result deviated, even contradicted, the classical gravitational segregation vertical fluid distribution. Specific GLR and Saturation Pressure evolution trends vs. depth scenarios and assumptions in the overpressure regime were made to govern fluid vertical distribution and reduce uncertainties in static and dynamic geomodel simulation to mimic the phenomena in the field.
Gas striping and overpressure need to be considered in order to have a reliable multilayer reservoir gas condensate-oil fluid model for reliable OOIP and IGIIP volumetric calculations and development scenarios. Using classical gravitational segregations vertical fluid distributions would lead to misleading conclusions. The results of volumetric calculations and uncertainties are rectified for the justification of the project's economic feasibility for the Manpatu's marginal gas field development FID's.
Success Story in Implementing New Substructure Technology for Offshore Marginal Fields
Authors: Islami Era 
Published: October 2023

Abstract
Medco E&P Indonesia (Medco E&P) operates offshore platform in Natuna Sea. The recent development in Natuna Sea is for marginal field. In case development of marginal field using wellhead platform concept, the challenge in built offshore platform in Natuna sea which has harsh environmental metocean and water depth range from 70 m – 100 m is limitation of crane barge for installation of offshore jacket platform. With metocean criteria and water depth in Natuna Sea, the minimum jacket weight using conventional design is about 1000 ton lifting weight, in 2019 during the Medco E&P Project executed, there is no crane barge with Indonesian flag available in market, the maximum crane barge capacity in Indonesia is 600 MT – 800 MT lift weight. Therefore, Medco E&P team should find substructure new technology for lightweight structure which could be installed by available crane in market to achieve fast track and optimized project cost for marginal field development.
The new technology is required to overcome the challenges for marginal field development which requires fast track and low capital project, modular braced monopod has been selected through qualitative and quantitative assessment done amongst 6 lightweight substructure technologies during select phase. Executing project with this new technology, requiring specific project and construction strategy as well as comprehensive assessment on installation procedure and acceptance criteria. The concept of modular braced monopod has benefit in lower offshore lifting weight so require only small crane barge. The jacket consists of several parts which the maximum lifting weight for jacket component is 380 MT only.
The modular braced monopod platforms for two fields in Natuna Sea has been installed and operated normally since December 2022, the project has successfully installed 1st modular braced monopod platform in Indonesia with maximum offshore lifting weight around 380 tons only for water depth 79 m compare to non-lightweight structure such as 4-legged platform for similar water depth might requires 2000 – 3000 tons crane barge capacity, the technology has supported for project cost optimization and suitable for tight schedule. The installation of modular braced monopod in the project is the fastest installation compared to other zeepod installation. Area of improvement has been documented and some recommendations for future application to be shared so that allowing better project development for other marginal project. The success story from this project will describe journey in technology selection, risk identification and mitigation, managing interfaces, high standard quality of construction and installation work, as well as providing some lesson learned to organization in executing new technology in offshore platform project.
An Intelligent Separated Zone Oil Production Technology Based on Electromagnetic Coupling Principle
Authors: Liao Chenglong , Jia Deli , Yang Qinghai , Pei Xiaohan , Zhu Yingjun , Kong Lingwei , Yu Yang , Du Kai 
Published: October 2023

Abstract
Separated zone oil production technology is an important means to solve the interlayer and planar contradiction, fully develop the middle and low permeability layers, reduce the ineffective water circulation, and realize the remaining oil exploration in the high water cut stage of the oilfield. The existing technologies suffer from many problems, such as unsuitable for pump inspection operation, short working life, and poor communication reliability.
This paper proposes an intelligent separated zone oil production technology based on electromagnetic coupling principle. The release-sub-involved pipe string structure is adopted, in which the production pipe string from the ground to the pump is connected by external binding cables, and multiple intelligent production allocators (IPAs) of the allocation pipe string are also connected by cables. The electromagnetic coupling principle is used to realize the close-range wireless transmission of power and data between the production and allocation strings. After the docking, the allocation pipe string can be powered from the ground, and two-way communication can be realized. This technology provides a repeatable downhole docking and detaching channel of power and data transmission, which eliminates the need to lift out the allocation pipe string during routine pump inspection operation, effectively increasing the working life of the IPA and reducing operation cost.
The main components of this technology include ground communication controller (GCC), downhole electromagnetic coupling device (DECD), and IPA of each layer. The GCC is used to collect downhole monitoring data and adjust the zonal fluid production. The DECD consists of an inner cylinder tool and an outer cylinder tool. The inner cylinder tool is connected to a tubular pump, while outer cylinder tool is connected to the IPA. The average transmission efficiency and power of the DECD is 94% and 52 W respectively, and the error rate of data transmission is less than 1%. The IPA has the functions of temperature, pressure, flow rate monitoring and zonal fluid production adjusting, with a flow rate measurement range of 5∼100m3/d, an accuracy of ±3% FS and a flow control valve of maximum overflow diameter of 15mm. The field trials of this technology were carried out in Daqing Oilfield and the experimental well was divided into two layers. The results showed that DECD was successfully docked. The measured downhole temperature was about 46°C, the maximum flow rate was 35 m3/d, and the bottomhole flowing pressure was 9 MPa.
This technology has the advantages of suitable for pump inspection operation, high communication reliability, and long working life, providing a new engineering technical means for alleviating the interlayer contradiction and improving reservoir recognition, which is expected to have a broad application prospect.