bluuebunny/crossref_metadata_2025_split huggingface dataset:
Asset Value Framing: Maximizing Asset Lifecycle Value Through Opportunity Roadmap Formulation
Authors: Guillory Ryan , Jamaludin Maisarah , Ranjan Rakesh , Abdul Rahim Mas Rizal , Masoudi Rahim 
Published: October 2019

Abstract
As resource owner, host authority, project enabler, and industry shaper, PETRONAS Malaysia Petroleum Management (MPM) has embarked on Asset Value Framing (AVF) since 2016 for its key assets in Malaysia. AVF is designed to provide an avenue for all stakeholders to generate opportunities in an integrated and holistic manner, with values associated, key risks and uncertainties identified, and the enablers and success factors tabled out. It is aimed to evaluate and consolidate all opportunities and synergies both within the Production Sharing Contract (PSC) and outside PSC boundaries with the intent to maximize field life value. The AVF provides a platform to establish a common roadmap shared by MPM and the Contractor to formulate further development steps, maximize economic recovery (MEC), slow production decline, understand the risks, challenge the givens, and to review new technologies to improve field performance.
Short, medium, and long term opportunities associated with reservoir redevelopment and optimization, improved and secondary recovery, near field exploration, well management, operational excellence, cost reduction, facilities optimization, and commercial opportunities are identified and evaluated. An asset roadmap, activity planning, and short term action plans are developed at the end of the AVF workshop, which is agreed and supported by all parties. A clear stack of opportunities for the remainder of the field life, with value and cost associated to each opportunity, become a guiding principle for field growth for all stakeholders. This alignment has enabled consistent planning of project sequencing, resources optimization, and resolution of commercial issues. Opportunities identified in the AVF are later matured, actionized and approved through established MPM channels of Asset Development Integrated Review (ADiR) and Asset Management Integrated Review (AMiR) processes.
Commissioning and Start-Up of Complex Mega Scale Project-Integrated Gas Field and EOR Development
Authors: Ghazali Izrie , Azman M Muaz , Ahmad Shatiry M Sahir , Jaidi M Zamri , Elarafi M Gaberalla 
Published: October 2019

Abstract
In an oil and gas project life cycle, commissioning is notably the moment of truth where the engineered, procured and constructed facilities are verified functioning for the first time. Inability to recognize a project's Commissioning and Start-Up (CSU) unique requirements would increase the risk of project failure. The risk could be mitigated by adopting the right mindset–begin with end in mind. This paper outlines the application of project management processes associated with commissioning discipline.
A multinational operating company undertook a complex mega scale project that aimed to develop an integrated gas field and Enhanced Oil Recovery (EOR) in offshore Sarawak, Malaysia. The project, executed by multiple Package Contractors, is composed of a new central processing platform (CPP), 2 new wellhead platforms, 6 new pipelines, 1 submarine cable, 9 brownfield platforms, 16 new wells and 4 workover wells. Commissioning Team was mobilized as early as Front-End Engineering Design (FEED) and adopted Systemization to decompose the project complexity into manageable constituents. The CSU Philosophy was designed to formulate the Integrated CSU (ICSU) Strategy that systematically drives the construction completion and synergizes the efforts.
Without the strategy, each package would have been focusing in delivering individual objectives that could have compromised the chance of overall project success. However, the timely deployment of it has realigned the execution strategies, noting that offshore project environment is largely dependent on marine vessels arrangement. The strategy managed also to break the silo mentality and encouraged collaboration and communication among the packages and Operations even before the start of the main offshore campaign. The teamwork, of 1200 manpower and 25 marine vessels at peak, was continued offshore and has materialized the introduction of hydrocarbon to CPP 40 days ahead of schedule. Subsequently, the first gas achievement was accelerated by two months ahead of schedule. Additionally, the risk of commercial exposure due to standby of marine vessels and resources caused by clashing of activities, was successfully mitigated.
The experience and lessons learnt from the project can benefit others to undertake similar projects safely and successfully in terms of strategizing, planning and execution.
First Natural Dump-Flood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment with Low-Cost Secondary Recovery
Authors: Abdulhadi Muhammad , Tran Toan Van , Mansor Najmi , Awang Pon Zaim , Chin Hon Voon , Jacobs Stephen , Suggust Alister Albert , Usop Mohammad Zulfiqar , Huong Chii Seen , Zamzuri Dzulfahmi , Abdussalam Khomeini , Khalid Aizuddin , Munandai Hasim , Yusop Zainuddin 
Published: October 2019

Abstract
Natural dump-flood, a low-cost secondary recovery method was successfully implemented for the first time in the Malaysian offshore environment. The dump-flood was initiated by adding perforations in a high-pressure water aquifer and allowing water to cross-flow naturally into a low-pressure depleted reservoir. With investment of 0.4 million USD, the dump-flood has effectively increased the reservoir recovery factor (RF) while increasing the reservoir pressure by more than 300 psi despite being continuously produced.
After 30 years of production, most solution gas drive reservoirs in Field B were idle and depleted. A low-cost natural dump-flood was implemented in reservoir S2, a depleted reservoir, by converting well D-10 into a dump-flood well. The conversion was achieved by perforating a high-pressure water aquifer underneath the S2 reservoir in the same well and allowing water to naturally cross-flow into the depleted reservoir. An existing oil producer, well D-07 was selected as the offtake well that would be produced once the pressure increased. The well operations were both simple and inexpensive as indicated above.
The dump-flood initiative in the first reservoir, S2, was a complete success. A year after the dump-flood was implemented, the offtake well D-07 began to steadily produce 250 bopd compared to its earlier intermittent production. The well production increased to 600 bopd after five years. Pressure survey and production logging results confirmed the positive impact of the dump-flood. The reservoir pressure increased by 300 psi, despite continuous production throughout the dump-flood period. A reservoir simulation model indicated the dump-flood increased the recovery factor of the S2 reservoir by more than 8%. Numerous lessons learned were acquired during the implementation of this first natural dump-flood in Malaysia which serve as a reference for future application. The dump-flood in the S2 reservoir is hailed as a breakthrough, since it helps prove that secondary recovery can be implemented with minimal investment in an offshore environment.
This paper provides valuable insight into the case study of maximizing oil recovery through dump-flooding in an offshore environment. The lessons learned serve as a guideline for this simple and low-cost approach, which is highly recommended for maximizing oil recovery in a mature field, especially in today's low margin business climate.
A Game Changer, Avoiding Production Deferment: First Successful Wireless Ignition System for Floating Flare Unit FFU in Malaysia
Authors: Wei Chuen Kok , Mahmood Shazli 
Published: October 2019

Abstract
The objective of the Floating Flare Unit, henceforth FFU, is to re-route vent gas from a fixed flare platform to a secure unit for performing maintenance that requires the flare platform to be fully shut down. Through this, production deferment can be avoided while maintenance can be carried out concurrently. The requirement of the first of its kind wireless flare ignition system came about with the FFU to effectively and safely ignite the FFU remotely from the safe distance of the platform. This innovation of technology, through the new method tested for wireless ignition of the FFU from the platform had proven to not only provide an effective remote ignition system but also assist in avoiding prolonged production deferment.
A flare ignition system was designed that incorporated a slip stream design which draws a small portion of the flare gas to be burnt away from the main flare gas flow, mixes this with air to obtain the correct stoichiometric mix, ignites this mixture with the high voltage ignitors and uses this smaller flame to ignite the main flare gas as there is no fuel gas supply available for a standard ignition system. The new design incorporated a self-contained skid, which included solar panels, batteries and a radio link mounted onto the FFU as a single unit.
Electrically, the main challenge was to design a system with a very low power consumption to enable the system to last for up to 3 days without solar charging. The new system had a continuous power consumption of 6 W, the power required for the radio receiever to allow remote operation and less than 30 W during ignition. The battery capacity was based on these figures and we easily achieved 3 days of working without re-charging the batteries. The first of its kind was tested in Samarang offshore platform in Sabah which allowed remote ignition of the flare tip of the FFU which was located 200 m. away from the platfrom. With this innovation, a prolonged platform shutdown and loss of production of about 10,000 bopd was avoided. The main benefit of this system is that no power source required for the ignition of the flare system. The flare system also works without any fuel gas supply and finally, the system can be operated from a safe distance of over 300 m. Other challenges included building a unit that is compact enough to proof-store the batteries and other electrical components, ensuring that the high voltage electrodes are with spares and preventing electrical cables from breaking as laid along 200 m. of floating hoses. With the successful deployment of this system, we are looking to replicate this success to other locations in Malaysia to mitigate production loss while performing maintenance of flare system or its platform.
Integrated Production Forecast Evaluation in a Complex Gas Market System - A Multidiscipline Approach to Optimize Gas Supply-Demand in South Sumatra PSC Block, Indonesia
Authors: Ginanjar Mugie , Yusim Sylvia 
Published: October 2019

Abstract
ConocoPhillips Grissik Ltd. (CPGL) is the operator of one of PSC block in onshore South Sumatra, Indonesia. The block consists of 7 gas fields which total gas production and reserves makes it one of the largest fields in Indonesia. As the operator, CPGL generally serves as the seller of gas and services many buyers with differing constraints and demands. Balancing the needs of both buyer and seller is important to ensure a successful long-term supply and demand relationship.
Accurate production forecasting is vital to ensuring optimum field development and management because it is a key input to economic evaluation and subsequent business decisions. To capture the future supply, forecasts are required for both the base production assets and new development projects. Accuracy of the production forecast drives decision making for project approval, project timing, need to engage new commercial contracts and optimization of planned maintenance timing. To ensure that the relationship of supply and demand is captured, the operator use an integrated production forecasting tool called the Gas Planning Tool (GPT).
This paper explains the methodology behind the GPT and how its results are used to support business decisions in the continued development of the PSC block. The methodology accommodates inputs from multiple disciplines: reservoir, commercial, surface facilities, operations downtime, and new drill/facility project schedules. The inputs are integrated and optimized solving for the interaction among input parameters and generates a production forecast that honors all the constraints. The value from the analysis is insights to improve understanding of relationships between different variables and variance between plans.
Gas Planning Tool (GPT) has sucessfully captured the gas supply-demand relationship and helped optimize incremental opportunities, timing of opportunities and idenfied the need for projects and commercial contracts.
Applying Epoxy Resin Technology on Remediation for 3.5 in. Casing Leak: Case Study, South Sulige Gas Field
Authors: Sun Yufei , Fang Anyu , Fan Wenmin , Chen Zhiyong , Liu Sheming , Wang Yang , Li Li , Zhang Xiaoming , Luo Chunlong 
Published: October 2019

Abstract
In the South Sulige gas field, a casing leak was discovered after a velocity string production failure caused well SNXXX-02 to be killed because of water traveling from the formation into the wellbore through the casing leak. This high productivity well urgently needed casing leak remediation to restart production.
Instead of a conventional casing patch approach to repair casing leakage, an innovative solution using an epoxy resin system was applied to recover wellbore integrity and return the well to production. In addition, the resin system does not create casing diameter reduction or restriction during the next velocity installation. However, operational histories and field performance in terms of the capability to mill resin inside 3 1/2-in. casing were rare. This paper discusses a case study of applying the epoxy resin system, a rigless operation using fiber-optic coiled tubing (FOCT) to detect a leak, and then squeezing the epoxy resin using coiled tubing (CT) followed by milling-out after its solidification.
The remediation's effectiveness was determined and examined using qualified wellbore pressure testing; this is the first successful application of an epoxy resin in the South Sulige gas field. The recovery of wellbore integrity helped the operator restart production and maintained the wellbore with no ID restriction for ease of the following velocity string installation.
Most of the wells in the South Sulige gas field are tubingless directional wells with 3 1/2-in. production casing. Implementing a velocity string was widely used as a deliquification method during production.
A casing patch was the primary solution to repair casing leakage in this area. This integrated service of detecting the casing leakage point and applying the epoxy resin presents a new method of well remediation for the operator.
Wider Salinity Range and Lower Water Detection Limit for Multiphase Flowmeters
Authors: Fiore Massimiliano , Xie Cheng-Gang , Jolivet Guillaume 
Published: October 2019

Abstract
With 20 years of operations, multiphase flowmeters (MPFMs) using a combination of venturi and multi-energy gamma-ray absorption have gained acceptance in the oil and gas industry by demonstrating reliable measurement and operational robustness. Nonetheless, some challenging operating scenarios are encountered such as significant water salinity changes in multiphase and wet-gas flows and rapid detection of small water quantities during production.
Although MPFMs are not affected by small water salinity changes, inaccurate flow rates can be calculated when water salinity significantly departs from the initial properties. To maintain measurement metrology as per specifications, the water-point should be manually modified to track variations; however, this operation is time consuming and may incur nonproductive time. Interpreting the multiphase mixture's dielectric constant and electrical conductivity simultaneously measured by a new microwave water salinity sensor at a high data acquisition rate shows that water salinity can be tracked online in the presence of oil, gas, and sand, and small water quantities can be detected rapidly in multiphase and wet-gas flows.
The detection of the first produced water is of paramount importance in many applications, such as for fields with high H2S production, where existing processing plants usually have limitations in treating produced water with dissolved H2S. Early detection of produced water in oil is required, enabling operators to take informed decisions about the oil production strategy as well as water treatment and corrosion protection plans. Extensive analyses in flow loops and field operations with the new microwave water salinity sensor demonstrate that the water detection limit is lowered from the typical ∼1000-ppm water volume fraction (WVF) for the MPFM to a remarkably low 50 ppm.
This paper describes the working principles of a new sensor and method, that enable additional capabilities to maintain accurate water-liquid ratio (WLR) measurement in situations where significant water salinity changes occur and to provide a rapid, much lower WVF detection level. Successful cases demonstrating first-water detection in flow loop tests and in field operations are also presented.
Chemical Agents Diversion with Microseismic Monitoring – New Prospects of Refracturing for Open-Hole Horizontal Well in Tight Oil Reservoir of Junggar Basin, China
Authors: Chen Jianlin , Wang yong , Zhao Xubin , Tang Chuanyi , Gao Yan , Zhou Dan , Zeng Bin , Liu Xiangping , Li Wenhong , Wu Jinping , Li Xueyi , Li Yang 
Published: October 2019

Abstract
Refracturing of existing producing wells is an economical option for increasing production when compared to new drills (Urban et al., 2016; French et al., 2014). However, stage isolation during refracturing of horizontal wells can be a challenge, especially in open-hole horizontal wells. Segmentation with common mechanical tools is of high risk and costly, even ineffective sometimes. This paper presents a new tool-free refracturing technology for open-hole horizontal wells in tight oil reservoir employing chemical diverting agents and real time microseismic monitoring technology.
The implementation procedures are as follows: First, reservoir characteristics, surplus oil distribution and brittleness index are evaluated to identify the best perforation candidates for creating new fractures. Second, through the classification of predicted breakdown pressures, number of temporary plugging and diverting fracturing stages are determined. The dosage of granular and powdery plugging agents is designed. Finally, refracturing treatment are performed with an injection procedure of ‘granular plugging agents+ fracturing fluid + proppants+ powdery plugging agents + fracturing fluid’, and microseismic monitoring technology is used to help judge the effect of refracturing and adjust the refracturing operations in real time.
The refracturing treatment was performed in Well X located at Junggar Basin in western China using the method presented in this paper. The microseismic monitoring results show that multi-stage new fractures perpendicular to the horizontal well were created and a more complex fracture network was generated by refracturing in the reservoir, which verifies the validity of the tool-free refracturing of open-hole horizontal wells with chemical diversion agents. After refracturing operation, daily oil production of Well X remarkably increased from 5.1 t/d to 25.1 t/d (one year after refracturing) in the field test.
This study provides an effective tool-free refracturing technology for open-hole horizontal wells, and it was firstly applied in China. It also provides guidelines to the working engineers with respect to refracturing stimulation design and commercial viability. In addition, this technology is not only suitable for open-hole horizontal wells, but also for casing-completion horizontal wells.
New Method of Water Channeling Identification in Unconsolidated Sandstone Reservoir
Authors: GU Wenhuan 
Published: October 2019

Abstract
A new quantitative model of water channeling identification in unconsolidated sandstone reservoir is presented that uses the hierarchical analysis and grey correlation method as its basis for calculations. By analyzing the influential factors of water channeling, seven static factors including sedimentary micro-facies, oil viscosity, permeability, porosity, reservoir type, heterogeneity and cementation degree which impact the formation and development of water channeling are studied, and six dynamic factors including water injection index, injection/production well pressure difference, liquid production index, water cut, production/injection ratio and sand production rate which indicate the appearance of water channeling are confirmed. Used the hierarchical analysis and grey correlation method, the weights of static factors and dynamic factors are calculated, and the new identification model of water channeling is established. In the new identification model of water channeling, there are six different geological models lead to different fluid flow law in the reservoir, which is conventional zone, high permeability zone, micro- fracture in reservoir, and macro-fracture in reservoir, part-completely developed water channeling and full-completely developed water channeling. Using the new method proposed in this paper, the characteristics of water channeling in a practical reservoir group are analyzed. And the quantitative identification results are proved by tracer monitor results. The testing result of tracer is the same as the quantitative identification method, that is to say the new method is effective and accurate.
A New Approach to Measure the Wettability of Porous Media by Temperature Sensitivity of Nuclear Magnetic Resonance Relaxation Time
Authors: Kwak Hyung Tae , Gao Jun , Al-Harbi Ahmad 
Published: October 2019

Abstract
The wettability, specifically the wettability of the porous structure within rocks, is one of the key parameters that determine fluid flow, which determines the potential oil producibility from reservoirs. The oil wetting preference on the pore surface of reservoir rock influences the reservoir performance in various steps of oil production, such as waterflooding and enhanced oil recovery (EOR).
The surface relaxation times of nuclear magnetic resonance (NMR) are sensitive to the wettability of pore surface since they are mainly determined by the strength of fluid-rock interaction. Thus, the surface effective activation energy (ΔE), which is determined by the properties of fluid and pore surface, is the key parameter determines the NMR surface relaxation times and the wettability. Since ΔE is related to temperature by Arrhenius laws for the correlation time, the wettability of pore surface can be acquired from temperature sensitivity of NMR surface relaxation times. A new wettability measurement method for reservoir rocks has been developed based on this temperature dependence of NMR relaxation time. The proposed method is also capable of measuring the wettability of porous media under any saturation level which conventional method cannot provide. The verification of the method has been conducted with 1 sandstone and 4 carbonates rock cores.