bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mitigation of Slim Open Hole Wireline Logging Risk Under High Overbalance Conditions
Authors: Siregar Ronald , Ramli Safuan , Turner David , Prachayarittikool Kachin , Iffwad Mohammad 
Published: March 2022

Abstract
The oil and gas fields offshore Malaysia-Thailand border are well known for the presence of high pressure and high temperature reservoir characteristics. The hot environment favours the use of hostile wireline logging tools over logging while drilling tools for some measurements.
High overbalance conditions are sometimes a necessary requirement to safely drill particular formations but bring with them operational challenges. For wireline logging a critical hazard is that of becoming differentially stuck, especially in the case of stationary logs such as pressure measurements, sampling, and coring. A reduction in allowable safe stationary times for these measurements can also compromise the quality of the results.
Production wells in this area are generally drilled with slim 6-1/8″ sections through the reservoir. As the borehole becomes smaller the risk of sticking increases as the tool contact area increases and so is a particular concern in slim holes. This often leads to logging being run using costly pipe conveyed methods or the inability to obtain required data altogether.
This paper presents case histories of wireline formation pressure testing and sampling in 6-1/8″ sections with high deviation, 3D trajectory boreholes with overbalance pressures of over 2,000 psi. The use of a high-performance roller system to create tool stand-off to mitigate differential sticking as well as eliminate friction is described, along with the use of an engineered hole finder to address hole access concerns. The importance of wireline simulation models to identify risks and test solutions in such conditions is also considered.
Slim hole logging and logging under overbalanced conditions are often a source of concern for subsurface, drilling and service company personnel alike. Describing a successful approach to address both is of interest to all involved parties and should provide ideas and confidence to plan cost-effective logging in similar wells.
L53-DD, On-Shore Thailand a Case Study of Integrated Geoscience to Engineering Approach Improving Reserve Estimation and Field Development Planning
Authors: Yew Zhen-Xuan , Kosolpinete Monthathip , Lerdsuwankij Thiti , Sen Gargi , Harun Mohd Fadzil , Duangprasert Tanabordee , Noomee Lakkanaporn , Thongseng Jeerisuda , Wongsawat Thanitha 
Published: March 2022

Abstract
The study emphasized on a collaborative work across various domains to improve reserve estimation utilizing integrated analysis from geological understanding, seismic interpretation, petrophysical log to sampled pressure and production data. A cross-disciplined approach was tailored for this complex marginal field and it included a fast loop full-field reservoir modeling and simulation to delineate the reservoir characteristics in a timely manner.
The study improves the confidence level in reserve estimation of the field with a range of 30-35% primary recovery factor interpreted across different sands which is in line with other publications that in a typical Gulf of Thailand oil reservoir, in the presence of a strong water drive, the most likely primary recovery factor is between 18-40%, depending on the thickness of the oil column, bottom water versus edge water and the presence of a gas cap. The study helps to drive real field decision making for upcoming drilling campaigns to further improve the economic life of the field. This paper presents a fit-for-purpose reservoir modeling while drilling approach demonstrating how the company used newly drilled well data to validate the reservoir model and to drive new decisions for field development planning.
The industry has limited published case studies on medium to heavy oil (19 to 25 degree API) with strong aquifer support in the region of onshore Thailand. This case study presents an approach in addressing multiple challenges faced to unlock the high oil potential of the region. In summary, a cross-disciplined, fit-for-purpose and practical approach using latest available commercial technology enabled real-field decisions being made timely and accurately. Similar approach will be undertaken in other fields of the company in the region.
Pressure Transient Behaviors of Discretely Fractured Reservoirs Using a Numerical Discrete Fracture Model
Authors: Chen Zhiming , Zhou Biao 
Published: March 2022

Abstract
The conventional dual-porosity model (Warren and Root 1963) may not apply to naturally fractured reservoirs which have poorly connected fractures. To narrow this gap, a discrete fracture model based numerical well testing (NWT) model is developed for pressure transient analysis in vertical wells interacting with natural fractures.
The accuracy and practicality of the proposed model have been demonstrated by model verifications. The results show that the flow regimes of the vertical well interacting with natural fractures can be divided into wellbore storage and skin effects, bilinear flow, linear flow, radial flow, natural-fracture (NF) effect, and boundary-dominated flow. This radial flow is the radial flow of the formation before pressure propagates to natural fractures, which is virtually quite different from that in the conventional dual-porosity model (Warren and Root 1963). However, there are no bilinear and linear flow stages in the vertical well interacting with no natural fractures. It is found that the vertical well interacting with natural fractures has a lower pressure depletion. It is also found that the "V-shape" caused by the NF effect in the pressure derivative curve becomes deeper when there are more natural fractures, longer natural fractures, and higher fracture conductivity. Furthermore, the "V-shape" appears earlier and the duration of the NF effect is longer as the number of natural fractures increases. Besides, with the decrease of the distance between the fracture and well, the impacts of natural fractures on pressure transient behaviors of the vertical well are more significant. This work provides a meaningful way to understand the pressure transient behaviors of discrete natural fractures.
Injector Design Plays an Important Role In Maximisation of CO2 Trapping in Geological Formations
Authors: Chidambaram Prasanna , Patil Parimal A , Tiwari Pankaj Kumar , Das Debasis P , Tewari Raj Deo 
Published: March 2022

Abstract
Storing CO2 in geological formations is gaining greater importance as various companies start transitioning towards a carbon neutral future. CO2 storage in depleted hydrocarbon reservoirs and saline aquifers is considered an effective and secure option to reduce atmospheric CO2. Once underground, four different mechanisms keep the supercritical CO2 securely stored. The mechanisms, in increasing order of storage security are, 1. Structural/stratigraphic trapping, 2. Residual trapping, 3. Solubility trapping, and 4. Mineral trapping. Optimization of injector design to increase the amount of CO2 trapped in one of the more secure mechanisms is desirable.
Structural trapping is the most dominant and least secure trapping mechanism for CO2 storage. Any opportunity to move structurally trapped CO2 into one of the other trapping mechanisms is preferable from the standpoint of storage security. Mechanistic models are used to study ways to improve amount of CO2 trapped by certain mechanisms. Residual trapping is affected by several factors including path traveled from perforation to the top of the structure. Similarly, solubility trapping is influenced by several factors including the amount of contact CO2 has with water. Injected CO2, due to buoyancy, rapidly rises to the top of the structure. There is potential to increase residual trapping and solubility trapping by optimizing the injector design to increase volume of reservoir contacted by CO2.
Mechanistic modeling study shows that residual trapped and solubility trapped CO2 volume can be increased by optimizing injector design. There is up to 50% improvement observed in both trapping mechanisms depending on the reservoir characteristics and injector design. Interestingly, lower permeability reservoirs are more sensitive to injector design compared to higher permeability reservoirs. Of the injector designs studied, horizontal injectors placed at the bottom of the structure show the most improvement in both residual and solubility trapping mechanisms. Pressure of the reservoir also influences trapping mechanisms. At higher reservoir pressures, density difference between CO2 and water is smaller. This affects how CO2 plume migrates in the reservoir.
The Achievement of Resource Optimisation on Lean Remote Wellhead Platform Visit with Collaborative 52 Weeks Plan
Authors: Zar Soe Thin , Leelaratsameephanit Anucha , Jitputti Phanuwat , Charoensook Sayan , Rodthip Alongkorn , Chitkla Sathit , On-Dam Apichai , Sirijitt Perapon 
Published: March 2022

Abstract
To survive in oil and gas industry, Operating Expenditure (OPEX) must be well controlled for profit maximization. One of the most resource-utilizing activities in Zawtika offshore field is remote wellhead platform (WHP) visit which was previously bi-weekly for operations activities, maintenance activities such as preventive maintenance (PM), etc., inspection activities like flowline erosion monitoring and wells annulus pressure monitoring, thereby high Marine Gas Oil (MGO) consumption due to vessel trips/routes and increased in manpower utilization. Currently, Zawtika Offshore field has a main platform called Zawtika Processing and Living Quarter Platform (ZPQ) and 10 remote wellhead platforms (WHPs). When it is considered for future, there will be more remote wellhead platforms (WHPs) which will increase more OPEX for new phases.
To tackle this, this paper describes that Myanmar Asset Zawtika launched a LEAN (Lean Six Sigma) initiative based on safely and cost-effectively reducing the frequency of remote wellhead platforms (WHP) visits, using collaborative 52 week planning to lessen OPEX cost from MGO consumption and manpower requirements as well as maintaining Zawtika Reliability and Asset Integrity (RAI) with the view of achieving resource optimization. This paper also illustrates the effective planning process across multiple functions/disciplines within different sessions/departments and at various locations called 52 weeks plan incorporating with "Integrated Operation Plan (IOP)" guideline established for the first time for Zawtika offshore field to help optimize the resources and activities plan of individual field or asset by ensuring the safety while sustaining the integrity. This paper also outlines the reduction in Greenhouse Gas (GHG) calculated back from MGO reduction which is one of PTTEP strategies for Sustainable Development (SD).
Pegaga Development Drilling Operations with PMCD and CDIV Applications
Authors: Mohammad Annas Omar , Bakar Azlee Abu , Mohd Khaidzir Khairil Azam , McKen Donald Robert , Yeow Lei Ming , McCluskey Timothy James 
Published: March 2022

Abstract
This paper describes the implementation of Pressurized Mud Cap Drilling (PMCD) and Casing Downhole Isolation Valve (CDIV) technology for the Pegaga Development Project to mitigate heavy fluid losses, allowing safe and effective drilling operations to reach well TD. The project consists of seven gas producers (deviated wells), drilled using a jack-up rig from a 10-slot wellhead deck.
This paper also describes the planning and operational challenges met to ensure the smooth application of PMCD, starting with selection of the rig and supply vessels, challenges related to adverse weather conditions, long distances between the supply base and drilling location, sufficient mud tank capacity, continuous supply of Light Annular Mud (LAM) for PMCD operations and pandemic related personnel movement restrictions.
A continuous learning process was applied for the drilling team where challenges experienced in drilling the first well in PMCD mode and lessons learned were captured and applied to the subsequent wells to improve drilling results. A comprehensive decision tree was established and refined to help the offshore team to make quick decisions when needed to switch to PMCD mode.
The Pegaga gas field is located in Block SK320 in the Central Luconia Province, off the coast of Sarawak, offshore Malaysia. The main reservoir is a Pinnacle Carbonate reservoir, which is made up of vugular/karstified carbonates that are likely to cause severe or total losses.
The top-hole sections for all seven wells were batched drilled before the PMCD system was rigged up prior to commencing the 12-1/4" intermediate and 8-1/2" reservoir hole sections. The 12-1/4" sections were drilled to above the target gas reservoir carbonate formations, with the PMCD system on standby in case the carbonate formations and severe losses were encountered shallower than prognosed. A single 9-5/8" CDIV (NACE standard) was run with the 9-5/8" × 10-3/4" casing string and permanently set (cemented) in the 12-1/4" open hole, which was the first time this had been done in Malaysia. The CDIVs were set in the open hole to reduce the potential volume of gas below the CDIV and reduce the mud volume required for tripping in PMCD conditions, while increasing the safety and efficiency of PMCD operations.
Seven wells were drilled to TD, five in PMCD mode, two conventionally. The lower and upper completions were run and set on six wells, with four of the lower completions run and set in PMCD mode. The CDIV was used to isolate the open hole for tripping out the BHA and running in the lower completion on two of the PMCD wells, while the other three used the top kill method.
Geological Field Characteristic of the Black Shales in the Belata Formation, Peninsular Malaysia
Authors: Owusu Esther Boateng , Tsegab Haylay Gebretsadik , Abubakar Rabiatuu 
Published: March 2022

Abstract
Peninsular Malaysia is made up of three fundamental stratigraphic belts; the Central Belt, the Eastern Belt, and the Western Belt with little data on their shale lithologies. The Belata Formation is situated in the Western Belt and is at the southernmost part of Tanjung Malim in the Perak State bordering the Selangor State. Belata Formation falls in between the Terolak and the Karak formations to the north and south respectively. Six Carboniferous shale outcrops were discovered during fieldwork. Outcrop description, sample collection, and laboratory studies were conducted on the Belata Formation. The outcrops include shales that range from black to grey. For laboratory investigation, twenty-two samples were obtained from the shale outcrops. Total organic carbon (TOC) analyses carried out on the samples revealed an average of 3.4 wt. %. The black color is possibly introduced in these shales because of organic matter incorporated in the sediments. Hence, these shales tentatively could be regarded as potential shale gas exploration targets in the Peninsular. However, the effect of the regional rnetarnorphisrn which affected the Sibumasu Terrane should be considered even though shales are not affected by contact metamorphism due to their distance further away from the granitic intrusions.
Preventing Halite Scaling in Offshore Pipelines Using Integrated Scale Management System and Modeling – Case Study from Gulf of Suez, Egypt
Authors: Darwish Abdallah Magdy , Khalil Ahmed Kamal , El-Dessouky Mohamed El-Hussein , Mohamed Islam Ibrahim , Abdelhalem Tamer Hosny 
Published: March 2022

Abstract
Halite scaling has a dreadful impact on production pipelines. Produced water from Nubia formation in "E" field has high level of total dissolved solids (TDS) concentration. Halite scale causes complete blockage of the flow paths, integrity complications and periodic production interruption. Pipeline pigging and flushing with fresh water were performed frequently to eliminate blockage and restore production.
An offshore platform with six online gas lifted wells; two high rate wells are producing from Nubia formation through the production pipeline and the remaining low rate wells are producing from other formations with a lower TDS through the test pipeline. High saline water flows through the production pipeline and cools down to seabed temperature resulting in halite precipitation, which regularly blocks the pipeline and requires repetitive fresh water flushing and pigging operations. Laboratory water analysis and scale tendency were conducted in conjunction with a pipeline network model to predict the halite precipitation temperature, actual friction coefficient and optimum fluid mixing and dilution strategy.
The combination of complete water analysis, scale tendency, real time remote monitoring system and pipeline network modeling showed that halite scaling started inside the subsea pipeline nearby the platform. The model matching revealed a high friction coefficient, which indicated partial plugging of the production pipeline. The model sensitivity analysis predicted that diluting the supersaturated water by mixing it with other wells’ lower salinity waters – into the same pipeline, would drop the mixture salinity with no halite scaling along the pipeline. As a result, the strategy of mixing was selected and optimized based on the modeling results and water compatibility tests to reduce losses due to back pressure and to minimize the risk of hard scale deposition. For more than a year, no halite has precipitated, which resulted in an uninterrupted production and allowed well testing of the remaining wells discretely through the test pipeline.
This paper demonstrates a comprehensive case in which halite scaling issues were predicted and mitigated through an integrated scale management system. The operating expenditures of pipeline flushing and pigging operations and oil losses were decreased due to interrupted production.
Cost Effective Framework of Integrated Development of Offshore Marginal Oilfields - Case Study of a Heavy Oil Reservoir with Thin Layers
Authors: Liu Yingxian , Shi Hongfu , Xu Zhongbo , Zhang Wenjun , Wang Xinpeng 
Published: March 2022

Abstract
The Bohai bay is rich in oil and natural gas resources. Over the past 40 years, a series of different types of large and medium-sized offshore oil and gas fields have been successfully discovered and developed. The newly discovers, however, is marginal either smaller in size or poor in reservoir quality which can't be economically and efficiently developed with the current conventional exploitation methods. The development of such marginal assets is of great significant for the the sustainability of Bohai production.
In this paper, L oilfield is taken as an example to explain how to establish a framework in developing such marginal oilfields cost-effectively through multi-disciplinary cooperation. The L oil field is one of the typical marginal green-oil fields discovered recently in the Bohai Bay which characterized as low OOIP, limited certain reservoir spaces for well placement and challenges economically for standalone development (Adeogun Oyebimpe, August 2018, Mohamed, A. Zakariya.March 2003). In addition, primarily thin oil layers at the average single layer thickness only 2.1 m, high crude oil viscosity at the average of 2000mpa·s, and low single well productivity less than 300 barrels per day. However, the L oil field geographically is next to a large oil field which is only 12km away. How to maximize the success chance of penetrating the sweet spot of those thin layers, and therefore achieve higher initial oil productivity, to form a complete injection-production well pattern for long period stability in production and to minimize capital investment through joint development with surrounding oilfields is the way out for L oilfield development.
Innovative Rigless-Deployed Electrical Submersible Pump ESP System for Installation at Floating Deep-Water Production Platform
Authors: Raman Intiran , Wardhana Yulian , Selamat Kasim , Shepheard Barry , Ghazali Muhammad Nabil , Blacklock Jon David , Tulathammakit Hattaya , Liu Zengzhen , Bathmanaaban Gopalan 
Published: March 2022

Abstract
Installing an electrical submersible pumping (ESP) system in an oil well is one of the optimal artificial lift methods to increase production and maximize ultimate recovery. However, installing and retrieving an ESP using an offshore rig is costly and presents planning challenges. In some geographies and projects, offshore intervention rig costs and risks sometimes outweigh the potential gains of an ESP system.
An operator in Malaysia was interested in installing an ESP system in an offshore well to maintain production rates, but the intervention costs were a roadblock. The challenge was to devise a rigless ESP deployment system that can be deployed through the existing completion to avoid the need for a rig, even on the initial deployment. The system would need to provide a 2000 BPD flow rate to justify the initial investment of the wellhead modifications, surface equipment, the newly developed rigless-deployed ESP system, and completions accessories.
This new generation rigless-deployed ESP system features an inverted ESP with the ESP motor on top, connected directly to the power cable. This revolutionary design eliminates the motor lead extension, removing the weakest connection in traditional ESP systems. The rigless deployed ESP system enables deployment under live well conditions, eliminating the need to kill the well and the need for a rig – inclusive of the initial deployment. This paper reviews the design and deployment process of the first installation in Southeast Asia.
An Experimental Investigation into the Potential of a Green Alkali-Surfactant-Polymer Formulation for Enhanced Oil Recovery in Sandstone Reservoir
Authors: Tackie-Otoo Bennet Nii , Ayoub Mohammed Mohammed Abdalla , Mohamad Ghani Muhammad Faiz , Jufar Shiferaw Regassa , Hassan Anas Mohammed 
Published: March 2022

Abstract
Despite the promising nature of alkali-surfactant-polymer (ASP) flooding, its application is limited by various technical issues and environmental concerns. The goal of mitigating the impact of these limitations has led to research into the oil recovery potential of alternative chemical agents. This study, therefore, focuses on investigating the potential of a "green" ASP formulation composed of monoethanolamine (ETA), sodium cocoyl alaninate (SCA) and Schizophyllan (SPG) for its enhanced oil recovery application. A conventional ASP formulation comprising sodium carbonate (Na2CO3), Sodium Dodecyl Sulfate (SDS) and partially hydrolyzed polyacrylamide (HPAM)was deployed for comparative purposes.
The hardness tolerance of the green ASP shows that surfactant precipitation and scale formation could be mitigated. Lower surfactant concentration required to achieve low IFT and contact angle upon addition of alkali shows synergism in interfacial properties and wettability alteration. The ETA–SCA system yielded a better synergy in IFT reduction (minimum IFT of 4.73 × 10-2 mN/m) and wettability alteration (contact angle of 3° in 600 seconds) than the Na2CO3–SDS system (minimum IFT of 0.22 mN/m and contact angle of 5° in 600 seconds). Nevertheless, the conventional AS formulation exhibited better synergism with brine yielding minimum IFT of 1.52 × 10-2 mN/m. The ETA–SCA system also exhibited the ability to emulsify crude oil and form stable emulsions, a desirable property in chemical EOR processes. ETA had an insignificant impact on SPG's rheology, and the viscosity increased when SCA was added. The ETA–SCA–SPG solution showed shear thinning behavior at low shear rates. The oscillatory studies showed that both SPG and HPAM possess viscoelastic properties, with the green ASP retaining the viscoelasticity of SPG while HPAM loses its viscoelasticity in the presence of Na2CO3. SCA adsorption onto the sand surface was made unfavourable at a threshold of 0.3 wt% ETA. The green ASP formulation achieved an additional recovery of ~22%, while the conventional ASP formulation achieved ~19% additional recovery. Therefore, the green ASP formulation proves to have excellent oil recovery potential compounded by its environmentally benign nature.