bluuebunny/crossref_metadata_2025_split huggingface dataset:
Flow Assurance Implementation for a Successful Fast Track FLNG Relocation
Authors: Wan Hashim Wan Mahsuri , Azuhan Aimi Samihah , M Norpiah Rohaizad , Idrus Aishah , M Johar Juhaida 
Published: November 2020

Abstract
One of the advantages of a floating LNG (floating Liquified Natural Gas) plant compared to an onshore plant is its capability to relocate from one location to another. For better economic opportunity, an existing FLNG plant is relocated to a new offshore location, 450 km away. Several studies are conducted prior to commencement of the relocation. One of them is to evaluate flow assurance issues before, during reconnection to the new facility, commissioning, start-up and subsequent operations. These aspects are evaluated through steady state and transient simulations, in particular to identify major issues that may require additional equipment or significant operational changes to mitigate the consequences arising from conditions at the new location.
The main objective of flow assurance study at the initial project stage is to identify and specify Long Lead Items (LLI). Two of the LLI aspects that had to be finalised early are pipeline size and distance between the gas exporting platform and FLNG vessel to meet FLNG's feed gas arrival temperature specification. At design flowrate, it is observed that Joule-Thomson (J-T) cooling resulted in fluid temperature arriving at FLNG riser below ambient temperatures. Parametric studies are also performed for commissioning, black start-up and gas ramp-up, based on operational experience at the first location. Recommended optimum start-up sequence is successfully employed during commissioning and recorded data is found to be comparable with results from simulations. Flow assurance is one of the critical considerations to relocate an FLNG vessel and associated systems to a new location. This paper explains how the study was done and shares the start-up experience for industry's first operational FLNG.
Reservoir Characterization Supported by Rock Physics Diagnostics
Authors: Gelinsky Stephan 
Published: November 2020

Abstract
To be of practical use for reservoir characterization, rock physics models are often perceived as too complicated and as dependent on too many difficult-to-measure parameters. Here we demonstrate how careful calibration of a common and quite simple rock physics model can provide valuable insights into the reservoir and seal elastic properties as function of porosity, fluid and mineral properties, andnet-to-gross. The model canbe used for quantitative seismic interpretation of reservoirs with variable net-to-gross and porosity away from well control.
We show that the Hashin Shtrikman Upper Bound is useful to model the compressional and shear velocities of grain-supported clean sandstones as function of porosity, whereas matrix-supported claystone compressional velocities follow the concaveHashin Shtrikman Lower Bound. The corresponding shear velocity shale data plot similarly but for the Lower Bound to be useful to model shale shear velocities the clay-bound-water needs to be modeled with a small but finite shear stiffness. This update alsoimproves the shale compressional velocity model fit. The resulting unified compressional and shear Hashin Shtrikman model allows for the calibration of a sand-shale mixing model that can be used to interpret seismic-derived acoustic and shear impedances in terms of sand net-to-gross and porosity away from well control.
Enhanced Safety and Optimized Cost for Fire & Gas Detection System Design using Risk based Approach Methodology and Computerized 3–Dimenional Fire & Gas Mapping Software
Authors: Chua Kien Kek , Tan Fang Yee , NG Chien Han 
Published: November 2020

Abstract
Assessing the effectiveness of a fire and gas detector installation is critical in enhancing safety in oil & gas industrial environments, but currently there are limited software tool to effectively perform such function. Traditional methods of ascertaining fire and gas detector locations currently leverage on rules-of-thumb or estimates which would result in either over or under-engineering. Often, these guidelines were established without any proper validation of their effectiveness. An innovative methodology has been developed which coupled with simulation software called fire and gas mapping in determining placement of detector in systematic and effective ways meeting international safety standard.
Mapping studies has been deployed to more than 30 Oil and gas brown field sites as well as new projects. The application of fire and gas mapping has resulted in the optimization of fire and gas detectors at facilities where over-engineering was seen. At the same time areas with insufficient coverage were prescribed with additional detection. Engineering companies which has applied such methodology and conducted the mapping studies recognized the benefits of such structured risk based evaluation of fire and gas detectors. This new approach has gained popularity and rapidly becoming the best practices adopted in the industry.
Enhanced Oil Production with Autonomous Inflow Control Devices in a Thin Oil Rim Reservoir Malaysia
Authors: Tusimin Fuziana , Riyanto Latief , Ahmad Tajuddin Norbaizurah , Moradi Mojtaba , Marimuthu Raam , Konopczynski Michael 
Published: November 2020

Abstract
The added value of greater reservoir contacts with horizontal wells will be minimisedby an uneven reservoir sweep along thewellbore as the well may intersect heterogeneous formationswith varying properties. This results in early water and/or gas production in thewell. These challenges can be mitigated by deploying Autonomous Inflow Control Devices (AICDs)that can manage the reservoir fluid influx alongthe wellbore and therefore optimise the performance of well.The design of the well completion with inflow control devices is oneof the important steps in field development planning with a strong influenceon the production profileand thereby the economics. An integrated workflow was followed to deliver successfully the first AICDapplication for PETRONAS-Malaysia in an offshore oil reservoir with huge uncertainties in remaining oilthickness and current fluid contacts. The workflow comprised pre-drilling studies including AICD flow looptesting, well candidate selection, flow performance evaluation (static/dynamic modelling) and post-drillinganalyses including real-time completion design, history matching and comparison ofproduction data with neighbouring wells.
In the 2018 infill development campaign, improved productionwas targeted by the installation of AICDs in wells atoffshore Sarawak. AICD completions ensurebalanced contribution from all reservoir sections and limit gas and water production. The chosenhorizontal well was drilled in a very thin formation with the oil rim average thickness of 13ft, the thinnestAICD application to date. The well intersected two geological layers with differentproperties.Alarge gas cap and an aquifer were located above and below the well. The oilproduction from this well was expected to be impaired significantly due to a high probability of early waterand gas breakthrough, potentially within days or weeks. Two analogue wells drilled in 2013 suffer from both issues despite being completed with passive ICDs. Through teamwork between the companiesinvolved in the campaign, the well was successfully completed with an RCP AICD completion. The wellwas segmented in several compartments and a tailored AICD completions was designed to restrict theproduction of unwanted fluids properly. The AICD completion has delivered a 200% increase in oilproduction while it has significantly reduced GOR (up to 90%) and water cut compared to several offset wellswith various other completions.The AICD is an active flow control device that delivers a variable flowrestriction in response to the properties of the fluid and the rate of flow passing through. The lessonslearnt from pre and post-installation studies will be discussed here. The AICD completions enabled theoperator to implement an optimum reservoir drainage strategy that uses downhole control which willbe manipulated autonomously based on well dynamic condition instead of surface control.
Drilling Fluids Optimization – A Case Study in Overcoming Drilling Challenges in Excessive Over Balanced, Loss Circulation and Wellbore Instability Environment
Authors: B A Razak M Solehuddin , Ong Sheau Hun 
Published: November 2020

Abstract
The paper presents a case study of an Operator who successfully drilled two challenging wells through optimization of the drilling fluids. Well A was a HPHT well drilled with mud weight up to 18.6 ppg with overbalanced pressure as high as 6,800 psi – the highest overbalanced pressure experienced by the Operator to date. Well B was required to drill through depleted sand and unstable shale where series of severe loss circulation and wellbore instability issues were experienced in the nearby wells.
Due to its HPHT nature, the design of the drilling fluids in Well A was expected to have a total solids content up to 70% by volume. Due to this high solid content, the rheology of the fluids system is inherently high posing an issue related to excessive ECD. To further exacerbate the issue, the extreme differential pressure which was expected to be observed in Well A requires the inclusion of bridging material in the system as part of the mitigation plan to minimize the risk of differential sticking. Conventional bridging material such as calcium carbonate and graphite with concentration between 20 to 40 ppb will further increase the amount of solids in the system. Likewise, in Well B, the Operator also observed that the application of common bridging material in the drilling fluids does not help in addressing the severe losses and wellbores instability issue observed in the offset wells. Almost 60% of the offsets encountered severe loss circulation as high as 6,000 bbl mud loss per well.
This paper will share several initiatives by the Operator during the design stage in order to optimize the mud formulation to address the challenges for both of these wells. These include evaluation of various types of bridging material and "a must have" mud testing to assess the performance of the drilling fluids system. Subsequently, the Operator has successfully drilled these wells with no issues related to differential sticking, loss circulation and wellbore instability.
Drillstem Testing at 436°F Using a Retrievable Packer and Multicycle Circulating/Tester Valve: Case Study
Authors: Sarode Mahesh , Khati Milind , Haddad Josmar 
Published: November 2020

Abstract
A leading exploration and production company in India drilled a high-pressure/high-temperature (HP/HT) well in eastern offshore India and required drillstem testing (DST) to be conducted using the service company's multiple-set HP/HT retrievable packer, multicycle circulating valve, and multicycle tester valve. The bottomhole temperature at reservoir depth was approximately 460°F. This case study discusses the recently conducted DST of the HP/HT well by one of the largest global oilfield service providers in collaboration with the operator.
The HP/HT environment presented many challenges. The operator initially decided to deploy a permanent packer; however, after comprehensive preoperation planning with the service provider, the decision was made to run a retrievable packer to save time and costs associated with setting and milling/retrieving a permanent packer. The hook-wall concentric bypass, 7-in. retrievable packer was designed and tested for HP/HT environments. It was decided to deploy a full-suite multicycle DST tool string rated to 450°F. To help ensure a higher success rate for the long duration of the test, a clear fluid system of lower weight (14.6 lbm/gal) was used for reliable functioning of the annulus pressure-operated DST tools after a hermetical test and heavy kill mud (15.7 lbm/gal) was used for the well kill operation.
Deploying a full suite of annulus pressure-operated, multicycle DST string rated for HP/HT conditions permitted the testing of the well to be performed safely and efficiently without any breach to safety and service quality. The initial cleanup, three-bean study, and downhole buildup were successfully completed.
Temperature recorded in this well at the 7-in. retrievable packer depth was 436°F, and the reservoir temperature was extrapolated to approximately 460°F. The reservoir was successfully tested with an annulus pressure-operated multicycle DST string designed to withstand the challenging HP/HT environment.
The operation set a new global record, which is the highest recorded bottomhole temperature during DST using the service company's retrievable packer and multicycle DST tools.
Cementing Production Casing for Steam Injection Wells: Case Study Wells Drilled in the Western Desert Region of India, Rajasthan
Authors: Ganguly Bibek , Sarma Arindam , Kumar Animesh , Fortner Kelly 
Published: November 2020

Abstract
Steam injection is a fundamental method for enhanced oil recovery (EOR) wherein the wells are drilled and steam is injected to heat the crude oil in the formation to help reduce viscosity and improve oil recovery. The best practices for zonal isolation in the Baghewala field in India are discussed in detail. For desired zonal isolation, cement should maintain long-term stability once placed. Pressure and temperature changes can cause failure within the set cement.
An effective annular seal designed in these wells will be exposed to high temperature, cyclic stresses, and potentially corrosive environments caused by the injection of high-temperature steam into the wellbore. The design stage should go beyond cement placement, compressive strength, and gas-migration prevention. The solution is rooted in the synergy between diagnostic tools and engineered cement systems. Such design methodology was developed to address the challenge of the loss of zonal isolation caused by changes in the wellbore that can stress the cement sheath and cause destabilization at any point during the life of the well.
Specific to the cyclic steam injection in the Baghewala field, a cement system was designed to address the following challenges: Achieving cement returns to surface without fallbackHelping ensure the cement system is thermally stable at the maximum expected temperature (i.e., no strength retrogression, radial cracking, debonding, etc.)Achieving a good cement bond throughout the open and cased holesHelping prevent wellhead growth during steam injectionEncountering different types of formations (halite, anhydrite, sand, and carbonate) in this fractured reservoirUsing a cement slurry designed to avoid strength retrogression of set cement during exposure to high-temperature injection
Proprietary 2D hydraulics, finite element analysis (FEA), and 3D displacement simulators are analytical tools designed for simulations or investigative modeling to simulate fluid properties and slurry placement during operations. Additionally, they help reduce the need for costly remediation and positively affect the long-term cement sheath integrity by assessing and addressing issues before they become problematic.
More than 10 wells were successfully constructed with no issues reported during/after cyclic steam injections, which is endorsed by excellent cement bond logs. This helped minimize multiple potential risks and ultimately maximize production.
The cement design technology associated with FEA simulations and analysis provides the ability of the set cement to expand and contract in sync with the well's fluctuating temperature, reducing stress on the cement sheath. This occurs because these cement systems have approximately the same thermal expansion properties as the steel casing. Unlike conventional cement, particles can expand and contract thermally, thus reducing cement-sheath stress six times more than conventional systems.
Remote Support Technology of Bozhong 19-6 Drilling Engineering
Authors: Xu Tong , He Pengfei , Yu Zhongtao , Yuan Hongshui , Yuan Zeming 
Published: November 2020

Abstract
During the drilling operation, a number of data is not processed and analyzed effectively, and related problems are not researched thoroughly. In addition, wellsites are lack of timely technical interactivity and remote support with the base. In order to solve these problems, an auxiliary decision-making system for drilling was established. Also, a real-time dynamic drilling and completion database was studied and newly built, and the calculation models (e.g. coupled hydrodynamic model, drag and torque model, and ROP optimization model) were integrated with drilling simulator as the core, and thus real-time dynamic simulation, three-dimensional visualization and remote drilling monitoring while drilling is realized. Finally, based on its application in 9 wells of BZ19-6 exploration project, combined with friction factor inversion method, hydraulic simulation fitting method and stage correction method, the simulation accuracy of hookload/torque/hydraulic was above 90%, the monitoring accuracy of pore pressure was up to 97%. What's more, remote technical support based on expert consultation has been carried out accumulatively over 20 times. And eventually, a set of structure and method of remote auxiliary decision-making system for drilling based on transient simulation analysis was established.
Application of Probabilistic Method in Development of PRSM
Authors: Girsang Christian Hariady , Yusoff Norhayati , Nasri Huang Noorizal , Rohani Muhammad Joehan , Abdul Rahman Azam 
Published: November 2020

Abstract
Regional Suitability Mapping (PRSM) was initiated in 2013 with the aim of optimising operational cost efficiency and minimising potential incidents during jack-up emplacement, particularly incidents due to punch through failure. In the later stage of PRSM, a pilot study was carried out to assess punch through failure using probabilistic method. The proposed approach is found to be readily applied to multiple locations by using a standardised computational model. The probabilities of punch-through at 100 locations in Malaysian Waters were studied using this approach for Keppel FELS B Class jack-up rig in strong clay over weak clay scenario. The study indicates that the majority of boreholes fell into the extremes, either having less than 10 % probability of punch-through, or more than 90 % probability of punch-through. It was concluded that the proposed probabilistic approach enables the probability of punch-through in strong clay overlying weak clay profiles to be quantitatively computed such that the risk can be objectively evaluated. This is an advantage as compared to the standard industry practice which is to perform deterministic leg penetration analysis based on two design strength profiles corresponding to the low and high estimates.
Mechanism and Risk Assessment of Shallow Water Flow Based on Laboratory and Numerical Studies
Authors: Shentu Junjie , Lin Botao , Jin Yan , Shi Can 
Published: November 2020

Abstract
In the deep-water hydrocarbon recovery, the over-pressured sand originating from fast sedimentary compaction brings about difficulties in well control during drilling practices. When encountered by a drill bit, the sand section will generate shallow water flow (SWF) that could substantially jeopardize the integrity of the drill string and the associated equipment, eventually leading to drilling failure. The SWF hazard has been one of the predominant geological hazards in the deep-water drilling operation nowadays. Therefore, it is crucial to accurately identify the SWF hazard, estimate the risk, and take the appropriate measures to minimize the engineering and economic losses. In this study, a set of experimental facility and workflow were proposed, in order to investigate the flow failure behavior of the over-pressured sand section. The experimental findings indicated that the initial overpressure was one of the principal factors of the SWF hazard. Accordingly, a discrete element method-computational fluid dynamics (DEM-CFD) coupling approach and was proposed to model the process of the SWF hazard. The results of the numerical simulation were verified by the behavior of sand transportation disclosed in the laboratory experiment. The simulation showed that the sand production of a specimen increases with three influence factors, including the initial overpressure, the porosity and the sand grain size. Some critical points were discovered and studied in the investigations of each influence factor, and the rising tendency of the curve tended to undergo a dramatic increment at the critical point. Finally, the SWF risk prediction chart was proposed for the fast and convenient identification and evaluation of the SWF risk.
Zirconium Crosslinkers: Understanding Performance Variations in Crosslinked Fracturing Fluids
Authors: Almubarak Tariq , Ng Jun Hong , Nasr-El-Din Hisham A. , Almubarak Majed , AlKhaldi Mohammed 
Published: November 2020

Abstract
Borate crosslinkers are the most commonly used crosslinker in fracturing fluids. However, they exhibit lower performance at high temperature, high pressure, high water salinity, and low pH applications. Consequently, zirconium crosslinkers are utilized to address these limitations. Zirconium crosslinking chemistry is complex and depends on many factors such as pH, metal to ligand ratio, ligand order, ionic strength, and type of polymer used, which in turn influence the delay time, thermal stability and shear resistance performance.
This work evaluates the rheological performance of four different zirconium crosslinkers with a biopolymer and a synthetic polymer. The tested crosslinkers are manufactured in different chemical structures. The two polymers tested are 40 lb/1,000 gal CMHPG and 40 lb/1,000 gal synthetic polymer. The rheological performance was measured through HPHT rheometer (100 s−1 shear rate) at 200-400°F for 2 hours. The shear tolerance performance was also evaluated under a custom shear rate schedule (100-1000 s−1).
The results show significant variation in crosslinking performance due to the changes in crosslinker chemical structure and type of polymer used. Zirconium lactate and propylene glycol crosslinker shows the highest enhancement in shear and thermal stability with CMHPG based fracturing fluids. Surprisingly, the same crosslinker performed the least with synthetic polymer-based fracturing fluids. However, Zirconium triethanol amine and lactate showed significant enhancements in shear and thermal stability with synthetic polymer-based systems. The results also show and discuss the influence of systematically changing crosslinker ligand order in CMHPG and synthetic polymer-based fracturing fluids.
The work studies the influence of the zirconium crosslinker chemical structure on the rheological properties of both biopolymer and synthetic polymer-based fracturing fluids. The performance evaluation shows that delay time, shear and thermal stability can be enhanced by manufacturing the appropriate crosslinker chemical structure, thus reducing additional additives required used and saving cost.