bluuebunny/crossref_metadata_2025_split huggingface dataset:
Interactive Experience and Learning Model can Reduce Non-Productive Time NPT
Authors: Brechan Bjorn , Sangesland Sigbjorn , Dale Stein Inge , Aranjo Brendan 
Published: March 2018

AbstractDigitalization is believed to increase efficiency and operational safety while reducing cost. While many initiatives are directed towards automatization of the drilling process, there are other areas that potentially can provide additional cost reductions in the same order of magnitude or more. Founded in the emerging era of digitalization is a new Life Cycle Well Integrity Model (LCWIM) which will change work processes and roles of involved personnel. The model will support work from the planning phase through to the final plugging and abandonment (P&A) of wells. The philosophy used during the systemization of the LCWIM entails reduction of direct human involvement through digitalization and automation. This can reduce the aspect of human error, and focus the efforts of each employee towards the performance aspects of their work. An area where the benefits from this philosophy may be most evident is handling of experiences and improvement. The new work process will allow personnel to establish an experience using the interacive section in the LCWIM. The software would then propose the content of the experience in subsequent planning and well construction work – where relevant. Some other areas where the LCWIM applies this philosophy are in the digitalization and embedding of standards and operational procedures.The oil and gas industry is constantly battling costly NPT in well construction and the production phase. Since the 90ies, there have been many initiatives to reduce NPT. The literature offers many technical improvements that eliminate specific errors and failures in the Well Construction phase, company internal campaigns and methods to focus on the most frequent time thieves, and proactive campaigns to boost performance. Digitalization may provide a step change in the fight against failure in planning and operations by the support of an interactive software built with learning features.The background for the change in work process is maybe best stated by a proverb possibly attributed incorrectly to Albert Einstein: "Computers are incredibly fast, accurate, but stupid. Humans are incredibly slow, inaccurate, but brilliant. Together they may be powerful beyond imagination". A software is not likely to be as brilliant in problem-solving as humans, but it can accumulate and apply all human intelligence implemented over time for every relevant planning and operational situation. Reaching the software's design target ability to adapt to any type of well design and operational situation, the LCWIM can be a considerable tool for increasing safety and reducing NPT.
Addressing Drilling Torque Issues and Redefining Extended Lateral Drilling in Midland Basin, USA
Authors: Chen Zhenyu , Chinh Phan Van , Akkaoui Ziad , Lo Allen , Carrasquilla Maria Neves , Mussa Shadi Altayeb , Gillaspy Micah , Shahid Tanveer 
Published: March 2018

Abstract
Field data have proven that, when drilling extended laterals in the Midland Basin, the rate of penetration (ROP) will significantly decline after the rig's surface torque limit is reached. A high-specification drilling system was introduced to combat drilling torque issues which, in turn, produced record-setting performance.
The approach is to identify which factors have the highest impact on drilling torque when using a motor-driven RSS (rotary steerable system) to drill a lateral longer than 10,000 ft. The field dataset analyzed included trajectory design, simulated torque and drag (T&D) versus actual values, hole cleaning effect, mid-lateral cleanup cycle effect, drilling parameters, target formation, and drilling fluids. The outcomes of torque reduction methods are explained in detail, and the final solution is verified with field results. Furthermore, an improvement plan to double the record lateral drilling speed in the Midland basin while staying within rig's capacity, is also discussed.
When drilling laterals longer than 10,000 ft, a motor-driven RSS can produce an ROP of 300 to 400 ft/hr until the mid-lateral point where surface torque reaches 28,000 to 30,000 ft.lbf. This is also close to the torque limit of 5-in. drillpipe. Comparisons between on-bottom and off-bottom torque suggest an oil-based mud (OBM) system yields lower off-bottom torque and friction than a water-based mud (WBM). Simulated and actual T&D data were studied to find that wellbores with tangent profile in the intermediate section, commonly seen in pad well design for anti-collision, contribute to higher bottomhole assembly (BHA) side forces and friction after the wells drill into lateral section. Drilling parameters also plays a significant role in torque induction since they affect interactions between bit and rock. On the formation side, stringers such as limestone reduce torque. Analysis also concluded that mid-lateral cleanup cycles have minimal impact on torque reduction, and OBM is necessary to extend drilling performance in long lateral wells. An RSS powered by a high-specification motor drilled a 7,000-ft lateral in just 21 hours to set a new high mark in the Permian Basin.
DCA-Based Application for Integrated Asset Management
Authors: Aulia Akmal , Ibrahim Mohd Ikhwan 
Published: March 2018

AbstractWe present a Decline Curve Analysis-based algorithm to rapidly determine the rig drilling schedule (effectively the investment timing) for future large offshore gas fields with the aim of sustaining nominated gas delivery. The algorithm generated schedules for multiple platforms and wells, and incorporates constraints due to facilities and pipelines. The resulting production profile is benchmarked against the profile generated by a full-blown reservoir simulation.The new algorithm takes the gross rate vs time profiles from each well and platform that were generated from standalone reservoir simulation models and the Arps’ empirical model. This well and platform sales gas rate vs time profile will be transformed into sales rate vs cumulative sales gas using relevant CO2 shrinkage factors to deliver gas within sales specifications. The algorithm will seek for contributions from each well/platform to meet the nominated gas delivery based on the current production profile, imposed prioritizations and facility/pipeline constraints. Finally, individual standalone models are coupled into the existing integrated model, and the results are compared against the ones generated by the algorithm.The algorithm (implemented using Visual Basic) is benchmarked against a full-blown reservoir simulation that couples multiple large gas fields with numerous wells. The wells are grouped into 5 platforms; platform A1, A2, B1, B2, and C1. Each platform contains 4 to 5 wells, which are optimized to fit into a single drilling rig campaign if possible. Drilling rig schedules of all 5 platforms are shown to satisfactorily match (i.e., within the campaign) for both the DCA-based algorithm and full-blown simulation. The results from the algorithm reveal that the total gas delivered (i.e., EUR, estimated ultimate recovery) from each platform is consistent with the original EUR. The blended feed gas CO2 profiles generated from both methods also satisfactorily agree. It can also be seen that the plateau of the gas production ends at about the same time in each case. Based on these results, it can be concluded the DCA-based algorithm is an excellent tool to generate multiple forecasts to select the optimal integrated development strategy for multiple gas fields.This new algorithm thus reduces the required time to optimize rig drilling schedules from days to hours. This is a valuable tool that can also alert management on investment opportunities and cost optimizations, in a timely manner before final evaluation and decision making.
Delivering Economic Infill Drilling Solutions with Innovative Re-Engineering and Push of Performance Envelopes
Authors: Ramli Shazwan , Ibrahim Azhar , Liew Alex 
Published: March 2018

Abstract
The operator has faced an uphill challenge to extend the economic life of an existing producing field. The optimal selected solution was to unlock reserves in an adjacent field by drilling an extended reach (ERD) well (Well 1) from an existing platform across a major geohazard fault. In addition to the ERD well, another well (Well 2) was drilled to recover unswept volumes of minor reservoirs in the existing field.
While the ERD ratio of Well 1 maybe only 2.4, the combined complexity of insufficient casing points due to slim hole requirement, narrow drilling margins and crossing a major fault at high angle, pushed the operator's drilling technical and HSE capability to the limit of Malaysia ERD experience. With the only remaining slot on the triple wellhead conductor, this well was the longest well drilled by the operator in Malaysia. These major drilling and geological challenges handcuffed the well design from the get-go, and risk assessments highlighted to stake holders, the risk of failure was prominent without innovative solutions.
This paper elaborates the major challenges and innovative strategies that have enabled successful execution of Well 1, drilled in a fast track drilling program. The team's relentless effort to challenge conventional methods has enabled innovative solutions such as ‘Casing-while-Drilling’ from a splitter wellhead in a congested collision prone platform, use of low rheology drilling fluid for narrow margin drilling as well as top of the line directional equipment. To contain the possibility of exceeding the economic limits, the operator's team also re-strategized the traditionally time based drilling contracting work by implementing the "First in Malaysia" lump sum integrated drilling and completion services contract, where costs were no longer time based, but 100% performance incentivized (IDS and ICS).
ML South: Innovation at Work to Push the Limits and to Deliver.
Authors: Cochet Sebastien , Luongo Matthieu , Martinez Jerome , Tartar Olivier , Bouziane Cherif , Delapierre Adrien , Oghittu Patrick , Roberts Reuben 
Published: March 2018

Abstract
In 2012, TOTAL E&P BORNEO decided to continue the Maharaja Lela South Field (MLS) development by drilling wells with up to 15,000psi on the south panel. This project required the installation of the third well head platform on the field is knowns as the ML South project. In 2016, the new wells drilled were among the most challenging development wells ever drilled in Ultra HP/HT domain, with reservoir pressure up to 17,000psi, well head pressure close to 15,000psi, reservoir temperature up to 165°C, all combined with CO2, H2S and shallow reservoir.
The MLS field is operated by TOTAL E&P BORNEO B.V for the association with Shell Deepwater Borneo Ltd and PB ExPro Sdn Bhd. Mud optimization, drilling procedures and adaptation of the well architecture have been intensively prepared and developed in partnership with Vallourec in order to overcome the extreme field conditions. A 10-½" Premium production casing with 125ksi sour service material was tailor made and qualified for this project in order to withstand the extreme load cases but also to optimize the string weight and maintain similar minimum clearance as with a 10" casing in a 12-¼" hole. On the completion side, the latest generation of premium connection has been intensively tested for the production tubing according to ISO 13679 FDIS:2011 CAL IV protocol, the most severe protocol available in the Industry. A fine-tuned chemistry of the Super 13 Chromium material which successfully passed the corrosion tests as per TOTAL requirements without pitting nor cracks has been developed, industrialized, delivered and finally run in the MLS South wells.
This paper describes how Vallourec and TOTAL have worked together on the development of innovative connection designs; new generation of materials and how the combination of both was able to solve several of the well architecture design challenges historically faced by operators embarking into HP/HT projects.
CFD Simulation of Roll Damping of a New-Build Barge-Shaped FPSO Vessel with Bilge Keels
Authors: Tan J. H. , Teng Y. J. , Kim J. W. , Sinha S. K. 
Published: March 2018

Abstract
Accurate prediction of roll damping is of utmost importance in estimating the roll motion of ships and other ship-shaped floating structures such as floating, production, storage and offloading (FPSO) and floating liquefied natural gas (FLNG) vessels. Roll damping is non-linear in nature and consists of several components including viscous damping which has been found to be highly dependent on flow separation patterns around the vessel. Industry practice of estimating roll damping by means of model testing and theoretical formulae has not always been reliable in estimating viscous damping due to limitations in both model tests and theoretical formulae. It is the objective of this study to use Computational Fluid Dynamics (CFD) methodology to predict roll damping and roll motion accurately for the concept design of a new-build barge-shaped FPSO vessel with bilge keels.
In this study, assessment of roll damping is based on prescribed sinusoidal roll motions applied to the vessel in two-dimensional and three-dimensional CFD simulations. Validation of the CFD prediction is performed using published experimental results. From the CFD simulations, roll damping of a barge-shaped FPSO vessel is found to vary considerably with changes in the bilge corner shapes and bilge keel dimensions. Roll damping increases with bilge keel height and roll amplitude. Results from two-dimensional and three-dimensional simulations show differences which may be attributed to the length of the bilge keels and the bow and stern effect. From this study, the optimum bilge keel configuration for application of this new-build barge-shaped FPSO vessel in moderate environmental conditions is identified in the early design stage.
Development of Online Mercury Measurement System for High Pressure Liquid Hydrocarbon
Authors: Uzaini Tg M , Mat B Tg , Wong Sharizal B Mohd Azam Shah , Hanafiah Ahmad Syukri Na'im B M 
Published: March 2018

Abstract
This paper will share the experience in the development of an online mercury measurement system for high pressure liquid hydrocarbon streams. It focuses on challenges in handling high pressure volatile hydrocarbon, impurities associated with the matrix, particulates, water and mercury concentration. Challenges associated with assurance in sample representativeness, and validation complete with automation are also discussed. The project was initiated to reduce cost of current offline mercury analysis, the need to minimize analytical error, expedite acquisition of analytical results, and minimize personnel exposure to mercury during manual sampling and analysis.
In addition, the determination of mercury in natural gas and condensate is made difficult by the very low concentrations involved, the highly volatile nature of mercury and the complexity of the sample matrix. This dictates that either a highly sensitive detector or a large sample volume or both are needed to perform adequate analysis. A variety of techniques with different sensitivities are presently available for the determination of mercury. The system developed consists of 4 main modules; sample pretreatment, sample capture, sample conditioning and mercury measurement (i.e. detection system). The detection system utilizes a spectroscopic technique for mercury analysis hyphenated with in-house developed liquid hydrocarbon conversion system and sampling system. Results gained from performance testing demonstrate good reliability and opens new prospects to further develop the system for other facilities where mercury monitoring is required, especially for remote facilities.
Deformation Profile Analysis of Deepwater Sabah Toe-Thrust Structural Trends – Observations on Structural Kinematics and Implications on Sedimentary Fairway Distribution Patterns
Authors: Khamis Mohd Asraf , Jong John , Barker Steve M. , Abdullah Siti Aishah , Watanabe Yoshiaki 
Published: March 2018

Abstract
This study aims to provide supporting evidence for a semi-qualitative understanding of the various deformational episodes experienced in the studied structures of deepwater Sabah toe-thrust trends, covering from the deeper Kinarut reservoir interval to seabed in a temporal and spatial framework. A quantitative analysis of the deformation profiles was conducted to observe their effect on sedimentary patterns, integrated with amplitude analysis and spectral decomposition volume interpretation. The basic principal of line balance restoration was employed to unravel the deformation history of three investigated structural trends: Trend 1 ("M-La-S"), Trend 2 ("L-B-P") and Trend 3 ("Pg-Lt-U"), with the fundamental assumption that a geological section will restore at any particular moment in time to an unstructured section according to the law of superposition and horizontality. These toe-thrust anticlines were examined by calculating the rate of shortening at different geological times over the section utilising a number of line sections. All three trends have experienced a dominant NW-SE oriented compression from Early Miocene until Late Miocene, during the closing of the proto-South China Sea and the subsequent opening of South China Sea. These regional tectonic events impacted directly on the structuration style in the study area. The quantitative analysis has shown that the structuration and deformation history of each of the studied structures varied along the structural trends. Late stage deformation episodes, which possess a higher stress regime play a significant role on the rate of shortening on each anticline and its fold geometry. These variations influence sediment fairway distributions and impact on the selection of exploration targets and reservoir objectives. The study demonstrated a fundamental genetic link between structural growth and sedimentary fairway loci. It is concluded that the key to reducing reservoir risk is to first understand the kinematic growth profiles and deformation history of the studied structures. Well-developed structural kinematic models and the establishment of the deformation history of the studied toe-thrust anticlines in deepwater Sabah will have a paramount impact for more reliable predictions of sedimentary fairway distribution patterns, where effort to locate sandy reservoir remains a critical challenge for deepwater exploration.
Automation Solutions for a Minimal Facility Offshore Wellhead Platform – Low Cost Low Power Concept
Authors: Jalil Jalina Suryani Abdul , Hwa Lee Boon , Chan Nigel , Jeran Azwin 
Published: March 2018

Abstract
After the successful delivery of two mammoth deep water projects in Sabah, Shell Malaysia turned its attention to develop cost competitive solutions to further develop and generate growth for small/marginal field development. The initial focus was to develop a low cost, minimal facility platform, which meets all the HSSE and operational requirements for a marginal gas field in Sarawak. To do things differently, new but proven technology had to be utilised and for this initial low-cost development wellhead platform, solar panels were employed to generate power for the platform facilities. Electricity generated by this technology is currently limited to 1200 Watts and due to this, the design of the controls of automation systems had to morph along with this limitation. Equipment such as pumps, control and safeguarding systems had to run on 24VDC supply. A low powered integrated control and safeguarding systems, limited to a power consumption of no more than 250 watts, suitable for installation and operation in outdoor hazardous environment, with temperatures reaching 50°C, had to be employed. Due to the power supply limitation, pressurised control rooms to house controls and safeguarding systems now are a thing of the past. And the design of the wellhead control panel was optimised by minimising the number of 24VDC pumps and utilizing pressure boosting regulators to achieve the different required pressures.
Production Analysis PA and Application of Rate Transient Analysis RTA in Carbonate Oil Reservoirs for Reservoir Characterization and Connectivity
Authors: Eghbal Motaei , Abdolrahim Ataei , Ebrahim Yazdi Mohammad 
Published: March 2018

Abstract
Analytical approaches are primary reservoir engineering techniques for understatingreservoir/well performance and reservoir characterization which creates additional value on top of comprehensive geological models. Different techniques such as Pressure Transient Analysis (PTA), Rate Transient Analysis (RTA), and analytical models provide good understating on reservoir extension and properties, reservoir connectivity and well interference signatures. For complex carbonate reservoir models, relying solely on petrophysical properties from core and LOG and calibrated is not enough. Several case studies are published where the static model is guided by seismic driven Acoustic Impedance(AI) which matched the porosity at the wellbore. These methods significantly enhance the reservoir property distribution if a reliable seismic data is available. Nevertheless, the permeability map and reservoir connectivity analysis still require detail investigation of well performances and production data.
This paper discusses the application of production data analysis to characterize the reservoir in larger scale and reveal the reservoir connectivity and flow barriers in the prevailing heterogeneity. Authors addressed the integrated production data analysis including RTA/PTA, 2D numerical simulation and deconvolution technique in gas cases (Ataei et al 2017).
The basic equations of RTA which requires single phase condition are still applicable in the current case study which involve oil above bubble point pressure. Simple 2D numerical simulation were used to address the challenges and the provides a solution to have better understanding of reservoir continuity, a reliable permeability map for upscaling core data and incorporating in the model into large (field scale). The calculated KH from PTA data was also integrated with that of estimated from RTA and evaluated by 2D model before integrating in into full field reservoir simulation model for future forecasting.
Field M Deepwater TLP Initial Start-Up and Operation: Flow Assurance Challenges and Learnings towards Achieving First-Oil
Authors: Chow M. H. , Loke Y. K. , Bandan P. , Zou X. 
Published: March 2018

Abstract
The Field M phase 1 development consists of 9 production wells and 2 water injectors in offshore Sabah. Field M is the first Tension Leg Platform (TLP) in Malaysia with several unique flow assurance features that were challenging for the project, namely hydrates, waxy crude with high pour point and cloud point temperatures, bypass pigging for wax as base-case strategy as well as an industry first Single Combo Top Tension Riser (SCTTR) with both gas lift and production strings in a nitrogen filled riser annulus. This paper describes the experience of bringing the Field M field into operation including hydrate inhibition, well unloading, dewatering, well ramp-up and ongoing steady state operation from a flow assurance perspective. The initial well unloading process and ongoing steady state operation of the wells and flowlines are described, and comparisons are made between expected responses based on steady state and transient simulations during the design phase, and actual field data. The key challenges faced and technical findings are also documented. Lessons learned during the first year of operation are a combination of work-arounds, differences in fluid properties from those initially assumed, benchmarking of field data with predicted simulation results, and general operational experiences related to flow assurance.