bluuebunny/crossref_metadata_2025 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

Digitalization 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

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

We 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

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

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

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

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

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

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

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

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.
Risk Management Study on Compaction and Subsidence for CO2 Storage Project
Authors: Ali Siti Syareena M , Widyanita Ana , Jalil M Azran b A , Kantaatmadja Budi Priyatna , Mansor M Nezam , Ern Kevin Teng Ging , Musa Ikhwanul Hafizi , Kamaruddin Nik M Fadhlan Nik , Zamberi M Shahrul Amir
Published: March 2018

As part of ongoing study for CO2 sequestration in Sarawak basin, offshore Malaysia, storing of CO2 in depleted gas reservoirs is one of the options besides deep saline aquifers and dry structures. These single options have their own advantages and challenges. Most of the depleted giant gas fields in Sarawak basin experienced pore collapse during later period of production life. The magnitude and the severity of pore collapse depend on effective stress changes and reservoir compaction behavior. Most of these carbonate reservoirs in Sarawak have been producing for more than 10 years and have undergo pore collapse to various degrees at depleted reservoir pressures. Core studies have indicated possible pore collapse to happen from 900psi to 1590 psi of abandonment field pressure. It was observed from the core studies that carbonate facies with predominantly vuggy and mouldic porosities varying in the range of 20 – 35 % that are more susceptible to collapse. The pore collapse consequently resulted in reduction pore volume, destruction of permeability, reservoir compaction and subsequently surface subsidence. This could further impact the existing surface facilities (platform sinking), casing integrity in existing wells and possible fault reactivation jeopardising structural integrity.

Nevertheless, some of the carbonate reefal gas reservoirs in Sarawak basin have sizeable capacity presenting attractive opportunity for utilizing them as potential storage sites once they reach the abandonment stage. However due to the above enumerated risks associated with the possible pore collapse scenarios, a thorough screening and selection of storage reservoirs is required. This paper attempts to present various selection criteria evolved for screening, selection of potential storage sites and a case study, focusing on overall 3D/4D Geomechanics workflow for reservoir compaction and seabed subsidence, data calibration and other criteria that helps for final development program of CO2 geological storage site.
Geo-Engineering Integrated Fracturing Design Workflow and Application in Sichuan Basin of Southwestern China
Authors: Li Yanchao , Yin Congbin , Qian Bin
Published: March 2018

In the past five years, shale gas development had made great progress in Longmaxi shale of Southwestern China. Different from the North American shale, the Chinese shale reservoir has the characteristics of deep and multi-stage tectonic movement, which presents a huge technical challenge for economic development. Especially, great horizontal stress difference resulted it was difficult to create complex fracture network during hydraulic fracturing. So it is vitally important to provide a workflow of geo-engineering integrated fracturing design for Chinese shale economic development.

In this paper, a workflow of geo-engineering integrated fracturing design is proposed to optimize fracturing parameters, which is based on geology modeling and formation quality evaluation. This workflow contains stress and natural fracture prediction and modeling, perforation sweet spot optimization, stimulated fracture network and productivity prediction, treatment parameters optimization, and fracturing design evaluation. In order to improve the use of convenient and complex data processing of fracturing engineers, the simulation system of shale stimulation (CQ-4S) is developed which is based on this workflow.

The applications of workflow and system during more than thirty shale gas wells in Southwestern China illustrated that the workflow and system could effective optimize design of shale stimulation, which contains some advice of perforation sweet spot, cluster spacing, treatment volume of fluid and proppant. The predicted fracture network had good agreement with microseismic data, and predict well performance also had good agreement with real-measured results. According to fracturing analysis and evaluation of more than thirty cases with this workflow and system, we also recognized that there were 13 geoengineering parameters which determined fracturing effectiveness of Chinese shale gas.

The results of this paper provide some guidelines for shale gas stimulation design and evaluation in Southwestern China, which is also can provide reference for other emerging shale gas development.
Gas Recovery Through the Injection of Carbon Dioxide or Concentrated Flue Gas in a Natural Gas Hydrate Reservoir
Authors: Peter Englezos , Messah Mani , Chau Jacky
Published: March 2018

Because CO2 hydrate is stable at pressures lower than those required to stabilize hydrates of CH4 when compared at the same temperature the injection of CO2 into gas hydrate reservoirs was proposed a while ago as a method to recover methane. The added advantage of such a technology is the simultaneous sequestering/storage of CO2 captured from fossil fuel power plants or other significant point sources of CO2. Recent reviews on the subject have provided an account of the laboratory and theoretical work on this topic. The reviews highlighted the need to further elucidate the dynamics of the exchange process and provide information needed for the design of industrial scale facilities. In this work, the kinetics of the CO2/CH4 exchange process are investigated in a 5.3 L laboratory crystallizer (reservoir) equipped with ahorizontal injection tube with 24 exits into the packed bed of silica sand particles. Preliminary experiments conducted using this apparatus and also with a high pressure calorimeter indicate that in lab experiments there is some residual water and that the extent of the exchange process is limited. Even if the CH4 recovery is optimized there is aneed for a CH4/CO2 separation plant to enable a complete cyclic sequence of CO2 capture, injection and CH4 recovery.
Unconventional Gas Dehydration System Failure Resulting in a Gas Hydrate Blockage
Authors: Sundramoorthy J. D. , Leknes M. J. , Moodley K.
Published: March 2018

This paper presents finding of how liquid hydrocarbon carryover from production separators could form solid contaminants that would later become a root cause for an unexpected failure of tri-ethylene glycol gas dehydration unit to deliver dry export gas. This incident will later be followed by an unanticipated capillary aided gas hydrate blockage inside the gas export line during a planned maintenance shut-down. Upon detailed operational review, all section of TEG dehydration tower unit are opened up, and inspected for: (1) presence of any solid contamination and blockages, and (2) to evaluate presence of internal equipment damages inside the dehydration system. Observations are explained with data analysis and field images, while correlating to TEG dehydration unit's operating parameters; pre and post gas hydrate blockage incident. Compositional analysis using GC-FID, XRD and EDS are conducted on samples collected from the unit to understand its nature. Then, using a customized gas hydrate rocking cell apparatus, gas hydrates growths are observed under 8 °C sub-cooling temperature. From vessel inspection, it is found that liquid hydrocarbon carryover results in accumulation of high chain hydrocarbon deposits (C19-C36), and some mineral scales formation inside the unit. These deposits are found to form when liquid carry-over passes through the reboiler unit. This then gradually blocks the TEG distribution spray nozzles and reduces the efficiency of gas dehydration. Later, with only 20.5% of the spray nozzle found to be in working condition, the dP across the distribution bar exceeds its maximum operating limit, later causing it to split open along the weldment area. Hence, this results a total functional failure to deliver dry gas, and formation of gas hydrate blockage later. On the basis of detailed operational review, field testing, compositional analysis and hydrate growth observations, the sequence of events that later caused a catastrophic capillary aided gas hydrate blockage even in the presence of hydrate risk management program is presented in this paper.
New Workflow in Reservoir Modelling - Incorporating High Resolution Seismic and Rock Physics
Authors: Ghosh Deva , Babasafari Amir , Ratnam Teresa , Sambo Chico
Published: March 2018

In field development and production, a reservoir model is a key element in the successful performance of an oil and gas field. Well logs and core data have high vertical resolution whereas seismic data has poorer resolution vertically. However, 3D seismic data has very high horizontal resolution. We will take this into account while proposing the new methodology.

Depending on wells only we can have a hi-res model far higher than what we actually need. However, in between the wells any meaningful extrapolation is flawed. Using geo-statistics through kriging algorithm and variography leads to non-geologic reservoir models. One particular process which is highly undesirable is to throw any valid well info and upscale it such as to fit the seismic. This results in a model that is inherently flawed. The important aspect of the new methodology is to follow up the seismic stochastic inversion together with a suitable rock physics modelling to achieve high resolution (reservoir scale) of different litho-facies discrimination.

In this study first a robust rock physics model is performed for not only shear velocity log prediction at not having shear log wells but also to more appropriate litho-facies differentiation at well locations using seismic elastic properties (AI vs. Vp/Vs). Afterwards, seismic pre-stack stochastic inversion is carried out to populate different types of litho-facies between the wells. Eventually, the distribution map of pay zone facies is resulted.
An ANN-Based Framework For Rapid Spectral Fatigue Analysis of Steel Catenary Risers
Authors: Hejazi Rasoul , Grime Andrew , Randolph Mark , Efthymiou Mike
Published: March 2018

A simplified framework is presented in which an existing artificial neural network (ANN) based tool for critical stress range prediction is used in order to rapidly assess the fatigue life of a steel catenary riser (SCR). The simplified approach considers the first-order motions of the hosting floater (heave, pitch and roll motions) and irregular sea-states to assess the critical stress range within the touchdown zone (TDZ) of the SCR. Stress transfer functions are generated that approximate the SCR TDZ critical stress range due to vertical motion at the SCR hang-off point. The motion response amplitude operators (RAOs) and transfer functions are then combined to generate the SCR TDZ stress spectra and hence assess accumulated fatigue damage for all potential sea-states at the floater location. The fatigue lives of two large diameter SCRs subject to a sample irregular wave scatter diagram are calculated using the simplified framework. The results are then compared with those determined via a state of the art commercial software that uses a dynamic time-domain finite element (FE) analysis with rain-flow cycle (RFC) counting and shown to provide a good agreement. It is an important result as the time required to run the simplified analysis is an order of magnitude smaller than the more rigorous analysis (minutes versus hours). It demonstrates the usefulness of the simplified approach at the early stages of an SCR design where a large number of simulations are needed for sensitivity studies in order to select an optimized concept.
Intelligent Near-Bit Reamer Affords Same-Trip Drilling, Hole Enlargement and Rathole Reduction for Optimal Deepwater Well Construction
Authors: Valverde Eddie
Published: March 2018

Simultaneous drilling and hole enlargement in deepwater wells helps set casing strings deeper in the well. Common BHA designs place an underreamer above the MWD/LWD package, which ensures reliable mechanical activation of the underreamer, but also leaves up to 200 feet of undergauge rat hole to TD. An intelligent underreamer is presented with RFID and pressure cycle activation capabilities. Placed closer to the bit, this underreamer minimizes the rat hole to ensure deeper casing setting.

The intelligent drilling reamer is a concentric mass-balance underreamer that enlarges wellbores below casing restrictions. The reamer simultaneously drills and enlarges when deployed with rotary-steerable systems or rotary BHAs. Unlike ballactivated underreamers, the intelligent reamer is activated via RFID, in which RFID tags are pumped downhole to transmit instructions to an electronic reader on the reamer. The reamer can also be activated with a pressure cycle, which opens or closes a solenoid-operated valve to lock or unlock the reamer. With this dual actuation feature, the tool can be installed just behind the bit, where it significantly reduces rathole length.

An operator working offshore Malaysia deployed the intelligent underreamer to enlarge a highly deviated, slimhole wellbore from 6-¾ in. to 8-½ in. The tool was run in the lower part of the directional BHA, near the bit, to minimize the rathole. A set of RFID tags was dropped into the drill string at the same time that the pressure pulse activation sequence began. The RFID tag activation code was not received at the expected time, an indication that the tags were not able to easily pass through the turbine-driven MWD tools. However, the reamer was activated by the pressure pulse sequence and the rathole elimination operation commenced.

The reamer reduced the rathole length from 180 ft to 10 ft (55 m to 3 m), allowing the operator to achieve its completion and reservoir inflow requirements without changing drilling practices or replacing any BHA components. The operation eliminated the need for a dedicated run to enlarge the hole. The single run also minimized openhole time, which reduced borehole instability risks. In total, this single-trip drilling and reaming run reduced rig time by approximately 20 hours, equivalent to a cost savings of approximately USD125K.

The intelligent reamer is the only one of its kind capable of actuation via RFID tags or pressure pulse cycling, which provides on-demand control for nearly unlimited activation and deactivation when tripping and drilling. It also provides a backup activation option when the primary RFID method fails. The tool's RFID-activated automatic battery savings mode increases battery life by up to four to eight times, which ensures longer reaming runs in the same trip.
Improved Reservoir Characterisation in Malay Basin through Seismic Stratigraphy and Rock Physics Modelling
Authors: Rahman Ahmad Sharif Abd , Fuad Muhammad Izzuljad Ahmad
Published: March 2018

Discovering easy hydrocarbon reserves in Malaysian Basins particularly in the Malay Basin has become the story of the past. Most of the remaining reserves are now anticipated to be found in more difficult geological settings; such as in channel sand, stratigraphic traps, or in thin beds. This is not to say that there is zero possibility of discovering new hydrocarbon reserves in the more "easier" anti-cline structural setting, but most likely the new reserves would be at deeper intervals below the current typical operating depth of within 3 km below the sea bottom. The deeper reservoirs would require larger investment and at the same time exposing exploration and development ventures to higher risks as the likelihoods of penetrating the overpressure zones in the Malay Basin at deeper interval are much higher.

The main objective of this paper is to establish a workflow concept of a seismic modelling platform that utilizes deterministic rock physics to derisk and reduce uncertainties in the reservoir characterization. This general objective entails three specific goals: 1) to model geological scenario from seismic data, in order to identify more likely geological scenarios among the all avaible geological possibilities; 2) to discover and incorporate rock physics diagnostic and modelling as the link between geological and geophysical parameters; 3) to apply the proposed workflow in an actual dataset (a possible delta fan lead in Malay basin) to verify its applicability.

A field in the early development stage has very limited data: a little well data, seismic data, and some geological observation. Reservoir forecasting in this stage is one of the most important tasks for future decision making. A deep lead located in half graben setting within Malay basin (Figure 1) is used for verification of the workflow, and the study starts from the beginning stage of stratigraphy modelling.
Moho Nord, A Complex Integrated Project
Authors: Blarez Emmanuel
Published: March 2018

Objectives/Scope

With two different reservoirs – Miocene and Albian; a development combining brownfield and greenfield; two production platforms – a Floating Production Unit (FPU) and a Tension Leg Platform (TLP); and the collapse of the oil price during the project execution phase … Moho Nord operated by Total E&P Congo is a highly complex project. The objective of this paper is to show how Total managed to ensure the success of the project phase.

Methods, procedures, process

The development scheme of Moho Nord is above all an optimal response to the constraints imposed by the different reservoirs. Then, Total had to efficiently supervise this complex project during the industry downturn, while maximizing the local content in Congo, drawing on the best available technologies to reduce the environmental impact of the new installations, and developing innovations notably to be able to simultaneously drill, intervene and produce the complex Albian reservoirs.

Results, observations, conclusions

Total successfully completed this large and complex project, including the first TLP for the Group in Africa. Production started in March 2017 less than four years after the Final Investment Decision (FID). Three floating units are involved: the already existing FPU Alima and the new-build FPU Likouf with a typical subsea production layout, and the TLP with surface trees. Production is sent onshore to the existing terminal at Djeno.

To meet the challenge of a dual development comprising brownfield and greenfield sites, Total created an integrated muti-discipline team to work on the upgrade of FPU Alima and its subsea network, modifications to the Djeno terminal, and the construction of the new FPU and TLP units. Packages for Umbilicals, Flowlines Risers (UFR), Subsea Production System (SPS), Geosciences, Drilling, and Support services were shared across the whole development.

The main contracts were signed in 2013 before the oil price collapse and Total had to rely on the expertise and creativity of its teams and contractors to manage the project through difficult times, without compromising success and safety.

Novel / additive information

With the Moho Nord project Total has demonstrated its capacity to manage a large, complex brownfield and greenfield project to time and budget even in a difficult economic climate.
Software for Automated Visual Assessment of Coating Damage
Authors: Tan Wei Chian , Chen I-Ming , Goh Phoi Chin , Tan Hoon Kiang
Published: March 2018

Current visual assessment of coating damage is performed by experienced inspector. This leads to variation in procedures and decisions among inspectors. Disagreement caused during assessment introduces issue of low reliability and repeatability of assessment results. A software that automatically identifies and determines percentage of defective areas in a given image is presented. Tested on a dataset of structural defects, outcome of the software is validated against answers provided by engineers and inspectors. The software requires an image of coating surface and hints on regions of interest as inputs. Users provide hints by clicking few times on regions they are interested (known as foreground) and not interested in (known as background). With built-in intelligence, the software scans the image and identifies defective areas by comparing colour difference between each pixel and hints user provided. If colour value of a pixel is found to be closer to hints in foreground, it is labelled as defective area and vice versa. Next, percentage of defective area in the image is determined and reported. Dataset of structural defects (http://xiscobonnin.github.io/resources/#datasets) with 73 images was used for experimental evaluation. These images come from wide range of engineering scenarios and contain different levels of coating damage. Wide variation that exists in the images would allow comprehensive understanding of performance of the software. Without prior learning, given each image, users provided hints by clicking few times (less than 10) on foreground and background. Machine (or computer) took over the analysis subsequently using algorithm developed based on colour information. Outcome from the software was validated against decisions made by engineers and inspectors. Results are promising with more than 90% of the defective areas successfully identified and in agreement with inspectors’ judgements. Reported percentage of defective areas for each image is also aligned with manually estimated value. This demonstrates that the developed tool is capable of improving process of visual inspection of coating surface. With current state of the art, user's hints have been proven to be very useful in guiding machine or algorithm to segment the image into foreground (region with coating damage) and background (irrelevant region). However, challenges remain for difficult situations such as colour of background being close to foreground and machine is unable to differentiate. Developed software is able to assess condition of coated surface quantitatively based on given image. This minimises the chance of argument over qualitative assessments during inspection. Having standardised tool for assessment would also allow comparison among existing cases. This serves as first step towards capture of experience in the industry through automation. Refinements such as threshold adjustment can be made subsequently to minimise difference between decision made by the software and experienced personnel.
Numerical Approach for the Prediction of Formation and Hydraulic Fracture Properties Considering Elliptical Flow Regime in Tight Gas Reservoirs
Authors: Hossain Md Mofazzal , Al-Fatlawi Omar , Brown Dominic , Ajeel Mohammed
Published: March 2018

As tight gas reservoirs (TGRs) become more significant to the future of the gas industry, investigation into the best methods for the evaluation of field performance is critical. While hydraulic fractured well in TRGs are proven to be most viable options for economic recovery of gas, the interpretation of pressure transient or well test data from hydraulic fractured well in TGRs for the accurate estimation of important reservoirs and fracture properties (e.g. fracture length, fracture conductivity, skin and reservoir permeability) is rather very complex and difficult because of the existence of multiple flow profiles/regimes. The flow regimes are complex in TGRs due to the large hydraulic fractures near the wellbore, combined with low matrix permeability and reservoir heterogeneity; and consequently the interpretation of well test or pressure transient data using the classical approaches usually used for conventional reservoirs can produce wrong results with high level of uncertainties. In addition, the time required to achieve radial flow regimes for such tight reservoir, as key condition to use classical approaches, is impractically long and not feasible from the context of both economic and practical operation viewpoint. These inherent causes and the operating limitations require amendment of the well test technique to analyse linear or elliptical flow regimes to accurately estimate the reservoir and fracture properties.

This paper proposed a simplified numerical approach to predict the reservoir and fracture parameters based upon well test or production data from hydraulic fractured vertical well in tight gas reservoir considering elliptical flow regime. Emphases are given on the development of simple computation tool that can be used as a handy, efficient and accurate tool to supplement the need for commercial simulators; yet can provide with estimation of reservoir and fracture properties with high level of accuracy especially in the case when limited pressure transient data is available.