bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comprehensive 3D Thermo-Chemo-Poroplastic Model for Evaluation of Borehole Stability in Chemically Active Rocks
Authors: Roshan H. , Oeser M. 
Published: January 2012

Abstract
Several instability issues such as pipe sticking, washout and borehole collapse can be experienced during drilling in chemically active formations. The conventional approaches towards the geomechanical modeling of such formations fall short of describing complex behavior of chemically active rocks, such as the swelling shales. The effect of crystalline swelling and chemical osmosis on elastic deformation have been adequately addressed by many authors, however, the effect of these changes on plastic deformation of rocks under three principle stress conditions have not been investigated. In this paper the effect of hydration/dehydration due to thermal and chemical osmosis on plastic deformation of chemically reactive shales is studied.
The 3D-model is developed to evaluate borehole stability problems in drilling a troublesome shale formation. From the results of this study it was revealed that most reactive shales at typical drill depth (2500m to 3500m) undergo plastic deformation. Hydration/dehydration due to crystalline swelling and osmosis (chemical and thermal) further aggravates the mechanical properties of shales. The numerical experiments also show that the vertical stress plays a significant rule in formation of plastic zone around the wellbore thus, making the wellbore prone to collapse failure.
Utilization of High Value Engineering Center (HVEC) in Execution of a Major Capitol Project, Gorgon
Authors: Malladi Siva , Shah Parag , Cruikshank David 
Published: January 2012

Abstract
The Chevron-operated Gorgon Project is located off the north-west coast of Western Australia and encompasses a number of mega-projects including an all-subsea upstream development of the Greater Gorgon gas fields, a greenfield gas processing facility including a 15MTPA liquefied natural gas plant and a 300TJ/d domestic gas plant and the world’s largest commercial scale carbon dioxide injection project.
The Gorgon Project is operated by an Australian subsidiary of Chevron and is a joint venture of the Australian subsidiaries of Chevron (approximately 47 percent), ExxonMobil (25 percent) and Shell (25 percent), Osaka Gas (1.25 percent), Tokyo Gas (1 percent) and Chubu Electric Power (0.417 percent).
Due to its sheer size, scale and complexity, in addition to a number of unique characteristics, the Gorgon Project has required an extraordinary level of project management and one of the key project management strategies employed has been the appointment of a High Value Engineering Center (HVEC) in Jakarta.
This paper explores the benefits of using the HVEC concept; the evaluations performed on the HVEC; the challenges associated with the execution; the execution planning utilized and the tactics utilized in executing the work, which have all enabled the successful delivery of the engineering phase of the Gorgon Project.
The HVEC concept is not new to the oil and gas industry. But execution success tends to vary based on numerous criteria and variables associated with the HVEC centre.
The conclusion is that the HVEC concept works and has a place in the execution of Major Capital Projects. The concept can be very successful with the following in place: Thorough evaluation of the HVEC capabilities, with a feed back into the HVEC execution plan.The HVEC project execution receives appropriate oversight from the main Execution Center (EC).Highly competent and motivated management present at the HVEC level.Robust procedures and processes in place to provide required guidance to the HVEC personnel.A detailed HVEC execution plan and implementation of the execution plan.Transition of the work scope from the main EC to the HVEC in accordance with the execution schedule, at an adequate level of maturity.
Although the HVEC concept is not new to the oil and gas industry, execution success tends to vary based on numerous criteria and variables associated with the individual HVEC utilized, its experience and its relationship with the managing EC.
Real-Time Optimization of an Integrated Gas System
Authors: Göbel Derek , Cramer Ron , Briers Jan , De Boer Frank , Lai Kok-Lam , Hooimeijer Martijn 
Published: January 2012

Abstract
This paper describes the large-scale trial of Real-Time Optimization (RTO) that Shell Malaysia E&P has conducted on the Integrated Gas Production System iln Sarawak, implementing models for real-time monitoring and optimization of wells and facilities on a gas production network spanning more than 100 wells on more than 40 platforms across a number of different Production Sharing Contracts (PSCs). We highlight how Digital Oil Field (DOF) practices enable field-based data to be turned into information, support decision making, and lead to actions that ensure production is optimized continuously.
The technology described in this paper is applied to achieve consistent gas supply to meet demand, maximizing revenue on producing assets, and enabling improved and timely operational decisions - striking a balance between short-term revenue and long-term value. It demonstrates Shell's ability to manage and continuously optimize complex, integrated, multiple-objective, closed-loop systems such as gas production assets. The pursued benefits are increased condensate production at current or improved expected Ultimate Recovery, whilst maintaining a stable gas supply, fulfilling quality constraints and contractual LNG nominations.
The optimization is data-driven and covers more than 1,000 variables and features multiple, mutually dependent objectives and constraints. The solution has proven significantly better than prior physical model-based solutions, which are capable of delivering optimized field settings, but with inherently unstable results, and not fast enough for application in a real-time decision making environment. This is one of the first successful attempts to optimize, in real-time, a production environment of this size and complexity, including a complicated set of commercial and contractual constraints.
Additionally, this approach replaces the traditional, daily or monthly optimization by a continuous one. The system generates optimal set-points for the control variables which are executed by the operators. Closed loop control is possible with remotely operated chokes which would allow the optimization of the entire gas system to be fully automated and minute-by-minute.
Heavy Oil Recovery by Steam Injection, Mapping of Temperature Distribution in Light of Heat Transfer Mechanisms
Authors: Romanov A. , Hamouda A. A. 
Published: January 2012

Abstract
Enhancing heavy oil mobility and drainage induced by reduction of viscosity and density due to temperature increase caused by steam injection is one of the most used methods by the industry. In spite of the vast investigation done in literature for the area of steam injection, the mechanism(s) of heat flow in reservoirs are not fully understood. Understanding heat flow mechanism(s) and temperature distribution, contribute to better optimization of the used steam.
It is attempted in this paper to shed light on thermal recovery and temperature distribution with steam injection from experimental work. Basically, a model reservoir is constructed with heavy oil to be recovered by steam injection. Mapping of temperature propagation within the model reservoir clearly demonstrates fast steam/ temperature propagation to the overburden and then propagate horizontally at the top of reservoir. Hence, top of the reservoir becomes the second heating source of the underlying layers. However, the obtained temperature propagation profiles of simulated heavy oil thermal recovery by steam are different from the experimental data.
Analysis of the temperature distribution shows that at the interface between the heated and cold region of the reservoir are initially contributed by convective heat flow (steam condensate and mobile heavy oil), then conductive heat transfer dominates. As the temperatures reach / close to steady state in the different heated areas, maximum drainage process takes place.
Different simulation and experimental temperature distribution data are compared and showed better agreement between the estimated and experimental data as a function of time, indicating more conductive heat transfer mechanism with time.
It is interesting to observe that in spite of the complexity of different processes taking place, consistent temperature gradients are established within the reservoir. This could lead to a better optimization of steam injection regime.
Fibrous Organic Cellulose Application to Combat Seepage Losses in Fractured Limestone Formations, Offshore East Kalimantan, Indonesia
Authors: Taufik M. , Panjaitan R. A. , Djambek A. 
Published: January 2012

Abstract
XY fields in offshore East Kalimantan, Indonesia, have a history of whole drilling fluid losses ranging from continuous seepage to catasthropic losses in its "high amplitude carbonate body". Even though these carbonates are well known and documented, have been closely predicted and well anticipated, and drilling program account for their occurrence, whole drilling fluid losses continued to plague drilling operations and result in highly cost of drilling fluid losses, require expensive treatments and incur Non-Productive Time (NPT)
Drilling programs call for controlling Equivalent Circulating Density (ECD), matching Rate of Penetration (ROP) to hole cleaning efficiency and reducing surge and swab pressures when loss zones are expected. Standard Lost Circulation Materials and Loss Prevention Materials (LCM and LPM) had been previously prepared and pumped prior to entering the loss zones with unpredictable and less than desirable results.
A special, Indonesia-sourced and manufactured, patented organic cellulose fiber was introduced in the fluid system to prevent losses prior to drilling the troublesome formation. A rapid, inexpensive, easily understood and applied, field test procedure have also been introduced for further development which allows a quick and accurate assessment of fluid system permeability sealing effectiveness and avoid over-treatment with fluid additives due to treating "on schedule" or "by formulation".
A significant improvement was shown for the first trial on X107 well and also on one exploration well. Success was achieved due to the ability of the Lost Prevention Material additives to create an effective wellbore seal in the troublesome formations. Drilling was continued without incurring NPT due to drilling fluid losses or remedial treatment requirements.
This paper presents and describes case histories which will detail material types and grades, function of the patented material, specific application and treatment details and compare time and cost savings to offset wells.
Integrating Mini-DST-Derived Permeability With Other Sources: A Case Study
Authors: Harmawan I. , Kabir C. S. , Habib S. , Kennedy J. , Henson J. , Minhas H. 
Published: January 2012

Abstract
Permeability is the cornerstone to any reservoir-flow modeling, leading to field development and production management. Typical sources of permeability include cores, logs, wireline formation tests or mini-DSTs, and conventional drill-stem tests or DSTs., Integrating various sources of permeability at different scales is problematic. Anchored in mini-DST-derived permeability, this study endeavors to integrate various sources of permeability, leading to reservoir description in a trubidite sandstone reservoir in the Sabah Basin, Malaysia.
Pressure-transient test data recorded during a mini-DST operation differ significantly from those gathered during a conventional DST. In the case of this well, although the test quality is excellent, interpretation challenges are numerous. The paper llustrates the planning and integration of Mini-DST data with multidisciplinary information from side-wall cores, MDT, NMR, and FMI image logs. This case study demonstrates that, in this particular setting, the use of mini-DSTs was cost-effective and yielded the necessary subsurface information required to plan field development options.
Correction of non-Darcy Coefficient and How to Estimate It for Development Wells
Authors: Raijo Tsuyoshi 
Published: January 2012

Summary
Abadi gas field located offshore Arafura Sea, eastern Indonesia (Figure-1) was discovered by INPEX in 2000 and the appraisal activities have been carried out subsequently since then. Total 7 wells have been drilled and 8 DSTs have been conducted so far. The objectives of this work are to obtain more accurate non-Darcy coefficient (D) from the exploration and appraisal well’s Drill Stem Test (DST) by accounting for the completion effects, and to estimate D for the development wells.
The result shows the importance of accounting for the completion effect in order to get more accurate non-Darcy coefficient (D). The installation of the downhole gauge below packer & flow sub eliminates the need for this kind of correction.
It was confirmed that the completion effect can significantly underestimate the IPR (Inflow Performance Relationship) of the high-permeability gas wells. In addition, the turbulence coefficient β was found from the field data to be the function of not only the reservoir properties but also the gun specification. To use a deep penetration gun and to avoid partial penetration were found to be the key for reducing the pressure drop caused by non-Darcy flow, if the cased & perforation is adopted as a completion technique of the development wells for the reservoir of interest.
Implementation of Next Generation Intelligent Downhole Production Control in Multiple-dipping Sandstone Reservoirs, Offshore East Malaysia
Authors: Chen J. H. , Azrul N. M. , Farris B. M. , NurHazrina K. Z. , Aminuddin M. K. , Saiful Anuar M. Y. , Gordon Goh K. F. , Kaur K. S. , Luke T. K. , Eddep A. 
Published: January 2012

Abstract
The ‘S’ field, located offshore East Malaysia, consists of multiple-dipping heterogeneous sandstone reservoirs with unconsolidated formation. These multi-stacked reservoirs have an overall 40m thick oil column with marginal Oil-Initial-In-Place (OIIP). A large gas cap, i.e. twice the OIIP equivalent, also exists. Scenarios of zonal gas-out leaving huge oil bypass and moderate aquifer strength with inevitable water invasion cautioned the asset team to consider intelligent zonal flow control especially in its horizontal producing wells.
Two of the 14 horizontal producer wells in this marginal field have been screened to apply the modular integrated intelligent completions system (IICS) to actively control and permanently monitor zonal inflow for optimal production. Future selective production control and data surveillance enabled by the IICS are essential to fulfill the needs for delicate downhole zonal flow balance for ultimate oil incremental and recovery. It provides control against the aggressive gas cap expansion at the heels while addressing the moderate aquifer coning-up problems from the dipping toes as the field depletes.
This paper highlights the successful implementation of the next generation intelligent completions system in a complicated, highly-dipping, multi-layered sandstone reservoir with commingled production. In this multi-zonal production solution, the conventional surface-controllable downhole zonal flow control valves are now integrated with data surveillance gauges, intelligent sensors and isolation packers all into one single completion joint, instead of the precedent multi-joints system (i.e. splicing required up-to 3 joints per zone conventionally). This single modulated joint system has reduced installation time substantially in comparison to conventional intelligent completions installations. The risk of surface completions make-up damage before run-in-hole is also greatly reduced with less connecting components. This robust yet compact system has made on-site completions tally adjustment easier and is enabled with LWD data update while drilling. As a result, intelligent completions design becomes more flexible and responsive to actual reservoir challenges and drilling surprises – providing an all together "intelligent" solution.
This paper also discusses the screening process from simulation performed for candidate evaluation to the resulting impact on production post-installation. Future applicants of such technology with similar fields’ nature and risks can benefit from the discussed lesson-learnt; best-practice workflow and seamless teamwork and coordination between the project team and service providers in delivering an advanced fit-for-purpose solution.
Temporary Storm/Cyclone Well Suspension Using Inflatable Packer Systems
Authors: Ingram Colin 
Published: January 2012

Abstract
The official tropical cyclone season in Australia runs from November 1st to April 30th and in a normal season it is usual to expect an average of at least 10 cyclones to develop over Australian waters. They are particularly prevalent on the North West Australian coast where drilling activity, especially in deep water is currently ongoing. With the approach of a cyclone it is standard practice, as mandated by government regulatory bodies in the guidelines for offshore well operations (Ref. 1), to temporarily plug the well. These regulations call for temporary barriers to be installed in the well to provide the safety required when the rig is evacuated or, in the case of semi-submersible or floating rigs, disconnected from the well and even moved off location.
It is not uncommon with today’s drilling technology to use long large-diameter casing strings, such as 20" OD (508mm), to depths of as much as 2000m (6562ft), but the availability of matching hook wall packers to be used as temporary plugs is severely limited and, as a consequence, the provision of the contingencies for emergency suspension or abandonment of such wells can present a major operational problem. To address this situation a large diameter inflatable packer/bridge plug system has been developed which can be run and set in several different casing diameters and left in the hole as a bridge plug to hold pressure from below to fulfill the regulatory, and safe operating requirements, that are mandated.
In this paper the author will review the design and operation of this large diameter inflatable bridge plug and describe the running procedure and the setting, retrieving and fluid handling tools that are required for safe and reliable operation. The author will present a case history of the deployment of this system in the offshore North West Australia operational area in severe weather and cyclonic conditions.
Reservoir/Well Production Assurance Strategies for Successful Field Development Projects
Authors: Chan Keng Seng , Masoudi Rahim , Ataei Abdolrahim , Darman Nasir H. , Othman Mohamad B. 
Published: January 2012

Abstract
Wells drilled and completed following the approved field developed plan (FDP) may not yield satisfactory performance results as predicted at the FDP phase. The gap could be due to accumulation of various uncertainties and risks encountered in each phase of field development planning from reservoir characterization, flow dynamic properties, well reservoir penetration and production optimization, well design, drilling and completion, to well support surface facilities design and implementation.
This paper delineated the issues/challenges in each key task of field development planning focusing on three key areas for improving quality assurance in (1) reservoir simulation, (2) drilling and completion, and (3) production system. Real field example cases were used to illustrate the need to improve integration of pre-during-post FDP strategies and approaches. The paper also provides simple and short check lists on requirements and workflow for helping to assure FDP well production throughout the field life.
Walkaway VSP Aid in Well Location Selection in Mumbai High South India, A Case Study
Authors: Rana R. K. , Lim T. K. , Deo P. P. , Sundaram K. M. 
Published: January 2012

Abstract
Surface seismic imaging is one of the initial stages in oil and gas exploration. Low frequency content and unknown changes associated with surface seismic contribute to the limitations of low resolution and uncertainty in the processing of surface seismic.
The limitations of surface seismic images also cause uncertainties in interpretation that could lead to dry wells. High-resolution borehole seismic images illuminate the subsurface better and can add value to the interpretation. The advantages of borehole seismic surveys can also be found in the literature (Hardage B. 1983)
In this study, a case is presented in which low-resolution surface seismic was not appropriate to delineate the reservoir and led to a dry well for Oil and Natural Gas Corporation (ONGC). A walkaway vertical seismic profile (WVSP) was recorded to resolve the issues and help make decisions for the next well location. WVSP provided high-resolution images around the well that also suggested the subseismic faults in the area.
Integrated Strategy Delivers Secure and Fast Drilling in Deep CO2-rich Gas Reservoir in Volcanic Formation
Authors: Cheng Rongchao , Wang Haige , Ge Yunhua , Zou Lingzhan , Chen Zhixue , Zhang Fucheng , Li Hongsheng , Bi Wenxin 
Published: January 2012

Abstract
The great exploration discovery of natural gas resources in volcanic formations has uncovered a prospective prologue for tremendous development activity in deep Songliao Basin, China, which inherently contains a high CO2 concentration of about 14%-30%. The CO2-rich environment combining with the poor drillability of volcanic rocks has made operators confronting with challenges in drilling and completion operations, such as anti-corrosion against pipe string and set cement, optimization of casing program and bit type, ROP improvement, and cost effective UBD and multi-lateral drilling methods.
An integrated strategy was successfully proposed and deployed to address drilling related problems. Firstly, based on the analysis of wellbore stability and anti-corrosive mechanism under different downhole condition, the casing program and anti-corrosive scheme for production casing material were optimized for vertical well and horizontal well, respectively. Secondly, a new CO2 corrosion resistant cement slurry was developed using a new anti-corrosive material F11F and other anti-channeling HT agents. Thirdly, with respect to detailed study on CO2 invasion affection, reservoir sensitivity, scale building prediction and wellbore multi-phase flow mechanism, appropriate UBD drilling fluid and bottom underpressure value were determined. Then, the specific bit design method and gas drilling technology were jointly applied to enhance ROP in deep volcanic formations. Finally, matching technologies for horizontal and multi-lateral well operations were systematically modified considering the PDM (positive displacement motor) tool and geosteering method.
Favorable achievements have been obtained during years of continuous optimization of drilling scheme. The integrated strategy allows more secure and faster drilling in deep volcanic formations, and offers a tight foundation to maintain profitable production in Songliao Basin. This paper will highlight the technical development in the CO2-rich area, and present helpful case histories and recommendations.