bluuebunny/crossref_metadata_2025_split huggingface dataset:
Corrosion Control in Oil & Gas Installations
Authors: Okasha Q.. , Aladasani A.. , Ameen A.. , Aravind N.. , Sen K.. , Al-Dushaishi M.. 
Published: October 2017

Abstract
Globalization inevitably drives prices of commodities and services lower. As such, to remain competitive in the Oil & Gas industry it is imperative in low oil prices regimes to decrease operating costs. A key element of low operating costs in hydrocarbon exploration, production and refining, is corrosion control. In this paper the development of corrosion circuits/loops is improved by categorizing sixty four damage mechanisms based on operating preconditions, material susceptibility and monitoring methods. The inspection resource requirements are determined for each Refinery unit based on number of damage mechanisms, the required monitoring methods and the screening of regulated equipment. Corrosion loops are developed based on failure mechanism applicability and not arbitrarily changes in operating conditions or the probability of failure. Material selection methods for critical units during detailed design should not be qualitative to avoid over/under designs that are carried over to operating/inspection programs. When inspection effectiveness does not add significant value to risk reduction due to a gap between operating requirements and turnaround intervals, consequence mitigation, including operating practices should be examined. Therefore, risk studies including RCM, HAZOP and QRA should be aligned with RBI and validated by failure and consequence statistics. IOW assignment should consider design risk profile and operating (operations and inspection) risk profiles. By far this is the underlining reasons why operators are unable to leverage management systems to mitigate risk, lower operating cost and avoid major accidents. The importance of managing risk transfer between equipment design, operation, inspection, safety and system integration is highlighted. Integrity operating windows are not exclusive. The alignment of all the installation risks enables the operator to leverage risk profiles in manner that satisfies the statutory body and addresses its business needs.
Successful Parallel Appraisal and Development in a Complicated Gas Cap Field, A Case Study
Authors: Ruifeng Wang , Fengjun Mao , Li Wang , Qizhi Huang , Xintao Yuan 
Published: October 2017

Abstract
This paper demonstrates successful application of parallel appraisal and development in G field, Niger. G field is a complicated stacked light oil reservoir with gas cap in its E2 major pool. After current operator's takeover in 2008, the government required realization of 10 KBOPD in this field within 3 years, leaving only 1 year for appraisal and development as field construction in this landlocked country at least takes 2 years. Whereas there was only 2D seismic and one well data (G-1) with RFT and testing, parallel appraisal and development strategy must be adopted and following 2 major challenges were identified: 1) Limited data and great uncertainties in gas-cap and well productivity; 2) development decision-making along with appraisal process.
Appraisal and development have been optimized by following approaches: 1) RFT and wireline data were fully studied to identify oil-gas-contact in E2 pool and indicate possible oil in E3 pool; 2) appraisal wells placement based on new 3D seismic; 3) identify key uncertain development parameters and combine into appraisal campaign targets to gradually reduce uncertainties.
Appraisal well G-2 confirmed the separation of block G-1 and G-2. The second appraisal well G-3 confirmed oil-gas-contact, encountered oil zone in lower E3 pool. The third appraisal well G-8 encountered oil zone in E2 and further firm up gas-cap area, laying firm foundation for subsequent development well placement.6 producers were placed out of gas cap and appraisal wells were transferred to development wells, all successfully commissioned in 2011, achieving desired production target.
Conclusions drawn from successful parallel appraisal and development application were:1) utilization of all data available contributed to correct appraisal decision-making; 2) Combining 3D and appraisal well findings help reduce geological uncertainties; 3) Identify and reduce key development uncertainties during appraisal speed up appraisal process. For complicated fields at appraisal stage, the methodology in this paper is of strong reference value.
Real-time Surveillance and Analysis Tool for Intelligent Completion - An Ultimate Solution to Oil Recovery and Integrated Operation
Authors: Ramizah A. R. , Gordon Goh K. , Tina Lee L. , Varma G. , Muzahidin M. S. , Willem S. , Ahmad S. H. , Sanggeetha K. , Lester T. M. , Khairul Akmal M. , Mabel Chia P. , Tamin M. , Dipak M. 
Published: October 2017

Abstract
Upfront investment and capital commitment is required in installing Intelligent Completion (IC) in ‘S’ Field. Without diligently using real-time sensor data, IC becomes an expensive Sliding Sleeve Door (SSD). A real-time surveillance and analysis tool was developed to maximize IC zonal control decision-making for commingled production optimization. It enables user to utilize fully the hardware to improve production and to extract production and reservoir information for subsequent Enhanced Oil Recovery (EOR) workflow input. The analysis platform connects to real-time data source and performs calculations converting sensor data into knowledge [i.e. zonal flow rates, productivity index (PI) and reservoir pressure (P*)] and intelligence (i.e. zonal production optimization). User will spend minimal time on data gathering instead maximum time optimizing production by analyzing the trending and diagnostic plots.
IC is surface controllable multi-position zonal downhole sensors that read tubing and annulus pressure, tubing and annulus temperature and flow control valve (FCV) positions. ‘S’ Field installed IC in nine wells and is in the late production life of initiating an EOR multi-zone production optimization. However, under-utilized sensor data and trial-and-error zonal-control method led to suboptimal response time, production delay and reactive mitigation action. Furthermore, there are persistent difficulties of integrating multi-zone downhole sensors with surface well-test data in a single analysis platform to improve production or reduce watercut.
This paper will outline how the integrated analysis platform will help both operational and subsurface team in making faster and guided decision to maximize the reservoir recovery in an Enhanced Oil Recovery (EOR) Integrated Operation IO. The tool was developed and tailored to complement IC installation in maximizing zonal control decision-making and zonal performance monitoring, specifically for commingled production. It is a customized solution to utilize zonal IC downhole data to enable field-wide EOR performance monitoring and trending advantages in ‘S’ Field EOR project.
An Innovative Methodology to Assess Cement Blend Flowability and Proneness to Segregation—A Step Forward to Higher Quality
Authors: Bourlon Arnaud Joseph , Roy-Delage Sylvaine Le , Taoutaou Salim 
Published: October 2017

Abstract
Oil and gas well integrity is obtained by placing a steel casing in the well and a cement sheath in the resulting casing/formation annulus. To provide zonal isolation, a large portfolio of cementing technology is available to meet various well conditions. Some of these technologies involve dry-blending operations and cement-blend handling of specific-tuned-blends mixing together particles of different characteristics in terms of density, shape, size, and chemistry including mineral and/or organic components. These blends are usually transported pneumatically and loaded to the rig then transferred to the rig silos. During the different transfers, the blend may be prone to segregation, thereby losing its homogeneity, which makes it difficult to use or even unusable.
Flowability is an important blend property for the blend-handling process. Segregation can be viewed as a mechanism leading to a nonrandom degree of uniformity of the different blend components at the scale at which end-use properties are required. Overall, the differences between particles in chemical nature, density, size, and shape will influence the flowability and, above all, the tendency to segregate. Dealing with blends is, therefore complex since they contain small, medium, and coarse particles in various proportions depending on the targeted slurry density and set material properties.
To counter this challenge, an innovative methodology and equipment to characterize the blend flowability and robustness to segregation were developed and implemented.
The laboratory results were validated with those obtained in the large-scale results using a pneumatic conveying flow-loop.
The implementation of the new methodology during the design phase of the cement job was used as a preventive measure to validate the design and quality control of the blend before the blend is prepared and sent to the rig. This helped in designing robust homogeneous blends and reducing the likelihood of blend transfer problems, thus ensuring the placement of the right quality cement slurry and assuring downhole well integrity.
The new methodology described in this paper was applied to tune several field blends known or identified to have problems and to develop of new generation of cementing technologies.
The outcome of this multidisciplinary approach of blend characterization helps the oil and gas industry to anticipate blend-handling issues and to continuously improve quality and field handling of engineered complex blends with high confidence and consistency.
Design and Application of Aerated and Foam Drilling Fluid, Case Study in Drilling Operation in Indonesia
Authors: Nugroho WA , Sumantri M , Wibisono D 
Published: October 2017

Abstract
Underbalance drilling is a common application in highly fractured and subnormal pressured formation. Technical reasons such as reservoir damage, drilling in depleted zone and hard drilling lead to more economic value in drilling operation. There are several ways to achieve underbalanced well pressure while drilling. One of the most common technique is air, aerated-mud and foam drilling or commonly known as Aerated Drilling.
Drilling with air, aerated-fluid and foam can lead to numerous advantages. In spite of the advantages, it also brings more challenge in design and operation. Cutting transport should be properly calculated to achieve a clean bottom hole condition. Air and gas parameters should be properly designed to prevent Wellbore wash out and formation collapse. All of them should be properly design while maintaining underbalance condition.
In some cases, improper aerated drilling parameters potentially leads to drilling problems such as lost circulation and stuck pipe. This condition should have been mitigated with the proper design of Air, Gas and Foam injection rate. Guo and Ghalambor in 2002 describe main criterion in aerated drilling design. Guo's technique can be applied in air, foam and aerated-liquid drilling. In 2009 Lyons adds more complicated technique, including calculation of liquid hold up and unstable foam drilling. Calculations in this paper are based on both criterion and technique. On operational side, several key takeaways are drawn based on operational challenges in multiple combination of operational conditions. This paper proposes comprehensive techniques to design and parameter in operation in aerated drilling. Several cases are presented in this paper and being evaluated using proposed technique. All of the data are taken from real underbalance drilling parameters in Drilling Operation in Indonesia.
Management of Downhole Organic and Inorganic Scale Agglomeration for the Survival of a Marginally Economic Field
Authors: Hamid Mohd Hisham , Johar Zurita , Razali Mohd Ramdzan 
Published: October 2017

AbstractThis paper presents the organic and inorganic scale depositional issues in Field P, a marginal oilfield located offshore Peninsular Malaysia. Routine well interventions such as running pressure surveys, performing zone-switches and gaslift valve change-outs is not a straight-forward affair in Field P. The field not only experiences severe wax-buildups downhole - as field water production continues to increase, calcium carbonate scale has in recent years been precipitating along the tubing wall of most wells, forming an organic plus inorganic agglomeration which is a rare occurrence and not as easily removed as with a conventional solvent or acid soaking job; thus preventing wireline entry for production surveillance and enhancement activities.Several mechanical, chemical and even combination techniques have been deployed with varied levels of success at Field P, which produces waxy crude from a small and unmanned platform. Facilities constraints (i.e. small deckspace and limited crane lifting capacity), a low oil price environment and high cost for effective wax and scale removal all contribute to the list of challenges in arresting production decline and maintaining a healthy cashflow for an asset which is nearing the end of its economic life.This paper describes the different wax and scale removal and inhibition methods tested in Field P, challenges in implementation, treatment effectiveness, and lessons learnt which can be used as reference for asset teams facing similar issues.The study and recommendation to implement an optimal scale management plan is shared.
Overcoming Electrical Submersible Pumping Production Challenges in Highly Deviated Wells
Authors: Mahbes Reda El , Quintero Regulo , Malino Antoni 
Published: October 2017

AbstractDeviated wells with a high dogleg severity (DLS) or buildup rate present major challenges for electrical submersible pumping systems(ESP) and often prevents the installation of ESPs at the deepest possible setting depth (El Mahbes, 2016). Passing ESP systems through a tight bend radius can reduce system reliability and limit how deep the system can be set to achieve maximum oil recovery. This paper highlights the benefit of using a newly designed ESP system for five highly deviated wells.The new tight-radius ESP system is designed to pass through buildup rates of up to 25° per 100 ft. with no impact on reliability. This capability means the ESP can be placed at the lowest possible setting depth closer to the production zone, which permits greater reservoir pressure draw down, enhanced overall production, and improved reserve recovery. In addition, tight-radius ESP system reduces the equipment installation time by more than 50% and eliminates the potential of dropping bolts in the wellbore during installation.This paper presents a comparison between using conventional ESP systems and the new tight-radius ESP design in highly deviated wells and wells where the buildup rate is very high for conventional ESPs to pass through. This technology was applied in multiple wells and results showed that the new ESP design helped extend ESP run life and allowed the operator to set the system deeper in the well, closer to the producing zone, to increase production and maximize reserve recovery.
Well Placement Optimisation in Gas-Condensate Reservoirs Using Genetic Algorithms
Authors: Abdul-Latif Benson Lamidi , Edem Tsikplornu Daniel , Hikmahtiar Syouma 
Published: October 2017

AbstractTo achieve maximum economic revenues in gas-condensate reservoirs, an optimisation tool is employed to estimate the optimum well placement. Uncertainty analysis in gas-condensate reservoirs is a prerequisite requirement before the developing phase of the hydrocarbon reservoir. Contrary to most conventional reservoir development, well spacing optimisation in gas-condensate fields has received less attention due to a general assumption that optimisation techniques and computational methodologies applied to oil fields development can be applied to gas-condensate fields.Uncertainty analyses were performed using fourth-order factorial design on a domain of gas-condensate field's data to identify key factors affecting the production of condensates from heterogeneous and ultra-low permeability reservoirs. Well placement objective functions for gas-condensate reservoirs were optimised as functions of cumulative condensate production using genetic algorithms. With compositional modeling, exhaustive search mechanisms were employed to validate the results of our proposed optimisation tool.Results from the proposed optimisation tool was more economically feasible compared to that of the exhaustive search mechanisms and thus, could be employed as a much simpler, less exhaustive and economically feasible optimisation tool for well placement projects in gas-condensate reservoirs. In using genetic algorithms we concluded that most optimisation tools do not have both reliability and efficiency. Genetic algorithms optimisation tool was observed to be the most reliable method for gas condensate reservoirs though excessive number of simulation runs for large fields makes their application expensive.A more strategic approach was used to formulate objective functions whilst incorporating the effect of condensate banking in gas-condensate reservoirs.
Heavy Oil Sampling Using Wireline Formation Tester - Case Studies of Highly Viscous Oils from Bohai Bay
Authors: Zhang Guoqiang , Tan Zhongjian , Hao Zhongtian , Lei Guowen , Hardikar Nikhil P. 
Published: October 2017

Abstract
Collecting high quality representative heavy oil samples is an essential requirement for detailed PVT and flow assurance analysis. Heavy oil is often discovered in shallow and highly unconsolidated reservoirs, which results in significant formation fluid sampling challenges. To overcome the potential problems of sand influx, emulsion formation and packer seal loss, an operationally optimized and efficient operating procedure has to be applied to sample the highly viscous heavy oil.
Using the optimized sampling methodology, high quality representative fluid samples (priority samples &gt; 95% formation oil) were collected even with a water-cut of 40-70% at the time of sampling by adopting the selective slug sampling technique, thus saving time and money. Low permeability (&lt; 10 md) oil bearing formations were also addressed by applying this fit-for-purpose methodology, thus assisting the oil discovery. The API gravity of the collected samples ranged between 8 ° API and 15 ° API and the viscosity at surface conditions is several centipoises (cp) in many cases.
Based on the successful heavy oil sampling operations, this paper discusses important observations, which can be useful for future planning of similar jobs. These include early oil breakthrough, emulsion effects on sampling and changing mobility during clean-up. Unlike the water-base mud (WBM) invasion characteristics of regular oil bearing formation, which is mainly dominated by overbalance pressure and is a function of time, the invasion of heavy oil bearing formation is highly influenced by viscosity dynamics. The resultant of such dynamics is delayed oil breakthrough and the formation of emulsion during the sampling process, resulting in an undesirably long pumping time before collecting a representative sample with acceptable contamination level. Lastly the changing mobility aspect is discussed, which is caused by drag-force effects and viscosity changes during the clean-up.
Rock Strength Analysis and Integrated FEA Modelling Optimise Bit Selection for Deepwater Exploration Drilling
Authors: Mardiana M. R. , Noviasta Bonar 
Published: October 2017

Abstract
Well X is a deepwater exploration well with the carbonates primary target. The water depth ranges from 2700 to 3400 ft and the well was drilled vertically to 14630 ft MD. The main objectives of this operation was to optimize drilling performance while maintaining safe drilling practice and minimize potential failures. One of the ways to optimize the drilling is to have an excellent bit selection to determine the best bit for the application.
Traditionally, due to limitation of the data, bit records from offset wells or fields becomes the only main source to select a bit. But sometimes, the selection becomes trial and error because of the availability of the data for evaluation. A Rock Strength Analysis (RSA) software now becomes a mandatory requirement for the pre-job planning to select a bit. Using the log data from offset wells, a bit selection software based on Unconfined Compressive Strength (UCMPS) calculation was used to optimize the bits for all section of Well X. The Dynamic FEA Modeling has also been used to contrast the drilling dynamics using several bit options for each section. The analysis is capable to simulate downhole drill string behavior with detailed components model including bits, reamers, driving systems, and all of the BHA components up to the surface. It includes axial, lateral, and torsional vibrations check, and also providing safe drilling parameter roadmaps to be applied in the field. The simulation is based on the cutter-rock interaction data from lab-test and has a wide range of lithology to make the result as accurate as possible.
The integration between the RSA software and the Dynamic FEA Modeling resulted the best bit and parameter roadmaps for this application. Compare to the traditional way, this integrated method can reduce the risk of having poor bit performance in the field. The recommended bit and parameter guidance for each section was then applied to drill Well X and generated satisfying ROP without any NPT related to bit performance. The bits also came out from the hole with 1-1 average dull grade due to the excellent stability of the drilling system. The hard carbonates formation target in 8.5-in and 6-in section was successfully drilled in one run to TD with low shock and vibration.
Even the bits only consume 3-6% of total drilling cost, it has a huge effect to the drilling performance. Combination of RSA and Dynamic FEA Modeling in bit selection process becomes a very effective practice to prepare an exploration drilling program with limited offset well data.