bluuebunny/crossref_metadata_2025_split huggingface dataset:
Maximising Gas Well Potential in the Breagh Field by Mitigating Formation Damage
Authors: McPhee C. , Judt M. , McRae D. , Rapach J. 
Published: October 2008

Abstract
An initial appraisal well, 42/13-2, drilled in the Breagh gasfield (Southern North Sea) in 1997, produced only 3 mmscf/d and effectively condemned the discovery to be non-viable. The operator subsequently relinquished the licence. The new field operator commissioned an integrated reservoir study which demonstrated that the poor well productivity and high skins were due to exposure of the reservoir formation to water-based drilling and completion fluids which caused extensive formation damage as a result of water retention, fines migration and solids mud invasion.
Following extensive geomechanical analysis to ensure formation integrity during drilling and testing, and core testing to optimise drill-in fluid design and performance, a comprehensive plan was developed to access the hydrocarbons utilising best practice in well construction and completion design. The second appraisal well, 42/13-3, was located on the crest of the mapped structure some 1500m northeast of the 42/13-2 well, and was drilled at lower overbalance using a specially-designed oil-based mud system.
The well was successfully drilled in 2007 without problems, tested, and produced 17.6 mmscf/d with low skins and no sand production, in line with expectation. In the absence of significant of significant formation damage the absolute open flow potential (AOF) has increased tenfold compared to the 42/13-2 welltest.
The recognition of the true reservoir potential by the new operator and the integrated formation damage mitigation methodology has opened up a significant development opportunity and has turned an unwanted asset into a commercially viable development.
Field Study of Enhancing Oil Recovery by Gas Cycling Injection in Ultra Deep Heavy Oil Reservoirs
Authors: Li Juhua , Jiang Tao , Xiao LinPeng , Yang Mingqiang , Zhao Jian 
Published: October 2008

Abstract
A global steady increase of energy consumption coupled with the decline of conventional oil resources points to a more aggressive exploitation of heavy oil. Management decisions and production strategies for heavy oil is booming in China. Block LKQ, one of reservoir of Tuha Oil Field, is a Extra heavy oil reservoir with edge and basal ground water. From 2003 to 2005, stimulation treatment of light oil solvent on pump and fracture had seen poor production performance meanwhile insignificant primary recovery was obtained by conventional development methods available. Availability of hydrocarbon gases produced wells adjacent to other units makes a solvent injection process attractive. Therefore, the field tests on 3 wells YX1, Y101, Y102 by gas cycling injection were carried in 2005. The objective of this study was to on-site investigate the performance of the method for enhanced recovery of LKQ heavy oil field. The paper will detail the static solution test, on-situ preparation, design injection parameters, injection process, every performance round and its result evaluation. It has settled the foundation on overall development in local deep-heavy oil reservoirs.
Several experiments have been carried out and the results show that viscosity of heavy oil dissolved is decreased 97.1% by injection gas. For static miscibility test, the more gas injecting time, the wider miscible region and the higher displacement efficiency. From the experiment figure of the solvent rate gradient, it displays the dissolution rate slows down.
Then a field study was conducted to ascertain whether gas cyclic injection mode can be effectively increase field oil rate and recovery. The field test has been lasting for 2 rounds more than 3 years and more. It was obtained primary success to develop extra deep heavy oil by cyclic gas injection. Using the injection mode, the yield of wells raised 2 times to 5 times, average yield of well was up to 8 tons per day, in which the production cycle was prolonged and oil increment was more and more. It suggests that further on-situ observation will be undertaken intently so that reasonable injecting parameters are adapted to field test in a large scale.
Hierarchical Geostatical Modeling and History Matching Strategies in a Volcanic Formation
Authors: Otake Mayu 
Published: October 2008

AbstractThis paper presents a geostatistical modeling approach to describe the complex facies patterns in a volcanic formation. An object-based approach (modified Boolean method) is employed to account for the macroscopic facies distribution (pattern) combined with a pixel based approach (sequential Gaussian simulation) to honor the small-scale irregularities. The hybrid approach has the advantage of maintaining the main pattern of facies distributions in the volcanic sequence while honoring the exact facies identified from well logs.Within the framework of the geostatistical modeling, a step-by-step history matching methodology was adopted based on the prior knowledge that the facies distribution is a dominant factor to account for the well performances in the target field. The method reduces the computational burden to search the model that best reproduces the production history from the infinite number of realizations.This paper describes the hierarchical geostatistical modeling and history matching methodology and demonstrates its practical utility through application to the representative sector models.
Fines Migration Evaluation in a Mature Field in Libya
Authors: Qiu Kaibin , Gherryo Yousef , Shatwan Mohamed , Fuller John , Martin Wesley 
Published: October 2008

AbstractAn experimental study was conducted on the mature Messla field to investigate the mechanism of fines migration and its contribution in formation damage. In the study, an advanced laboratory test programme was designed after investigation of production history, well performance, in-situ stress state and depletion history. The programme included critical velocity tests and pore volume Compressibility (PVC) fines migration tests. The critical velocity tests investigated the relationship between flow rate and decrease of permeability by flowing the core plug at different flow rate and concurrently measuring corresponding permeability. Additionally, alternating flow of kerosene and formation water was conducted in the tests to investigate the effect of water breakthrough on fines migration. The PVC fines migration tests were carried out by applying triaxial loading to the samples that followed the stress path of reservoir depletion to identify any critical depletion level that may damage the formation during reservoir production. Concurrently, horizontal flow measurements were made with the PVC tests to simulate production. In addition, produced fines were evaluated by using standard light microscope and Scanning Electron Microscopy (SEM). The composition of any fines collected is further identified through X-Ray Diffraction (XRD) analysis. Through these tests, the tendency and severity of fines migration in this field were investigated and the impact of reservoir depletion on permeability was revealed. Based on the knowledge, the sandface completions were optimized to improve their performance.
Reservoir Characterisation of the Miocene Reservoirs of the North Malay Basin, Malaysia-Thailand Joint Development Area (MTJDA)
Authors: Carney S. , Chai S. N. , Barr D. , Leal L. 
Published: October 2008

Abstract
The Cakerawala, Bulan, Bumi and Suriya gas fields in the MTJDA, northern Malay Basin form a major new development hub for the region, with an estimated total GIIP of 9 Tcf. These large assets are very early in their field life with only 300 Bcf of production from Cakerawala field so far. There has however already been significant (USD 1-2 billion) development investment. There is significant subsurface uncertainty due to geological complexities and a detailed, integrated data gathering and interpretation effort was necessary to better understand the asset. The impact of the study is a deeper understanding of the fields' potential and an insight into how to optimally develop these complex resources. This study covers many aspects of the reservoir characterisation process with examples from the North Malay Basin and has application in other complex fields.
The subsurface geology comprises a thick interval (more than 7,000 ft) of stacked, clastic, fine grained, often clay-rich reservoirs, deposited in an upper delta plain to shallow marine environment. Significant challenges exist in developing these fields due to the large development area, thick zones of interest, large number of reservoirs and challenging depositional setting. There are also petrophysical issues to overcome, including fine scale reservoir heterogeneity, complex mineralogy and the presence of low-resistivity low-contrast (LRLC) pay.
An improved understanding of the factors controlling reservoir quality was achieved by adopting a holistic and multidisciplinary approach. This included the integration of stratigraphic, depositional and lithofacies information along with mineralogical and pore system data.
Key lessons learnt include the importance of acquiring good subsurface rock data and the construction of robust databases. The novel application of Lorenz plots and Winland R35 analysis calibrated to test data provided key rock quality and heterogeneity information for inclusion in geo-engineering models. The definition of LRLC reservoirs proved to be an important milestone which led to the development of a water saturation cut-off for gas-productive reservoirs. These findings are now being incorporated into our forward development strategies in Block A-18 and other assets. Success was achieved on a highly complex problem due to the application of an integrated, multi-disciplinary work flow.
People and Parts—Transforming the Risk Drivers
Authors: Cooper S. R. 
Published: October 2008

Abstract
The hazards of oil and gas facilities are well known to the league of operators, hardware providers, designers and lieges of contractors and consultants who work supporting the industry. Since Piper Alpha in 1988 safety is and has been a priority and the driver of countless modifications to ensure the well being of personnel in operating environments.
The oil and gas industry overall has shown a declining trend in fatalities and injury rates around the world demonstrating that learnings from mistakes have been taken on board so that they are not to be repeated. With the advent of deepwater production, bigger equipment items, changing field conditions and extended field lives, the financial rewards have become potentially even greater than ever to the industry, but at what risk?
The drivers are changing just like in the Le Mans 24 hour car race, the impact of safety risk is less prevalent as people are removed and other risks comes to the fore.
This paper discusses some of the issues that Granherne and the author has experienced in its provision of safety services to the oil and gas industry and provides an insight into how safety principles can still be focused even without the people present.
Scenario Analysis Tool for Probabilistic Analysis of Reserves
Authors: Collinson R. , Gupta R. , Smith G. C. , Van Elk J. F. 
Published: October 2008

Abstract
Probabilistic assessment of reserves is commonly performed through a series of reservoir simulations over the range of field parameters. In most cases, an exhaustive study of parameter combinations is unfeasible because the number of parameters to be investigated is usually large. Statistical design of experiments (DOE) can be used to select a small number of reservoir simulation runs. The choice of design, especially its ability to capture complex interactions in field parameters, is crucial for DOE to be successful. To this end, we have developed a Scenario Analysis Tool (SAT) using DOE methodology for selecting scenarios to run in 3-D modelling and analyse the resulting reserves values to estimate the ultimate recovery.
The primary goal of SAT is to minimise experimental effort (and cost) by recommending the minimum number of reservoir simulation runs required to accurately estimate uncertainty in hydrocarbon reserves for a given set of uncertainty parameters. The process has three main steps: specify the uncertainty framework to generate appropriate scenarios;model scenarios in 3-D simulators and input the response into SAT; anduse SAT to perform the analysis and generate the probabilistic response curve.
SAT is implemented within the Microsoft Excel environment, making it user friendly with simple and intuitive data entry and minimal training requirements. The user is guided by menus and dialog boxes through a few simple sequential steps. SAT output includes reserves estimates, probabilistic response curves, tornado charts, and a comprehensive statistical output. Efficient designs results in a significant reduction in simulation effort for generating the reserves value. Usually, less than 0.1% of possible models need to be simulated and confidence levels are beyond exploration teams' expectations. The capability of SAT will be demonstrated through a number of examples.
Downhole Pressure Boosting in Natural Gas Wells: Results from Prototype Testing
Authors: Geary B. , Alford A. , Bernatt N. , Liley J. E. N. 
Published: October 2008

Abstract
Downhole Gas Compression (DGC) is an entirely new powered artificial lift technology designed specifically for gas wells which stands to serve an as yet unrealised opportunity within the Upstream Gas industry. The paper presents two key elements in this ongoing Joint Industry Programme supported by three major E&P companies.
The first element describes the key enabling technologies of DGC, a low loss electrical power delivery system and the application of gas bearings to a downhole rotating assembly.
The second element of the paper describes the verification philosophy being followed and presents the results from subsystem testing through to full prototype testing that is being conducted in a new fully representative multi-phase flow loop.
CO2 Storage—Managing the Risk Associated With Well Leakage over Long Timescales
Authors: Le Guen Y. , Le Gouevec J. , Chammas R. , Gerard B. , Poupard O. , Van Der Beken A. , Jammes L. 
Published: October 2008

Abstract
One of the major challenges associated with CO2 geological storage is the performance of the confining system over long timescales. In particular, the occurrence of CO2 leakage through existing wells could not only defeat the purpose of storage but also badly affect human health or the environment. Indeed, cement degradation and casing corrosion in injection, production or abandoned wells can create preferential channels over time, allowing migration of CO2 from the reservoir to shallower formations (e.g. aquifers), and/or to the surface.
In this paper, a risk-based approach is proposed for well integrity and confinement performance management. The approach, based on Performance and Risk Management methodology (P&R™), serves as a decision support tool. The major steps are (i) identifying the system and the sources of degradation through characterization and system analysis; (ii) quantifying their criticity through modeling, in terms of probability and severity, and (iii) establishing a risk mitigation plan. This methodology is based on experience in material aging and risk assessment of complex systems, like nuclear structures, where probabilistic simulations are performed. It accounts for all stakes involved in well integrity management and enables the full integration of uncertainties as part of risk estimation.
The methodology presented here greatly improves common approaches based on "Features, Events, and Processes" as it quantifies risk levels. It provides useful and reliable tools to support decisions for well integrity management strategies or emergency plans. To that purpose, mitigation actions such as characterization/inspection, remediation (workover), design improvement or monitoring are valued based on a cost/benefits ratio. Moreover, updating risk assessment with incoming data allows for an evolving vision of risk levels to optimize interventions in time.
This approach is successfully applied, leading to recommendations for safer and more efficient design, maintenance, and monitoring strategies.
Successful Implementation of Horizontal Open-Hole Gravel Packing in the Stybarrow Field, Offshore Western Australia
Authors: Napalowski Ralf , Hill Robin , Stomp Robert , Fagervik Egil , Derkach Edward , Manning David 
Published: October 2008

Abstract
Key sandface completion challenges were faced in the selection, design, planning and execution phases of the open-hole horizontal gravel pack completions in the deepwater Stybarrow Field, offshore Western Australia. Only limited technical experience and infrastructure were available in country to support such a complex operation. Additionally, the lateral reservoir quality variations and challenging sand/shale heterogeneities have necessitated an early focus on appropriate reservoir drilling fluid design, detailed sand screen selection, and gravel pack modeling to minimize premature screen out during gravel packing and ensuring minimal formation damage.
This paper documents the multidisciplinary approach that commenced during the field appraisal and data acquisition stages to derive the sand management plan and culminated in the successful implementation of four horizontal open-hole gravel packs. A novel reservoir drilling fluid design, extensive formation damage testing and the selection of the circulating gravel packing technique have led to the successful sand control implementation with pack factors in excess of 100%. Attention to detail during detailed design, extensive contingency planning and diligent execution were major contributing factors in delivering high quality wells capable of producing as per basis of well design proven by early production performance. The Stybarrow Development represents the first successful implementation of horizontal open-hole gravel packing in Australia.
Measurement of the Diffusion Coefficient of CO2 in Formation Water Under Reservoir Conditions: Implications for CO2 Storage
Authors: Bahar M. , Liu K. 
Published: October 2008

Abstract
Laboratory measurements of the diffusion coefficient of CO2 into brine under both unsteady state and steady state conditions were carried out to obtain the dissolution rates of CO2 during CO2 injection and/or flooding in short term and for CO2 preservation at thermodynamic equilibrium in long term. The experiments used pure CO2 gas and a synthetic brine of 2% NaCl with experimental P/T conditions at 2580 Psia and 83 °C, respectively, similar to that of the target reservoir interval of the proposed CO2 injection well (CRC-1) in the Otway Bain, Australia. The pressure drop in the core flooding cell during the contact of the CO2 and brine phases was used to measure the diffusion coefficient of the system under the storage condition. The diffusion mechanism includes both a steady state and an unsteady state component. The diffusion coefficient of the CO2 in the unsteady state appears to be larger than that of the steady state. The duration of the unsteady state appears to strongly depend on the pressure and temperature of the system.
Horizontal Well Best Practices to Reverse Production Decline in Mature Fields in South China Sea
Authors: Hongqing You , Ping Wei , Xiang Tian , Dong Xu Xiang , JiHong Lian , Tran Thanh , Partono Yoseph J. , Kok Jeffrey , Yang Liu , Balka Sarfraz 
Published: October 2008

Abstract
The Huizhou 6S and 3S oil fields in the Pearl River Basin, Offshore South China Sea are mature fields which have produced 40% to 60% of their original oil in place since 1991. Currently the field production is rapidly declining and water production is increasing. However, through reservoir surveillance data, geologic and reservoir modeling, significant recoverable oil was identified in shaly sandstone reservoirs and attic structural locations of clean sandstone reservoirs. As a result, a comprehensive portfolio of prospects has been built for a robust development program. Horizontal wells were utilized to improve oil recovery in shaly sands and to reduce water coning in thin remaining oil columns. Horizontal drilling best practices were applied during well planning and drilling executions, such as optimum well designs, specific LWD/MWD tool selections, low fluid loss drilling fluids, real-time geosteering data monitoring and the cleaning of the pay zone during completions were applied to maximize reserve recovery and successfully reverse the field's production decline.
EOR Using Thin Oil Film Drainage Mechanism in Water Wet Oil Reservoir
Authors: Maeda Haruo , Okatsu Komei 
Published: October 2008

Abstract
Recovery of residual oil by gas flooding is one of the usual and effective Enhanced Oil recovery (EOR) methods. However, generally in immiscible gas flooding operation, high oil recovery cannot be expected, especially in waterflood reservoirs. In such cases, if the relationship of interfacial tensions among three phases (oil, gas and water) meets some conditions, thin oil film drainage mechanism is applicable as a unique EOR technique. Oil film drainage phenomena involve the formation of a thin film by residual oil brobs in water wet media which becomes continuous between water and gas under certain conditions and consequently recovers mobility.
This investigation reports the results from experimental and mathematical model studies of the pore scale thin oil film drainage mechanism responsible for the mobilization of waterflood residual oil by immiscible gas floods in strongly water wet conditions in high pressure and high temperature conditions. One is the micro pore film flow experiment study, and another is 2 Dimensional 3 phase micro flow simulation study based on Lattice Boltzmann Method (LBM). These two approaches show that thin oil film drainage become very effective to recover water flood residual oil in the case of Positive Spreading Coefficient, especially with high positive value. The higher the positive spreading value, the more the oil recovery, because in such case, the thin oil film spreads and flows easily in the reservoir.
Furthermore in order to verify oil recovery enhancement of gasflood by oil film flow in the reservoir condition (that is, high pressure and high temperature, three dimension porous space), a core flood experiment assuming film flow was carried out under the same conditions as actual reservoir. Since the oil film is supposed to be formed after the interfacial tensions are balanced, a soak period was set during gasflood to balance the interfacial tensions. The oil production behavior was different between before and after the soak period, which indicates that the film flow phenomena occurred.