bluuebunny/crossref_metadata_2025 huggingface dataset:
A Leading Model on Evaluation and Training Strategies for National Workforces in International Organizations
Authors: Grice Roger , Plato Kathryn , Zuniga Andres
Published: October 2008

The decision to utilize a proportion of the natural gas reserves of Peru for export purposes and as a valuable foreign currency source was a momentous occasion in the economic evolvement of the country, for with it came the single largest inward investment of $3.8 billion in the history of Peru. The new company, PERU LNG S.R.L. (PERU LNG), would be responsible for developing gas reserves, building a 408-kilometer natural gas pipeline, constructing new storage and export facilities, and of course the LNG plant itself. PERU LNG is a partnership between Hunt Oil Company of Dallas, TX (Project Leader, 50%), SK Energy of South Korea (20%), Spain's Repsol YPF (20%) and Marubeni of Japan (10%). Compania Operadora de LNG del Peru (COLP) is the operating company of PERU LNG. COLP is responsible for constructing the LNG plant and gas supply pipeline, as well as for the plant and pipeline operation and support services.

Although some reference will be made to technical aspects of the project, the main purpose of this paper is to illustrate the approach adopted relating to the training of Peruvian technicians and operators for the new LNG plant. The plant situated at Melchorita will have a capacity of 4.4 million tons per year and will be operational in Q2 2010. COLP (the Company) is initially employing an experienced expatriate workforce with phased replacement by trained Peruvian workers over a ten year period. The strategy and methodology adopted to achieve over 90% Peruvian nationals within the company workforce by 2020 makes up the main body of this paper.

A critical piece of building a sustainable operation in Peru is the integration of Peruvians into the workforce. Workers require proper training to meet regulatory requirements and to ensure work is performed in a competent manner that meets technical, legal and other requirements adopted by the project. Work performed without appropriate training may result in legal non-compliance, non-conformance to applicable quality and performance standards, delays, additional cost, environmental, health and social risks. The Company considered training a critical component to the project and explored several options for delivery of training.
Effective Engineering Decision Matrix Lead to 2-fold Improvement in Gas Well's Productivity
Authors: Nwoke Linus A. , Akinrinmade O. Goke , Ekiyor-Katimi Theophilus P. , Alaka Collins O. , Cookey Mina S.
Published: October 2008

A gas well completed across 60ft interval (with External Gravel Pack (EGP) as sand exclusion option) was successfully tested to 66MMscf/d against 100MMscf/d design potential due to 3rd party barge handling capacity limitation. Production fell far below expectation when the well was hooked-up to the gas plant with maximum production of 20MMscf/d at 100% maximum choke opening. This necessitated a workover to replace suspected faulty Tr-ScSSSV.

The post re-entry performance following the replacement of the Tr-ScSSSV was also poor as the well could only deliver 53MMscf/d at 100% choke opening. The poor performance was suspected to be as a result of near-wellbore damage, caused by the LCM-pill that was used during the re-entry. Integrated Production Modelling (IPM) simulation using various sensitivities on FTHP, skin factors and screen plugging predicted that the poor performance was more from surface than from subsurface issues. Requests to investigate the surface network got initial pushback as the flowline was pigged before hook-up. The popular steer was to acidize the near wellbore region for skin damage removal. Production gain predicted by PROSPER model simulation if the predicted skin damage is removed was however marginal. In an attempt to address the issues, a multi-disciplinary team to tackle the problem starting with the less expensive surface network clean-up drew a decision matrix.

Dismantling and inspection of the flowline connections to the variable choke housing revealed the source of the poor performance. Materials that were used during the flowline laying/pigging (marine rope and hand gloves) were left in the flowline, creating secondary choke (restriction) along the flowline initially and later pushed down to the choke inlet. The removal of these materials left in the flowline and the clean-up of the choke improved production from 53 to a realistic production potential rate of 127MMscf/d at 100% choke opening. The production rate increased to 150MMscf/d at 98% choke size as the well cleaned up after seven months.

This paper demonstrates how good PROSPER modelling, integrated decision matrix and persistence on sound engineering practice led to improved gas production, meeting gas supply commitments and eliminating further unnecessary expenditures ($600,000 on stimulation). Delayed gas recovery was eliminated by this effort, needless to mention the accelerated revenue from the gas supply attributed to this improvement. The paper concludes with Integrated Decision Making Strategy, Value of Success and Recommendations for future interventions.
Maximising Gas Well Potential in the Breagh Field by Mitigating Formation Damage
Authors: McPhee C. , Judt M. , McRae D. , Rapach J.
Published: October 2008

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

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

This 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

An 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

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

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

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

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

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

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

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

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

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.
Utilizing Steam Injection to Improve Performance of Mature Waterflooding Reservoir
Authors: Shuhong Wu , Wenlong Guan , Desheng Ma , Dehuang Shen , jinzhong Liang , Xiaojin Wang
Published: October 2008

F reservoir, a mature waterflooding reservoir with high wax content and oil viscosity higher than 50cp, is developed by 30-year's waterflooding with 14% oil recovery but 90% water-cut. How to rejuvenate such mature reservoir with ‘secondary water body’ and water channel formed by long-time water flooding? The answer is steam injection. The paper will discuss some of mechanisms, strategies as well as barriers and difficulties to high recovery of steam injection following water flooding.

Firstly, the paper will introduce lab experiments, which include single core tube, multi-tube displacement and three-dimension physical experiments and discuss mechanisms of steam injection. Single tube displacement experiment shows steam injection can enhance displacement efficiency to 80% from 40% of waterflooding. Multi-tube and 3-D experiments show steam overriding can help steam to displace oil in the upper un-drived by waterflooding and increase vertical swept efficiency, increase productivity and lower watercut, enhance recovery to 50% from 14%.

Secondly, the paper will discuss key factors such as depth, net-to-gross sand rate, oil viscosity, oil saturation and so on, which shows oil saturation left by waterflooding is the most important factor to influence performance of steam injection.

Thirdly, the paper will detail numerical simulation study, such as well pattern, development manner and pilot test plan. It shows steam injection following waterflooding should obey to several strategies. One of the important is the well pattern designed for steamflooding should make the steam spread evenly and avoid steam rapidly breakthrough to producers through water channel formed by waterflooding.

The paper finally will introduce pilot test performance. More than 100 wells experienced steam injection show high productivity, low water cut and potential to enhance the oil recovery.
Efficient Conceptual Design of an Offshore Gas Gathering Network
Authors: Watson M. J. , Hawkes N. J. , Pickering P. F. , Brown L. D.
Published: October 2008

Offshore gas gathering networks require large capital investments in wells, subsea equipment, pipelines and compression systems. Generally, the optimum design for such systems can only be found by assessing multiple scenarios. Many scenarios may have significant flow assurance constraints, such as hydrate avoidance and/or minimum operating temperature limitations. This paper highlights the benefits of using a modern thermal hydraulic Integrated Production Model (IPM) to investigate the economics and operability of numerous design options for such systems.

A thermal hydraulic IPM simulator was used to carry out a conceptual study of a large offshore gas field with several satellite tiebacks. Production and drilling profiles were predicted subject to multiple constraints, including drilling access, processing capacity and flow assurance operability limits.

IPM calculations were performed to establish the phasing of drilling, field development and compression necessary to sustain required gas delivery rates. The model computation speed was rapid, permitting the fast turnaround of numerous cases. Moreover, the calculations were performed rigorously, thus allowing the simultaneous simulation of flow assurance issues, such as required glycol flow rates and minimum flowing wellhead temperatures to avoid hydrate formation and blockage. By evaluating the gas delivery requirements in conjunction with the flow assurance constraints, it was possible to select an initial concept that was both economically and technically robust.

The main trade-off in the study were well and compression availability; various maximum available compression power profiles were compared to the drilling schedules to meet a given demand for gas. In summary then, the paper presents the application of a software tool to the quickly evaluate and generate an initial development concept for a large gas gathering system with the principal objective of selecting the most capital efficient and economically optimal scheme.
A Miscibility Scoping Study for Gas Injection into a High-Temperature Volatile Oil Reservoir in the Cooper Basin, Australia
Authors: Clark Peter , Toulekima Serge , Sarma Hemanta
Published: October 2008

As part of the Moomba Carbon Storage Project, a scoping study for the potential of miscible gas injection into Tirrawarra, an Australian onshore high temperature volatile oil reservoir, has been completed. Twenty-six injectants with varying compositions of CO2, CH4, C2H6, n-C5H12 and N2 are considered in the study. The volatile oil under study has a CO2 content of approximately 20 mol%. High temperature reservoirs and volatile oils are two extremes of a miscible gas injection system that have not commonly been studied in previous literature.

The minimum miscibility pressure (MMP) between oil and an injectant is a key parameter in a miscible gas injection project, directly affecting project design. MMP is highly dependant on reservoir temperature as well as oil and injectant compositions. Commonly, MMP calculations involve one of the following three methods: (i) thermodynamic miscibility modeling, (ii) laboratory-based miscibility tests and simulations, (iii) use of correlations in the literature. In this study an Equation-of-State is used to facilitate 1-D slim tube simulations, through which the MMP between the volatile oil and various injectants is determined.

Applying commonly used MMP correlations to our study reservoir provided poor results – with some correlations predicting MMP values at up to approximately 140% of those determined through 1-D slim tube simulation. This was due to the inability of many correlations to account for the effect of volatile oil composition and high reservoir temperatures. Our results show that MMP correlations can give misleading results if applied to reservoir data which is dissimilar to that with which the correlation was developed.

The MMP with 100% CO2 injectant was calculated to be 2680 psig at 285°F. The highest MMP was obtained with pure N2 injectant at greater than 3600 psig. Variation of injectant composition had clear effects on the MMP. The increase of both N2 and CH4 concentrations in the injectant raised MMP by 25.6 psi/mol% and 15.2 psi/mol%, respectively. Increasing the C2H6 and n-C5H12 concentrations decreased MMP by 6.4 psi/mol% and 34.4 psi/mol%, respectively. The results of this study will help in developing an optimized injection strategy for the candidate reservoir, in addition to providing insights into key design parameters for surface facilities.
Noise Pollution in Marine Areas-Mitigation and the Need for Wider Protection
Authors: Tyagi Rani
Published: October 2008

Noise Pollution continues to receive increasing attention in international level. This paper reviews a growing body of evidence of the harmful effects of man made noise on marine life. There is an urgent need for a European and global legislative framework for monitoring the effects of underwater noise and regulating the input of underwater noise into the marine environment. The unregulated proliferation of harmful man made noise in the oceans and seas poses potential threat to marine life and ecosystems. The EU Marine strategy process has not been identified underwater noise as a form of pollution. However, a number of applicable legal instruments, including among others, UNCLOSE and the EU Habitats Directive2 Member states with clear obligations to protect marine living resources from disturbance and pollution and to do so in ways that reflect the precautionary principle. Underwater noise should be recognized as a form of pollution within EU legislation and therefore integrated into the Marine Strategy Process, with a view toward developing further specific legislation on the issue.
Early Reservoir Management Insights from the Enfield Oil Development, Offshore Western Australia
Authors: Hamp Roland , Mee Benjamin C. , Duggan Tim J. , Bada Inyau A.
Published: October 2008

Integration of key information in the early life of the Enfield water-flood development project led to improved understanding of the reservoir's architecture and dynamic behavior. This paper provides an overview of the field and a review of the first two years of production from the Enfield reservoir including start up of the field, water injection optimisation, acquisition and interpretation of Australia's first time lapse ‘4D’ seismic survey, key well and reservoir performance learnings, use of chemical tracer technology to monitor fluid movement, and the benefits of comprehensive real time field data transmission to shore.

The Enfield field, discovered in April 1999, is located offshore North West Cape, Western Australia in license WA–28-L. Water depths range from 325m to 550m across the field. Following appraisal drilling and development studies the field was sanctioned for water-flood development in March 2004. The Upper Jurassic Macedon reservoir comprise generally clean, high permeability, unconsolidated sandstone containing a 22° API, moderate viscosity, relatively low GOR oil which is overlain by a significant gas cap. The field has been developed to date via a total of fourteen sub-sea production, water injection and gas re-injection wells producing to a new-build, double hulled FPSO (the ‘Nganhurra’). All five production wells, including three high rate horizontal wells, are completed with open-hole gravel packs for sand control. Key challenges during the development execution phase were operating in an extremely environmentally sensitive, cyclone prone deepwater area, in which there was no existing infrastructure or production operations experience.

Production commenced on 24th July 2006 with oil rates peaking at 74,000 bbl/day in September of that year. Initial production rates were constrained by the slower than expected establishment of pressure support from water injectors and then fell to about 43,000 bbl/day in October when a key production well was shut-in due to high levels of sand production. Significantly different water breakthrough and water cut development in two of the production wells coupled with dynamic pressure data and insights from 4D seismic across the field have started to reveal reservoir complexity greater than previously expected, although overall reservoir connectivity appears to be good.

During the first two years of production operations the reservoir and facility performance has generally been good and in line with pre-development reservoir models, with the exception of sand control in all three key horizontal production wells, each of which were eventually sidetracked in order to install effective open-hole gravel packs in ~600m horizontal sections.
Large Bore Subsea Production Systems for Woodside's Gas Developments
Authors: Jenner Gary , Hughes Gordon
Published: October 2008

Due the high cost of deepwater subsea wells, large bore subsea production systems with high flowrate potential are desirable to lower the development cost of Woodside's gas reserves. With an ever increasing demand for reliable gas supply to LNG facilities, subsea system reliability in Woodside's exsiting and future gas development is of equal importance. With the number of large gas reserves in its portfolio, Woodside has developed an evolving strategy to deliver a suite of standard large bore reliable subsea production components to enable reliable development of gas fields for lower unit cost.

This paper will describe how Woodside has worked together with its subsea system partner, FMC Technologies, to develop the equipment and systems required to facilitate reliable production of deep water high rate gas wells, including Standard 7" gas tree;Manifolds and Pipeline termination assemblies;Large bore diver-less connection systems;Umbilicals and control systems;Managing flow assurance issues (Incl. hydrate prevention, sand and flow management);

Additionally, the paper will discuss the "stepping stone" approach to developing and proving the large bore system components through initial application on the NWS to the deepwater application of Pluto and will highlight the installation drivers associated with this development approach.
West Australian Gas Technology Trial—Benefits of a Local Partnership
Authors: Kavanagh Neil , Inman Jessie , Melaxos Marie
Published: October 2008

Gas technology developed at the Woodside Research Facility at Curtin University in 2003, was the subject of a field trial conducted at a local onshore gas field operated by Arc Energy Limited. Called Gas Subsea Separation and Sweetening, (GS4), the field trial was an industry led collaboration intended to demonstrate two related technologies in one location.

The Woodside technology(1) uses a low temperature process to purposefully form gas hydrates in the raw gas stream, which when removed leave the gas dehydrated. This allows Carbon Steel, as opposed to Corrosion Resistant Alloy, pipeline material to be employed for subsequent distribution, reducing costs. This alternative gas dehydration technology has several advantages over traditional chemical based drying solutions – simplicity, foot print, absence of chemical consumables.

The related CryoCell® technology was developed by Cool Energy and uses a cryogenic process to capture solid CO2 from the gas stream. This technology has significant advantages over traditional chemical based sweetening technologies.

The focus of this paper is on the management of the trial. Woodside is a large scale offshore operator with significant gas interests. Conducting a first technology trial offshore would be slow and expensive. It was decided therefore to work with an upstream operator, ARC Energy, at their onshore Xyris gas field located onshore near Dongara, in Western Australia. The trial was managed through a services contract with local CO2 solutions company, Cool Energy Ltd.

These arrangement delivered many advantages over a conventional in-house trial on an offshore gas facility. The lessons learnt during the trial may assist other operators or technology providers in Australia to mature their technologies for large scale, remote gas applications.

The paper also describe some of the lessons learnt from these arrangements that would improve any repeat trials and outlines some of the opportunities in Australia gas for onshore technology field trials.
Workflow for Integrated Production Modelling of Gas Wells in the Northern Cooper Basin
Authors: Shrestha Tejaswi , Hunt Suzanne , Sarma Hemanta
Published: October 2008

Integrated production modelling is essential for well performance evaluation and enhancement of the production system. It is a process of predicting the effects of changes through a systematic analysis of individual components and the impact of their interaction on field performance1.

This paper describes a best-practice workflow that was followed in an integrated production modelling study of a region in the Cooper Basin, Australia. Procedures are presented that improve time efficiency in development of a surface network model, including rigorous validation of tank, simulation, VLP, IPR and compressor models.

The broad objectives of this work were to improve speed of model development in order to study well inflow performance in complex stacked fluvial sand systems and optimise gas production through investigation of debottlenecking opportunities and additional drill projects. Following the model build, four optimisation scenarios effects were investigated: Alternative flowline connection points for a high rate wellAlternative tie-in connections to different satellites (debottleneck)Additional drill projectsDebottlenecking with additional drill projects.

The aim of this paper is to provide an example of best-practice approach to network optimisation in complex stacked sand multi-layered reservoirs where time efficiency and model validation are critical.
Focussed Data Acquisition Strategy Aids Pluto and Xena Field Reservoir Characterisation
Authors: Conroy Tim , Seggie Robert , Clayton Christopher , Rayfield Mark , Johnson Glen
Published: October 2008

The Pluto gas field, located 190 km northwest of Karratha, Australia, in 400 to 1000m water depth was discovered in April, 2005. A more recently discovered nearby satellite gas field, Xena, is located 10 km east of Pluto. The combined estimated dry gas recoverable volume of the Pluto and Xena fields is approximately 5 Tcf. The early implementation of a well integrated data acquisition strategy has been central to achieving development milestones. Integration of detailed core analysis with high quality wireline logs enabled reservoir understanding in a complex geological setting.

The Pluto field was penetrated by one exploration and five appraisal wells and the Xena field by one exploration and two appraisal wells. The wells targeted the Triassic Mungaroo and Brigadier reservoirs which are fluvio-estuarine in nature with multi Darcy flow properties. The reservoirs are expected to behave as a well connected gas depletion system.

The occasionally radioactive (high gamma ray), heterogeneous inter bedded nature of the Triassic reservoirs necessitated a multi faceted core-log interpretation. Good quality core data and photography coupled with high resolution density-neutron, resistivity image and nuclear magnetic resonance data allowed confident net to gross estimation. Data acquisition and interpretation was designed to address petrophysical, geological, reservoir engineering, quantitative interpretation (QI) geophysical and geomechanical uncertainties in the fields. This knowledge has been used in the construction of geomechanical analyses, static models and dynamic simulations.

This paper demonstrates the benefits of an extensive integrated data acquisition interpretation strategy to aid effective reservoir characterisation early in field life. This strategy assisted optimised development drilling targets, detailed well and completion designs and accelerated field development planning.
Parallel Appraisal and Development Planning of the Pluto Field
Authors: Rayfield Mark A. , Johnson Glen A. , McCarthy Simon , Clayton Chris
Published: October 2008

Discovered in April 2005, in exploration permit WA–350-P, the Pluto gas field lies about 190km north-west of Karratha and the West Australian coastline. Following Pluto appraisal and the discovery of a satellite field in Xena, the best estimate recoverable resource is approximately 5 Tcf dry gas. With an initial 100% equity interest, Woodside was able to quickly reach agreement on foundation LNG sales with two customers, with planned first gas in late 2010. This development will represent the first deepwater gas production from the Carnarvon Basin. The 27 months (Table 1) from discovery to project approval represents a rapid maturation cycle for a reservoir to market greenfield LNG development.

The high quality reservoirs in the Pluto Field are expected to behave as well-connected gas depletion systems. The two main formations of the reservoir are fluvio-estuarine and with excellent flow properties are well understood in the offset North West Shelf Venture (NWSV) fields. Seismic data is reasonable to good, complicated by the field location under the slope down from the continental shelf. Offshore, which will be the focus of this paper, the physical setting on and under the shelf slope provides significant development challenges. The development calls for designing and laying pipelines up part of the continental slope, a riser platform in a challenging geotechnical area and directional drilling of big bore wells.

This paper will describe the challenges faced in the offshore development planning process, particularly given the preferred schedule. The approaches used to facilitate decision making are described, up to and including the Final Investment Decision (FID).

Approvals for the Pluto LNG Project are now in place and the project team is focusing on the execution phase. The Project is on track to be developed from discovery to first gas in around five and a half years. This rapid project maturation can be attributed, at least in part to the effective use of Woodside's field development planning process to quickly and efficiently select the best development concept.