bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Application of the PRMS to Coal Seam Gas
Authors: Barker Geoffrey J 
Published: October 2008

Abstract
In March 2007, the SPE Board, along with the WPC, AAPG and SPEE approved the new Petroleum Resources Management System (PRMS). The PRMS contains a set of definitions, standards and guidelines for the classification of conventional and unconventional petroleum resources.
This paper discusses the importance of coal seam gas as a global resource and presents an overview of the coal seam gas industry in Australia. The basic principles of the PRMS are presented and the current practices used by the industry to classify and categorise reserves and resources are summarised. Unconventional petroleum resources require different evaluation and development techniques and have their own uncertainty characteristics which can affect reserves booking. The scale of development projects may also be very different for 1P, 2P and 3P reserves categories and consequently each of these may require considerably different capital investment.
Industry practice indicates that there may be some confusion about the application of the PRMS to coal seam gas properties and therefore it is the objective of this paper to assist stakeholders to correctly and consistently apply the PRMS standards. This is of particular importance as the development of coal seam gas is going through an exponential growth phase in the drive to meet record demand.
Acid Gas Removal System for Tangga Barat Cluster Gas Development – Case Study
Authors: Muhamad Suhana , Hassan Nur Hayati , Sabri Harris Abd Rahman , Ariff Izrul Akmal M , A Karim A Hamid , Hong Teh Yat 
Published: October 2008

Abstract
This paper discusses challenges in developing high CO2 gas fields based on project execution of Tangga Barat Cluster, the very first high CO2 gas cluster being developed offshore Peninsular Malaysia by PETRONAS Carigali. Discussion focuses on the intricacy and challenges specifically on designing offshore facilities to accommodate one of the largest Acid Gas Removal System (AGRS) offshore. It addresses steps and considerations in decision making, reaching the most advantageous solutions, in designing the AGRS as well as the overall facilities which involves the required supporting utilities. Data from well tests, FORGAS simulations, and process model from HYSYS among others shall be woven in the discussion.
The discussions on the executed design strategy shall benefit future high CO2 gas fields projects by providing at the very least, a design guidance. The paper highlights the modus operandi in ensuring the final gas specifications of 8 mole% CO2 is met while accommodating different AGRS technology provider utilities requirements.
The membrane technology was identified for the bulk CO2 removal of 35% down to 8% CO2 in sales gas. Due to distinctive differences in the technology provider's removal processes, several factors were considered in designing the process utilities, electrical, mechanical and structural aspect of the system. The overall project economics for hydrocarbon losses in both single and two stage systems were assessed to reach a decision with acceptable losses. The operating conditions of the AGRS were optimized through the analysis of the reservoirs pressure and the booster compressor optimization.
In view of the high development costs associated with these acidic fields, it is the author's intent to contribute, to some degree, lessons learnt in the planning, design and execution for future acidic field developments. It is aspired that through costs, time and resources optimization, the overall project economics can be improved.