Woodside Energy Research Articles

Development-Well and Execution Planning in a Complex Subsurface Environment - The Effect of Large- and Small-Scale Modeling on Well Deliverability

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 101874, "Development-Well and Execution Planning in a Complex Subsurface Environment - The Impact of Large- and Small-Scale Modeling on Well Deliverability," by G. Philip, SPE, S.K. Twartz, SPE, and J. DePledge, Woodside Energy, prepared for the 2006 SPE Asia Pacific Oil & Gas Conference and Exhibition, Adelaide, Australia, 11–13 September. The Thylacine gas field is in the Otway basin (offshore southeast Australia). The interplay of intrafield faulting and the layered geology provide potential for a high degree of compartmentalization. A significant proportion of the reserves is thought to reside in reservoirs of the Thylacine sandstone member, which contains poor-quality marine sands interbedded with successions of shale and thinly bedded sand/shale. Key to designing wells to achieve satisfactory deliverability was an understanding of the distribution of net reservoir in the background of nonreservoir. Introduction The Thylacine field is 70 km offshore Victoria in Tasmanian waters. The field was discovered and appraised in 2001 with Wells Thylacine-1 and Thylacine-2 (Fig. 1), which penetrated gross hydrocarbon columns of 275 and 240 m, respectively, in the Waarre and Flaxman marine-deltaic sandstone formations. Overlying Belfast shales provide the seal to the accumulation. The discovery and appraisal wells indicated that productivity would be low from the upper reservoir units and that considerable reservoir distribution and connectivity uncertainty exists. These elements present significant challenges to the commercial development of this resource. Any well drilled into sections having lower net-to-gross reservoir-thickness ratio must be placed carefully to enable commercial deliverability. Therefore, a detailed predictive reservoir stratigraphic model integrated with seismic inversion was used. The model increased confidence in the location of the target reservoir. Development Challenges A combination of complex field structure, reservoir-facies areal distribution, and vertical-stacking patterns presented considerable challenges to developing the Thylacine field. Low-quality potentially compartmentalized reservoir sands in Thylacine hold significant gas reserves. Wells in this environment must be designed to intersect sufficient productive reservoir to maximize productivity and connect potential pressure compartments at commercially viable levels. Uncertainty related to reservoir-facies development and the effect of small-scale faulting on individual-well productivity also meant that final horizontal lengths of wells could not be preset and had to be determined as the reservoir section was drilled. Detailed reservoir modeling across the range of potential subsurface outcomes before drilling, translating net-to-gross reservoir-thickness ratio to a productivity and value measure by use of dynamic simulation, provided a working tool for determining optimum horizontal-well length during drilling.

Checklist of the Crustacea collected by the Western Australian Museum/ Woodside Energy Ltd. partnership to explore the Marine Biodiversity of the Dampier Archipelago, Western Australia, 1998-2002

Lots (Exp.) = number of specimen lots collected during Woodside Dampier Archipelago Expeditions Lots (Other) = number of specimen lots collected from Dampier Archipelago prior to or after Woodside Dampier Archipelago Expeditions UN = species collected from the Dampier Archipelago during the expedition, from an unofficial station 00 = species collected from the Dampier Archipelago during the expedition, with station data missing

Screening Methodology for Downhole Sand-Control Selection

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88493, "Screening Methodology for Downhole Sand-Control Selection," by Chris Farrow, SPE, Helix RDS, and David Munro and Thomas McCarthy, Woodside Energy Ltd., prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October. The sand-management strategy for existing Northwest Shelf (NWS) fields offshore Australia involves reactive down-hole sand control in the event sand is produced above acceptable limits. Sand-face completions for new wells consider well and system risks during the life of the development. A screening method was developed to evaluate and rank available sand-control techniques for NWS conditions. Published criteria were used in a systematic manner, allowing a consistent, balanced, and transparent view of benefits and risks across the different system aspects. Introduction The NWS gas/condensate fields (North Rankin, Goodwyn, Perseus, and Echo-Yodel) are approximately 135 km offshore from Dampier, Australia. Typically, these fields were developed without downhole sand control or specific topside sand-handling equipment. Considerable benefits have been realized in terms of development costs and production capacity as a result, with minimal sand production observed to date. However, there is uncertainty about future sand production as reservoirs deplete or water breakthrough occurs. Woodside formed an integrated sand team with the specific aim to protect against the possible effects of sand. The team developed a sand-management strategy as follows. - Manage current (low) levels of sanding by well management (including best practices for sand monitoring, drawdown, and bean up) and assess topside desanding options. - Develop a downhole plan for key existing wells. Activate this plan on a reactive basis if sand production becomes a problem. - Build system robustness against the risk of sand by considering the installation of downhole sand control in new wells. To support this strategy, a systematic approach to ranking available sand-control options (for both remedial and new-field developments) was developed and applied.

Dynamic Simulation Establishes Water-Cut Limits for Well Kickoff

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 88543, "Impact of Dynamic Simulation on Establishing Water-Cut Limits for Well Kickoff," by Juan Carlos Mantecon, SPE, and Iris Andersen, Scandpower Petroleum Technology; David Freeman, SPE, Woodside Energy Ltd.; and Mark Adams, SPE, Helix-RDS, prepared for the 2004 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 18-20 October. Dynamic well modeling can provide understanding and a process that ensures a well is going to flow naturally during initial kickoff or predict the water-cut limits for the restart/kickoff of naturally flowing wells after a shut-in. As reservoir pressure declines and water cut increases, naturally flowing wells often require gas lift (or some other method of artificial lift) to kick off and flow continuously. Generally, these wells encounter kickoff problems at a lower water cut than their natural-flow limit because of fluid-segregation effects in the wellbore under static conditions. Therefore, determining the kickoff limit is of primary importance to determine the optimum gas lift implementation schedule and its economic effect. Dynamic modeling of the wells during kickoff can determine the associated flowing tubinghead pressure (FTHP) that will enable the well to attain steady-state flow as a function of well productivity index (PI), reservoir pressure, and water cut. Introduction A well producing oil, water, and gas will exhibit segregation of the three fluids in the tubing during shut-in. When the well is first opened after the shut-in period, the column of gas is produced from the tubing, leaving a higher-density mixture of oil, water, and new reservoir fluid. The flowing bottomhole pressure (FBHP) of the well reaches a maximum at the point when the gas column has been produced from the tubing. As shown in Fig. 1, in certain circumstances, the weight of fluid in the tubing at this point in time does not allow the well to flow, and the well is deemed to have a kickoff problem. The water cut at which the kickoff problem is experienced usually is lower than the water cut at which the well will naturally stop flowing. Four undersaturated-oil fields with eight wells producing through a subsea system to the Cossack Pioneer floating production, storage, and offloading vessel were studied. Gas lift is expected to be required sometime in the future to kick off production from wells in the Wanaea, Lambert, and Hermes fields. The Cossack field already had gas lift installed in the single producing well (Cossack 4). The Wanaea, Lambert, and Hermes wells do not use artificial lift, although the wells do have gas lift valves installed. Studies to support the installation of gas lift flowlines and sufficient additional compression to meet future artificial-lift requirements are under way. The cost for installation of a gas lift system to support the kickoff of the Wanaea, Lambert, and Hermes wells is significant, and deferring this expenditure could increase asset value. However, the inability to kick off the wells has a bigger value effect in terms of deferred production, typically 10 times greater than the capital-expense-deferment savings.

Predicting Gas-Condensate Relative Permeability and Production Per formance

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 77935, "Applying MAK Gas-Water Relative Permeability Correlations to Predict a Gas- Condensate Relative Permeability and Production Performance (Case Study)," by Henny Mulyadi, SPE, ChevronTexaco Australia Pty Ltd., and Tom Mason and David Steer, SPE, Woodside Energy Ltd., originally presented at the 2002 SPE Asia Pacific Oil and Gas Conference and Exhibition, Melbourne, Australia, 8-10 October.

CAN SUSTAINABLE DEVELOPMENT THINKING BE APPLIED TO NEW OILFIELDS? A CASE STUDY OF THE EARLY STAGES OF THE ENFIELD AREA DEVELOPMENT IN AN ENVIRONMENTALLY AND SOCIALLY SENSITIVE AREA

Can development of a finite resource, such as oil, be consistent with sustainable development? Sustainable development involves meeting the needs of current and future generations through simultaneous consideration of environmental, social and economic aspects (referred to as the triple bottom line).Since 1998, Woodside Energy Ltd (Woodside) has discovered three oil fields in the WA-271-P Permit area offshore North West Cape, northern Western Australia. The fields are some 20 km from the boundary of the Ningaloo Marine Park.The first part of this paper presents a case study of the Enfield Area Development. It describes the approach taken to simultaneously manage environmental, social and economic considerations while planning for the development of oil fields in exploration permit WA-271-P.A range of measures have been employed that are considered examples of best practice for the petroleum industry in Australia, including:early commitment to a range of responsible environmental management measures in design; a comprehensive community engagement program, with links to the development and environmental assessment processes; and pioneering environmental research.Novel methods of establishing environmental and social issues as key priorities within the Woodside development team have been successfully implemented.The case study provides by giving an overview of the most significant environmental risks associated with the proposed development, and concludes that the development does not represent a significant risk to the environment.The second part of the paper then addresses the question of whether oilfields can be developed sustainably, looking at current views from the literature, and whether the approach outlined in the case study can be considered sustainable.While the project is still in an early stage of development, it provides a strong indication that oil development can be consistent with current thinking on sustainability, provided that current needs, which include a dependence on fossil fuels, and future needs, such as preservation of the productive and social value of the environmental resource base, are balanced simultaneously. The paper concludes that oil development, even in an environmentally and socially sensitive area, can help facilitate the transition to a more sustainable future.

Valuation and Strategy Setting for Remote Gas Reserves

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 77930, "The Valuation and Strategy Setting for Remote Gas Reserves," by Jan F. van Elk, SPE, Woodside Energy Ltd., originally presented at the 2002 SPE Asia Pacific Oil and Gas Conference and Exhibition, Melbourne, Australia, 8-10 October.

Geohazards: Are We Looking at Them the Right Way?

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 14106, "Geohazards: Are We Looking at Them the Right Way? View From Down Under," by Andy Lane and Alex Taylor, Woodside Energy Ltd., originally presented at the 2002 Offshore Technology Conference, Houston, 6-9 May.

THE NEXT GENERATION SPATIAL DATA WAREHOUSE

Woodside Energy, based in Perth, Western Australia, has commenced the implementation of its next generation spatial data warehousing and visualisation system. The warehouse facilitates access to data in various corporate geoscience data sets, as well as up-to-date cultural and environmental data. It expands the capabilities of the existing geoscience database by providing a facility to handle spatial data at the database level rather than in files and maps. Spatial data can now be kept in the database, in its correct spatial location, and with a known provenance.Woodside’s worldwide exploration, development and production activities require the use of a wide variety of geographic data such as seismic, bathymetry, wells, permits, coastlines, political boundaries, navigation charts, remote sensing and geological interpretations.Geo-spatial data comes to Woodside in a variety of formats, datums and conditions. The Geomatics Department, through the Geoscience Database and Spatial Information Management teams, loads, maintains and manages all data considered to be corporate. It is quality controlled and placed into the warehouse, where it is readily accessible to technical and administrative staff.Location is an essential element in most Woodside decisions. Because of the new spatial capabilities, a number of geographic information processes are now possible. Additionally information can also be made available through the internet if required.Reliable geographic information will become more widely available in the organisation, and be more easily merged with traditional data types, enhancing the decision-making process.

Well Control of an Influx From a Breathing Fracture

This article is a synopsis of paper SPE 62770, "Well Control of an Influx From a Fracture Breathing Formation," by P.R. Ashley, SPE, Woodside Energy Ltd., originally presented at the 2000 IADC/SPE Asia Pacific Drilling Technology, Kuala Lumpur, 11-13 September.

DEEPWATER EXPLORATION: NORTH WESTERN AUSTRALIA COMPARED WITH GULF OF MEXICO AND MAURITANIA

Some of Australia’s deepwater frontiers are opening up for exploration, with existing and new companies taking acreage positions. Despite favourable fiscal terms and political stability, interest levels have not matched those in international hot spots due to key differences in perceived prospectivity.In this paper, Australia’s deepwater plays in the Northern Carnarvon Basin are compared and contrasted with deepwater plays in the Gulf of Mexico and offshore Mauritania. This comparison is largely based on Woodside Energy Ltd’s exploration pursuits in these areas.The Northern Carnarvon Basin deepwater plays are principally an extension of shallower water petroleum fairways, submerged to greater water depths by the absence of the Tertiary progradational, carbonate shelf sequence. Trap types and reservoir-seal pairs in the deepwater prospects are similar to their shallow water counterparts, but extensive deepwater areas carry an increased exploration risk due to the absence of this shelf overburden to load the Jurassic source rocks into the oil expulsion window. Hydrocarbons generated typically comprise dry gas from deeper Triassic source rocks, often trapped in sub-commercial quantities. Although the basin lacks a world class, widespread, oil-generating source rock, recent deepwater commercial oil discoveries in the Exmouth Sub-basin indicate the existence of a localised sweet spot associated with a Late Jurassic depocentre, similar to the proven Barrow-Dampier Subbasins located in shallower waters.In contrast, Woodside’s deepwater Gulf of Mexico and offshore Mauritania plays combine deepwater depositional systems with present day deepwater. They have reservoir-quality turbidite sandstones, well imaged on excellent quality 3D seismic, sealed by deep marine shales and charged by world class, organic-rich, prolific source rocks. Salt tectonics, shale diapirism and sloperelated slumping and thrusting have generated appealing structural styles, resulting in multiple play types and a density of prospects and leads not seen in Australia’s deepwater frontiers to date.Although elements of these plays are present at some locations in Australia’s deepwater, nowhere yet have all the required exploration ingredients for a major oil province been found juxtaposed as in the proven Gulf of Mexico and the highly prospective offshore Mauritania. Political stability and relatively favourable fiscal terms remain essential in attracting the exploration investment dollar to Australia’s deepwater.

Managing Operating Costs With a Risk- and Economic-Evaluation Tool

This article is a synopsis of paper SPE 64448, "A Risk- and Economic-Evaluation Tool for Management of Operating Costs," by Helen E. Harvey, SPE, and Dale P. Gration, Woodside Energy Ltd., and Stephen Martin, IGL Engineering Pty. Ltd., originally presented at the 2000 SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16-18 October.

THE KYOTO PROTOCOL- THREATS AND OPPORTUNITIES

In 1997, Australia signed the Kyoto Protocol under which it had been assigned what will become a legally binding emissions cap of 108% of its 1990 emissions. This target may be appropriate for our national circumstances but will be challenging to meet. This paper examines the way Woodside Energy Ltd is addressing the threats and opportunities raised by the Kyoto Protocol.The major risk to Woodside's business arises from the division of the Protocol into Annex B and non-Annex B. Australia is in Annex B, which is composed primarily of developed countries that have assigned emission amounts that will be legally binding when the protocol comes into force and is ratified.Meeting the Australian target and the global greenhouse emission reduction objective will require increasing the substitution of gas into national fuel mixes. Natural gas, including LNG, has the lowest lifecycle emissions of any fossil fuel.The Australian LNG industry is the only major Annex B supplier of LNG to Japan and thus would be at a severe competitive disadvantage if the costs of unilaterally imposed abatement policies and measures were applied to the industry in Australia that were not applied to its international competitors. The LNG industry is seeking differential treatment to alleviate this risk. Woodside has proposed a solution, put forward in this paper, that a scheme be negotiated into the Protocol at CoP6, allowing for the repatriation of credits from the LNG fuel cycle to the exporting country. This would permit fair competition across all LNG exporters.Woodside is keen to undertake its fair share of emission reduction and has already implemented some projects that have been successful in this regard. Further implementation of beyond no regrets projects relies on the Commonwealth resolving the recognition for early action question. A trial framework for making decisions on early abatement projects is described.Woodside is also investigating potential opportunities arising from the Protocol. Progress is reported on early investigation into clean development mechanism (CDM) projects and greenhouse abatement research and development (R&D). Sink enhancement studies are nearly complete and a detailed business case is under preparation.

Design of High-Rate Gas Wells: Issues and Solutions

This article is a synopsis of paper SPE 50081, "High-Rate-Gas-Well Design: Issues and Solutions - Goodwyn Gas Condensate, NWS, Australia," by D. Teng, SPE, G. Nettleship, SPE, S. Hicking, and K. Hindmarsh, Woodside Energy Ltd., originally presented at the 1998 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 12-14 October.

Integrated Field-Development Planning

This article is a synopsis of paper SPE 50154, "Laminaria/Corallina - An Integrated Field-Development Planning Approach," by M.N. Shaw, SPE, J.D. Fowles, S. Abernethy, and R. Hamp, SPE, Woodside Energy Ltd., originally presented at the 1998 SPE Asia Pacific Oil and Gas Conference and Exhibition, Perth, Australia, 12-14 October.

DRILLING FLUIDS AND THEIR ENVIRONMENTAL MANAGEMENT: CHARACTERISATION OF BASE FLUIDS AND THE INTRODUCTION OF QUALITY CONTROL PROCEDURES

Since the early 1990s, a variety of invert emulsion base fluids have been introduced into the drilling fluid market. The chemical composition of these fluids has evolved with the focus on minimising the environmental impact of discharged cuttings that contain adhered drilling fluids.The trend within Australia and other regions in which drilling fluids are extensively used, is that the life span of these fluids has become increasingly shorter, due to environmental impact pressures from the regulatory authorities in the North Sea and Australia, as well as public perception within these regions.The Well Construction Department within Woodside Energy Ltd. (WEL) has identified the need to characterise these base fluids in a manner that was both reproducible and definitive. The need was driven by the availability of a large number of commercial base fluids claiming technical and environmental superiority and the requirement for robust quality control systems for the base fluids from production to discharge—a cradle to grave philosophy.To this end, a study was initiated in 1997 where several drilling fluids were analysed using gas chromatography- mass spectrometry (GC-MS) techniques. From this work, four classifications of invert emulsion, non-water based fluids (NWBF) have been identified. They include low toxicity oil based fluids (LTOBF), enhanced mineral oil based fluids (EMOBF), synthetic based fluids (SBF), and oxygen based fluids (OBF). The definition of these fluids and the rationale for this classification is presented here.The GC-MS characterisation has provided an insight into the structure of the base fluid, rheological characteristics, quality control/quality assurance, and in the future, the ability to develop a robust link to minimising environmental impact of the discharge.All of these benefits will aid in developing drilling fluids which achieve the technical objectives of drilling fluids as well as minimising the environmental impact. The quality control procedures for the base fluid also allow an auditable process for benchmarking with input from the regulator, operator, fluid service company and manufacturer.