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 24 th 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.Key successes to date have included the ability to monitor well and facility operating conditions virtually in real time from the Operators onshore offices, the reservoir insights gained from a very early monitor 4D survey, and the organisational integration between the Reservoir Development team and the Production Operations tea...

The Laminaria and Corallina Fields were discovered in 1994 and 1995, within permit AC/P8 in the Timor Sea, and are currently being developed using subsea wells, manifolds, flowlines and a large Floating Production, Storage and Offloading (FPSO) vessel. Expected reserves for the combined fields ranges from 130 to 250 MMbbl and production is planned to commence in October 1999, five years after field discovery. In order to achieve this, subsurface development studies have been conducted in parallel with facility concept and engineering design studies. Due to the large range of reserves associated with the two fields, leading edge technology and rigorous uncertainty management techniques have been used to produce a robust development plan. Seismic imaging in this area is particularly difficult and has been enhanced by using Prestack Depth Migration. Even so, structural mapping remains the largest factor contributing to reserves uncertainty. P. 497

Australia's National Offshore Petroleum Titles Administrator (‘NOPTA’) has completed a project to gain more detailed insights from field development and performance monitoring of Australian offshore gas developments in Commonwealth waters (excluding state and Northern Territory coastal waters). These insights help identify benchmarks for optimum long-term recovery and aspects of good oilfield practice when evaluating existing and future gas field developments. The methodology applied, high-level metrics, example analysis plots and key insights are discussed. A new confidential in-house Field Benchmarking Database (‘Database’) has been built, collating a large subset of Australian offshore gas field data acquired by NOPTA from titleholders. The key datasets include field and reservoir properties, facilities data, development timelines and development costs. The Database also references reserves information, production data and estimated ultimate recovery, thereby allowing for quantified analysis and assessment of offshore gas fields in Commonwealth waters within a variety of subsurface, development, operational and commercial contexts. Data set correlations based on actual and planned long-term gas field performance, capital investment, and resource recovery are utilised to create a range of benchmarking plots focussed on production efficiency, recovery efficiency, schedule efficiency and cost efficiency. A number of key insights from these metrics are presented. The approach presented lends itself to all petroleum resources within Australian waters. However, this exercise has focussed on gas fields where there are a large number of data (e.g. within each basin, reservoir age, etc.) and where there is a diversity of field performance experience. Consistent with NOPTA's role and resource management objectives, the new Database and workflows enable efficient analysis of past, present and future field developments. This facilitates the ongoing assessment of developed and undeveloped field performance with regard to recovery, production, capital and schedule efficiencies. Thus, improvement opportunities can be identified. Although the Database which underpins these insights represents a high-level view of the field and project performance data, it demonstrates the key influencing effects of reservoir quality, resource size and field location. The outcomes of benchmarking are also used to support more performance improvement focussed discussion between the NOPTA and titleholders. Additionally, the benefits of improved recovery initiatives as well as late life investments can be evaluated. Existing commercial databases and benchmarks do not have a comprehensive dataset of regional analogues specific to Australian offshore petroleum resources, particularly for gas field developments. The derived insights are practically useful and valuable for both titleholders and NOPTA, with the shared objective of delivering continuous improvement in optimum long-term recovery and good oilfield practice.

Woodside Offshore Petroleum, together with joint venture participants Shell Development Australia and BHP Petroleum, are developing the Laminaria and Corallina Fields in the Timor Sea. The selected development concept is a floating monohull production facility supplied by subsea wells. This paper describes the approach taken by the Project team to deliver a diverless deepwater subsea facility which met the objectives of flexibility and maximised value whilst accommodating the evolving subsurface modelling process. A key element of the approach selected was the philosophy of Best Managed Risk (BMR), and the application of this philosophy to deal with reservoir uncertainties during the subsea design process is discussed. A second key element was the early definition of a "minimum facilities field layout" to which additional facilities could only be added if justified by a rigorous business case which demonstrated added value to the Project. The benefits of this strategy in allowing capital expenditure to be controlled in the face of significant uncertainties is discussed and supported by several examples. P. 327

The Nelson field gas-lift completions were designed to optimize production, enhance safety and reliability, and minimize well-maintenance costs. The completions are of a near-monobore design and include an annular safety system, which is regarded as a major safety benefit during gas lift. The single-trip completions were batch installed in eight high-angle (up to 70·) predrilled wells. This paper presents details of the completion design and the approach taken to planning and installing the completions. The paper also describes the use of a novel technique for perforating the platform wells with wireline guns.