History matching is traditionally complex and time-consuming: multiple parameters influence the match and their inter-dependency produces effects that are difficult to predict. Defining the match itself can be challenging, since various indexes or responses can be used: water breakthrough timing, pressures, layer contributions etc… Consequently, whilst multiple realisations methodologies are routinely applied for "green" field development planning, most of the time incremental activity screening on "brown" fields is done on a single matching realisation -"the" matched model - with little confidence that the full range of uncertainties is captured. Experimental design provides a well-suited framework to tackle the challenge of multi-realisation history matching, following these key steps:Selection of key parameters with variance analysis,Reduction of dimensionality by creating hybrid parameters, using techniques related to principle component analysis,Predicting matching domains: combination of parameters levels (once discretised) that are likely to generate a match. This greatly helps the likelihood of finding multiple matching realisations, covering the range of parameter variation. This methodology was successfully applied in the F6 subsurface studies, aimed at screening field redevelopment opportunities. F6 is the largest gas field in the Central Luconia carbonate province, offshore Sarawak (Borneo), having a GIIP of more than 7 Tscf. With over half the reserves produced, well capacity is now threatened by the rising aquifer. In order to safeguard and possibly increase the reserves, a field review was undertaken to identify further development opportunities, and a multi-realisation approach was chosen to capture the effect of key subsurface uncertainties on those activities. A total of 28 matching realisations were generated, covering the variation range of the identified key seven parameters whilst optimising the number of runs performed, thus saving time. Key to the success of the method lies in the integration of disciplines to allow the upfront identification of parameters and their ranges. The screening of redevelopment options against those realisations allowed to establish the range of expected incremental reserves, assess risks, and form a sound basis for business decisions. Introduction F6 is the largest gas field within the Sarawak Shell portfolio, with a GIIP of over 7 Tscf. The field covers a large area of approx. 168 km2 and has a gas-bearing interval of over 850 feet thickness. It is an elongated carbonate build-up of Miocen age, which has steep flanks and a generally flat crest. Two main units make up the gas accumulation: the Upper (Zone 1 and Zone 2) reservoir and Lower (Zone 3) reservoir, separated by an extensive baffle (figure 1). The Lower reservoir contains almost two-thirds of the gas in place. Production started in 1987 and the initial field performance indicated a weak aquifer drive, with a slow water rise. Water breakthrough occurred in late 2001, and capacity went under threat since then, and triggered the need to look at infill drilling and redevelopment opportunities. To this purpose a comprehensive subsurface review was undertaken, using the latest information, notably a 3D seismic dataset shot in 2002, but also innovative technologies such as multi-attribute imaging to map the internal architecture, and Experimental Design techniques to perform a multi-parameter history match, aimed at delivering matching subsurface realisations covering the whole range of uncertainties.
It is well established that working in an integrated team is a more valuable and efficient way of working. But how to ensure that the maximum value is harnessed from those multi-disciplinary teams? The approach chosen in Shell Malaysia is to turn the typical sequential study flow pattern from seismic-static-dynamic-development plan into a truly parallel one. This means: integration through iterations, where the end objective is worked from a 50/50 solution iteratively towards the 80/20 or more. This is what 3D-All-The-Way™ is all about!This paper describes a live example of this way of working applied to the further development of F6, one of the largest gas fields operated by Shell Malaysia in Sarawak waters. The F6 field is located in the Central Laconia carbonate province, some 180 km offshore form Bintulu. The field has been on production since 1987, and over half of the reserves produced have been drained by 11 slightly deviated wells from its own standalone platform facilities. F6 existing well capacity is coming under threat with regional aquifer rise and localised coning around wells. As a result, further development is required to maintain the capacity at the level required from the supply plan, and to ensure that reserves are protected against the un-even rise of the aquifer in the field. This redevelopment study used the most recent data available, ranging from 3D seismic, to pressure and contact surveillance. The business value of the 3D-All-The-Way™ approach is (1) speed: as the redevelopment plan and supporting studies are executed in a reduced time-frame (2) efficiency: as from an early stage and continuously through the study work un-realistic subsurface realisations and development options are screened out, (3) quality: the overall robustness of the subsurface work is improved, as every discipline are contributing simultaneously, and at each iteration. Finally, as an added bonus, the teamwork is more enjoyable and cross-discipline learning is enhanced. The methodology followed by the F6 further development team is being applied to other Field Development Plans within Shell Malaysia E&P, with the same success, saving time, improving the quality of the models and of the decisions. Introduction F6 is the largest gas field within the Shell Sarawak portfolio, with a GIIP of ca 7 Tscf. The field covers a large area of approx. 168 km2 and has a gas-bearing interval of over 850 feet thick at its highest point. It is an elongated carbonate build-up, with steep flanks and a generally flat top of Miocene age. Gas is contained in three major zones: the highly prolific Zone1, which forms the upper part of the build-up and contains less than 10% of the GIIP, the lower grade Zone2, which extends over the central half of the build-up and the intermediate quality Zone3 which contains about 2/3 of the gas in place (figure 1). The field is maturing, with over half the reserves produced. Commissioned in 1987, the field has been producing at rates close to platform capacity (700 MMscf/d), from 11 deviated wells. Half the wells were completed on Zone3 and the other half on Zone1. Field performance had been indicating a weak aquifer drive. Water contact movement monitoring has been a key surveillance activity from production start-up, since gas-water coning and aquifer rise represent a key risk to well capacity and to some extent reserves. The first water-breakthrough occurred in late 2001, and since then the primary mitigation had been to perform water shutoffs by cementing off water producing intervals and when possible recomplete higher up on Zone1 and Zone2 (figure 2). However, by then a longer term strategy was required to safeguard reserves and capacity in the field against the water rise. A 3D survey was acquired in mid 2002 to support an infill drilling campaign and a potential field re-development. The reservoir management strategy for the field was clear: in the short-term: maintain capacity with non-rig interventions, the mid-term: increase capacity with infill wells, and the long-term: safeguard and increase reserves with a re-development (figure 3)
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