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Seismic attributes are routinely used to interpret depositional patterns, particularly where channel systems form the main reservoir sands. This paper presents an example of an apparently clearly imaged channel-like feature, the size of which did not match that implied by pressure transient analysis. The anomaly in question is a relatively straight, sharp-edged, channel-like feature interpreted at a TWT depth greater than 2 seconds. An appraisal well was drilled through the feature, encountering a gas-charged sand at the interpreted level in the well. A drill-stem test (DST) was conducted, and gas was produced to surface in a sustainable manner. Based on the combination of seismic attributes and well data, the sand body was geologically interpreted to be a relatively clean, tidally reworked sand deposited in a linear incised valley, with thickness-width ratio of around 1:30. This ratio is considered narrow for the depositional setting, but is within published ranges for channel systems. When the DST results were subjected to Pressure Transient Analysis (PTA) and dynamic modeling, the technique implied that the sand had a drainage radius several times that indicated by the seismic attribute. Subsequent re-interpretation of the seismic anomaly has led to the conclusion that the seismic attribute did not image the reservoir sand. Rather, the attribute is now thought to indicate an erosional cut through a coal bed, which by coincidence overlies a gas-filled sand. The discrepancy between the seismic interpretation and the well test result has implications for volumetric estimates. Long-term production testing is therefore being considered in order to better-define the lateral extent of the reservoir. In the meantime, a high level of caution will be applied to the interpretation of seismic images from deeper reservoir intervals. Introduction Carigali Hess operates four gas fields within Block A-18 (Figure 1) of the northern Malay Basin: Cakerawala, Bumi, Suriya and Bulan. Gas pay in these fields occurs within multiple, stacked sandstone reservoirs that range in depth from less than 4,000 ft to greater than 10,000 ft subsea. A 3-D Q-Marine seismic survey was acquired in 2006, and attributes from this survey have been routinely used to successfully identify and target gas pay sands in the shallower reservoir intervals. Seismic attributes have also been used on deeper reservoir intervals in order to identify potential reservoir bodies.

Irong Barat Field, located in the southeastern part of the Malay Basin, was discovered in 1979. The field structure is a complexly faulted WNW-ESE trending asymmetrical anticline dissected into four major fault blocks by a set of NNW- SSE trending normal faults, with additional subsidiary faults further segmenting the field in the central fault blocks. Oil bearing reservoirs are encountered in the H and I reservoir groups, with the bulk of reserves and present production from the H-50 unit. Existing development, 18 wells from a manned Irong Barat A platform, is mainly confined to the structurally less complex Fault Block I with 2 wells completed in the adjacent Fault Block II. Production started in November 1983 and more than 80% of the estimated developed reserves have been produced. Currently the field is producing at 11 MSTB/D. A multi-disciplinary team was formed to identify and mature the hydrocarbon potential of the complexly faulted undeveloped Fault Block II, III and IV and also the remaining opportunity in Fault Block I. The 3D seismic, appraisal well, production and well data were reviewed and a few development options were considered. As a result of the integrated field review, 2 additional drilling programs are planned to further develop the field, which involve drilling of 20 new wells from existing Irong Barat A and a new Irong Barat B platform. This paper discusses how the integrated field review enabled the team to further develop the field through better understanding of the reservoir and geology and better managing of the uncertainties. Introduction The Irong Barat oil field lies in the South China Sea about 184 km to the east of Kertih, Terengganu in a water depth of 60 m (Fig. 1). The field was discovered in 1979 and a total of 12 exploration wells were drilled to delineate the field over a period of 17 years. Irong Barat structure is a faulted asymmetrical anticline plunging to the west and is divided into four major fault blocks: Fault Blocks I (FBI), II (FBII), III (FBIII) and IV (FBIV) (Fig. 2 and 3). Irong Barat came on stream in November 1983 from Irong Barat A platform via 15 development wells. 13 wells were confined in FBI and 2 wells in the adjacent FBII (Fig. 4). The developed reservoirs are the H and I Groups with the H-50 unit containing 94% of the reserves. The oil production peaked at 23 MSTB/D in 1984. 3 additional infill wells were then drilled in late 1988 providing an incremental peak rate of 12 MSTB/D (Fig. 5). Currently the field is producing at 11 MSTB/D with an increasing gas oil ratio of 1000 Scf/Stb, and water cut of less than 10%. As of end of 1999, 106 MMSTB of oil or about 82% of the total developed field reserves have been produced. In order to identify and mature the hydrocarbon potential of the complexly faulted undeveloped, an integrated multi disciplinary team was formed with members from reservoir, geology, geophysics and drilling groups.

The Wheatstone gas field located in the Northern Carnarvon Basin offshore Western Australia achieved first gas in mid-2017. All seven foundation producers are equipped with permanent downhole gauges (PDHGs) for real-time pressure monitoring. Data from these gauges have been instrumental in understanding dynamic reservoir performance and reducing static uncertainties. The scope of this paper specifically covers the use of pressure and rate transient analyses (PTA and RTA) and the insights that have been gained during the first two years of production. Significant offset distances exist between each PDHG and the reservoir. Corrections were developed to convert the gauge pressure to a reservoir datum, which primarily account for frictional and gas density changes with varying rates and temperatures within the wellbore. Other physical constraints and effects have been found to be more challenging to overcome, limiting the quality and interpretability of the pressure transients, particularly in the middle-time region. These include interference from non-reservoir pressure signals such as liquid fallback during shut-in, extremely low signal-to-noise ratios in the higher quality formations, and proximity to boundaries that render a short infinite-acting radial flow (IARF) period that could be masked by wellbore storage. Attempts to circumvent these issues have included the use of drawdown transient analysis to complement build-ups. The step-rate test can eliminate liquid fallback entirely, which allows for better resolution of the IARF period. Rapid choke movements were also trialled to boost the reservoir response in some instances. Interpretations using the drawdown data were further verified in one producer through analysis of the buildup data acquired following a routine downhole safety valve closure, which benefitted from the trapping of condensed liquid above the closed valve. This provided the cleanest PTA data seen outside of drill stem testing during field appraisal. While successful in the example presented, no methods have yet been found to reliably increase IARF interpretability in those wells producing from the best quality sands. Regarding RTA, the authors have found very few documented cases in the literature of applying this technique to conventional gas fields. To field-test its applicability in such an environment, evaluations of drainage volume by producer were performed and found satisfactory when compared with other estimates of gas in-place. It is hoped that a presentation and discussion of this finding will be additive to the reservoir engineering toolkit.

This paper presents an integrated production model construction workflow with actual field application from four fields with multiple stacked reservoirs and with varying carbon dioxide (CO2) content (up to 60%) located in the Malaysia-Thailand Joint Development Area (MTJDA). The subsurface-to-surface linked coupled models are history matched to field performance and reconciled to the surface gas utilization (fuel, flare, drop-out, etc.) under specific operating conditions to meet sales specifications. The capability of the subsurface-to-surface linked coupled models is further enhanced with the modeling of the CO2 membrane unit to aid in development planning. This integration is expected to help to maximize the economic value from the assets by accurately predicting the reservoir performance with respect to the surface network constraints. The objectives of this project are to: Produce more reliable sales forecastsGenerate representative reserves recovery estimatesEqually compare different projects in different fieldsEstimate the timing of future developments to meet existing Gas Sales Agreements The construction workflow can be described in four steps: Project DefinitionTest of ConceptQuality ControlForecast. Project work scope calls for a coupled model that is able to generate a fully-automated combined field deliverability forecast at specified sales CO2 content that takes into account the CO2 removal unit, intra-field pipeline network, and every developable reservoir within the area. This custom built simulation model is capable of generating incremental production profiles from the integrated dynamic simulation models (as opposed to tank models) to the sales point and its configuration allows a "plug and play" option to allow additional models to be integrated easily. This is an example of effective use of current simulation techniques to robustly and efficiently address the challenges of developing complex assets with highly variable CO2 content.