High carbon dioxide in reservoirs limits successful exploration in many petroliferous basins, particularly in Southeast Asia. High reservoir CO2 in the offshore Malay Basin represents a significant exploration challenge. Some fields contain >80% CO2, which makes them unattractive targets for development. Various hypotheses on the origin of CO2 have been proposed but remain controversial. This paper shows that geochemistry and advanced petroleum system modeling help to resolve the origins of reservoir CO2 and allow quantitative estimates of CO2 in prospective reservoir targets prior to drilling. A novel workflow estimates the CO2 content in reservoirs based on knowledge of the chemical mechanisms for the origin of the CO2 and numerical simulation of geologic burial history. Heat flow, deposition of overburden rock, and the kinetics of specific reaction mechanisms control the timing of CO2 generation and the relative contributions of CO2 from different sources. In this study, stable carbon isotope ratios of CO2 and methane (δ13CCO2 and δ13CCH4, ‰) were used to identify the source of the CO2 in Malay Basin gas samples. For example, Figure 3 shows δ13CCO2 and δ13CCH4 for samples from various depths in the nearby field. The isotope data indicate that the samples contain mixed CO2 derived by different mechanisms from two sources. Partial least squares (PLS) regression of δ13CCO2 and δ13CCH4 and depth for 61 samples from the nearby field, where %CO2 was set as the dependent variable, resulted in a systematic correlation between predicted and measured %CO2. Alternate least squares (ALS) confirms that the data can be explained by mixing of gases from two endmembers: (1) shallower samples show lower %CO2 that is isotopically depleted in δ13CCH4 and δ13CCO2, and (2) deeper samples show higher %CO2 that is isotopically enriched in δ13CCH4 and δ13CCO2. The relative proportion of each endmember in the mixture can be calculated for each gas. Examples of near endmember gases in the nearby field (Figure 3) are: (1) shallow thermogenic CO2 derived by cracking of kerogen, e.g., 1681 m, 5% CO2, δ13CCH4 = -60‰, δ13CCO2 = -13‰, (100:0 mix); and (2) deep CO2 from carbonate decomposition, e.g., 2918 m, 74% CO2, δ13CCH4 = -32‰, δ13CCO2 = -3‰ (15:85 mix). These results are consistent with the general observation that tested Miocene traps in the Malay Basin and show a general trend of higher concentrations of CO2 in the deeper traps that are nearer carbonate basement. Biogenic CO2 may represent a third endmember in other parts of the basin.
The study area of this paper is located in the mature North Malay Basin, within the offshore Malaysia-Thailand Joint Development Area (MTJDA). Exploration activities have been conducted since 1971 and several gas fields have been developed, mostly at relatively shallow stratigraphic levels of Late Miocene sequences. The study area covers 7250 km2, which includes exploration and production areas covered by approximately 300 wells, 6400 km2 of 3D surveys and 10664 km of 2D seismic line. The multi-disciplinary team was tasked to establish the overall hydrocarbon potential of the area, including potential new play-openers and covering the area outside of existing PSC acreages. The workflow initially focused on post drill analysis of the existing wells whereby new complete petrophysical analyses for 74 exploration and appraisal wells were incorporated. Geological and geophysical interpretation focused on delineation of regional structural setting and development of a seismic sequence stratigraphic framework. This comprised of interpretation of key selected surfaces at wells and on seismic in the Oligocene and Miocene succession of the North Malay Basin. Upon completion of the tectono-stratigraphic interpretation, litho- and chrono-stratigraphy, sedimentology and sequence stratigraphy, analyses of seismic attributes and gross depositional environments (GDE), velocity model construction, depth conversion, isopach maps, regional overpressure trends; hydrocarbon play analyses could then proceed as supported by comprehensive petroleum system modelling and a regional CO2 study. Source rock hydrocarbon generation and migration timing are favourable throughout the Oligocene to Pliocene at all prospect levels. At lead and prospect scales, work on seismic inversion, AVO analyses and pore pressure modelling were undertaken preceding prospect volumetrics, risking and ranking. Primary target play types are predominantly comprised of stacked, stratigraphic structural combination traps of tidedominated estuarine reservoirs, deposited within a high frequency 4th-order sequence. This comprehensive play based evaluation approach has successfully identified remaining hydrocarbon prospectivity, not only at deeper undrilled stratigraphic levels, but also at current producing shallow sequences. Several potential drillable prospects were further analyzed for future exploration, often with strong stratigraphic elements, as well as unconventional new play-types enabled by conceptual geological models and supported by existing data analysis and interpretation. Furthermore, a robust petroleum system modeling has enhanced and supported prospective plays in this basin, facilitating realistic yet-to-find resource estimates over the entire area, with good future prospectivity remaining in the area. Apart from the various collaborative technical studies carried out during the project, the imperative factor behind the success of this project was the synergy and co-operation among the team members, with regular technical and management reviews.
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