Boolean Modelling of the Fluvial Mungaroo Formation, Gorgon Field, Northwest Shelf, Australia
Abstract: The objective in building the Gorgon reservoir characterisation and simulation model was to create a 3D, object based model in a sequence stratigraphic framework integrating core, log, engineering, and seismic attribute data. The project team specified that software and work flow must incorporate marked point - boolean processes with or without seismic conditioning, recognise uncertainties in reservoir and model input parameters, generate multiple model realisations for a probabilistic range of gas in place, a… Show more
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Prediction of sandstone body dimensions within paralic depositional systems is crucial for the development of predictive 3D reservoir models. Continental-scale paralic reservoir targets have complex architectures, with interpretation often further compounded because they are often located at subsurface depths ≥2 km in pre- and synrift basinal settings, typified by poor seismic resolution. As such, in many cases analysis relies on core and wireline-log data, from which depositional facies are interpreted and thicknesses of sandstone reservoir units measured. Estimation of width:thickness (W:T) ratios for different reservoir elements relies on analogue data. However, the inherent uncertainty in the initial interpretation of core/log data and the wide W:T ranges for different sandstone bodies within published analogue datasets hinders prediction of accurate reservoir geometry/dimensions. Without access to quality seismic data, constraining the evolution and dimensions of reservoirs in these depositional systems is challenging.This paper presents a detailed case study of the Triassic Mungaroo Formation, and assesses the uncertainty and limitation of interpretations that can be made about reservoir architecture and the evolution of a paralic depositional system, if only wireline and core data are available.The Mungaroo Formation is characterized by upper and lower delta-plain channel sandstones, swamps and restricted embayments, through to delta-front and pro-delta heterolithics. Core-to-wireline-log calibration allowed identification of key marine intervals that enabled well correlations to be established across the study area, based on candidate flooding surfaces. Applying classic sequence stratigraphic models to low gradient fluvio-deltaic systems is difficult, due to a lack of preservation and/or confident identification of laterally continuous chronostratigraphic markers. The large-scale temporal change in reservoir architecture was likely to have been controlled by eustatic sea level causing overall transgression of the depositional system. However, the observed complex spatial facies variability is most likely controlled by climatic-induced changes in sediment supply/fluvial discharge and autocyclic processes.Four classes of sandstone bodies/reservoir elements have been identified from core and wireline data based on their thickness distributions. Whereas core to wireline to seismic calibration has enabled large-, medium- and small-scale geobodies to be identified representing fluvial channel belt complexes; multistorey channel belts; and single-storey channel belts, respectively. To predict channel body widths and sinuosity from thickness data extracted from wells, typically, analogue data are used. However, for each geobody type there is a large range of possible sandstone body dimensions based on published literature. The largest-scale sand bodies, with most significance as reservoir targets, have possible interpretations as either incised valleys or amalgamated channel belts, based on their thickness ranges alone. This poses significant uncertainty for understanding the evolution of the depositional system and input into predictive reservoir models.This study emphasizes the importance of understanding the range of uncertainty of interpretation and the need for refined analogue data to better constrain reservoir element dimensions when relying solely on well-log datasets. Where seismic attribute analysis from high-quality 3D seismic data are available, W:T dimensions for reservoir elements can be constrained more accurately and correlated to core and log data. The existing global database is limited, often poorly constrained due to the use of variable terminology and potential for misinterpretation. Many studies lack statistical rigour. We conclude that further high-resolution studies are required to build more robust and quantitative analogue datasets.
Prediction of sandstone body dimensions within paralic depositional systems is crucial for the development of predictive 3D reservoir models. Continental-scale paralic reservoir targets have complex architectures, with interpretation often further compounded because they are often located at subsurface depths ≥2 km in pre- and synrift basinal settings, typified by poor seismic resolution. As such, in many cases analysis relies on core and wireline-log data, from which depositional facies are interpreted and thicknesses of sandstone reservoir units measured. Estimation of width:thickness (W:T) ratios for different reservoir elements relies on analogue data. However, the inherent uncertainty in the initial interpretation of core/log data and the wide W:T ranges for different sandstone bodies within published analogue datasets hinders prediction of accurate reservoir geometry/dimensions. Without access to quality seismic data, constraining the evolution and dimensions of reservoirs in these depositional systems is challenging.This paper presents a detailed case study of the Triassic Mungaroo Formation, and assesses the uncertainty and limitation of interpretations that can be made about reservoir architecture and the evolution of a paralic depositional system, if only wireline and core data are available.The Mungaroo Formation is characterized by upper and lower delta-plain channel sandstones, swamps and restricted embayments, through to delta-front and pro-delta heterolithics. Core-to-wireline-log calibration allowed identification of key marine intervals that enabled well correlations to be established across the study area, based on candidate flooding surfaces. Applying classic sequence stratigraphic models to low gradient fluvio-deltaic systems is difficult, due to a lack of preservation and/or confident identification of laterally continuous chronostratigraphic markers. The large-scale temporal change in reservoir architecture was likely to have been controlled by eustatic sea level causing overall transgression of the depositional system. However, the observed complex spatial facies variability is most likely controlled by climatic-induced changes in sediment supply/fluvial discharge and autocyclic processes.Four classes of sandstone bodies/reservoir elements have been identified from core and wireline data based on their thickness distributions. Whereas core to wireline to seismic calibration has enabled large-, medium- and small-scale geobodies to be identified representing fluvial channel belt complexes; multistorey channel belts; and single-storey channel belts, respectively. To predict channel body widths and sinuosity from thickness data extracted from wells, typically, analogue data are used. However, for each geobody type there is a large range of possible sandstone body dimensions based on published literature. The largest-scale sand bodies, with most significance as reservoir targets, have possible interpretations as either incised valleys or amalgamated channel belts, based on their thickness ranges alone. This poses significant uncertainty for understanding the evolution of the depositional system and input into predictive reservoir models.This study emphasizes the importance of understanding the range of uncertainty of interpretation and the need for refined analogue data to better constrain reservoir element dimensions when relying solely on well-log datasets. Where seismic attribute analysis from high-quality 3D seismic data are available, W:T dimensions for reservoir elements can be constrained more accurately and correlated to core and log data. The existing global database is limited, often poorly constrained due to the use of variable terminology and potential for misinterpretation. Many studies lack statistical rigour. We conclude that further high-resolution studies are required to build more robust and quantitative analogue datasets.
Feasibility analysis for time-lapse seafloor gravity monitoring of producing gas fields in the Northern Carnarvon Basin, offshore Australia
Highly accurate seafloor gravity data can detect small density changes in subsurface hydrocarbon reservoirs by precisely repositioning the gravimeters on the seafloor. In producing gas fields, these small density changes are primarily caused by production-related changes to the pressure and gas/fluid saturations in the reservoir pore space. Knowledge of the pressure and saturation changes is vital to optimize the gas recovery, especially in offshore environments in which wells are expensive and sparse. We assessed the feasibility of time-lapse seafloor gravity monitoring for the giant gas fields in Australia’s premier hydrocarbon province, the Northern Carnarvon Basin. We determined that gravity monitoring is more feasible for reservoirs with a large areal extent and/or shallow burial depths, with high porosities and high net-to-gross sand ratios. Forward modeling of the gravity responses using simple equivalent geometry shapes and full 3D complex heterogeneous models predicted that density changes in several of these producing gas reservoirs will result in readily detectable gravity signals ([Formula: see text]) within just a year or so of gas production. In a pure water-drive production regime, this gravity response equated to a fieldwide change in the gas-water contact height of approximately 2–3 m, or in a pure depletion-drive regime, a pressure decline equated to approximately 3–4 MPa (435–580 psi). We assessed the feasibility of time-lapse seafloor gravity monitoring for producing gas reservoirs that is flexible and practical, and it may be useful for a wide range of subsurface fluid-flow monitoring applications.
The Walloon Coal Measure (WCM) in the Surat Basin in Australia consists of coal-rich mire and a fine-grained meandering fluvial system. The main gas producing targets of WCM are numerous thin coal plies within six coal members with frequent pinching outs, splitting and merging. The geology is stratigraphically complex making correlations of individual coal plies difficult. Consequently, previous geological studies have been mostly based on coal members instead of individual coal plies resulting in inadequate description of the heterogeneity of the coal deposit. To remedy this situation, we proposed a workflow using high-resolution sequence stratigraphy to build an isochronic stratigraphy framework of sublayers and coal plies by utilizing all available data from cores and logs. The key methodology was to identify single fining-upwards cycles with coal, clay or siltstone at the top and sandstone at the base. Then similarity analysis on the cycles was used to identify aggradation, progradation or retrogradation of fluvial facies sequence between adjacent wells. Log density cutoff was used to identify coal, shaly coal, shale, sandstone and siltstone from the whole Walloon fluvial system. Reservoir parameters including gas, ash, moisture content, density, and permeability versus depth were correlated taking into consideration depth shift, regional core data and lithology in different members. All of the above were integrated into a ply-based geomodel which was used to identify highly concentrated, overlapping, continuous plies that are potential sweet pots for field development. Our intent is to provide analogue information and understanding for the coal seam distribution in the green field development of the Surat Basin. This methodology was applied to WCM to perform division and correlation of 20 sub-layers and 125 single plies with thickness ranging from 0.3–1.4 m. Coal distribution area versus thickness relationship was generated to analyze the variogram range used for some key properties, especially density and net-to-gross, and to investigate the impact of coal continuity on well spacing. Five micro-facies in fluvial system were used to describe the distribution of coal properties, impact of coal architecture and heterogeneity. Several potential sweet spots for field development were identified. With proper upscaling, this high-resolution ply-based model can be used in reservoir simulation to forecast production and calculate estimated ultimate recovery (EUR). This methodology has been applied to three coalbed methane (CBM) fields in the Surat Basin in Australia. It is novel in applying high-resolution sequence stratigraphy used in geomodel building of convention oil and gas reservoirs to CBM characterization. It has resulted in a better understanding of the complex depositional character of the WCM and consequently more accurate determination of potential sweet spots, production forecast and EUR calculation.
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