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Abstract An integrated reservoir study represents the one reservoir modeling technique available to a reservoir management team that incorporates ALL of the information available regarding a petroleum reservoir. As such, the integrated study has the potential to provide the team with the highest resolution most accurate description of their field that is currently available. However, that high resolution comes at the expense of a highly complex, data intensive process. This paper was an attempt to simplify and codify the complex process of performing an integrated reservoir study. The paper presents an overview of the integrated reservoir modeling process including how that process has changed from the early days of reservoir simulation to the present day. Two models are presented that illustrate the study process for a 1980 time frame multi reservoir study and a 2002 time frame geostatistically based compositional reservoir model. Emphasis is placed on the changes in workflows from the early models โ simple mapping of properties and manual digitization of maps to simulation model grids โ to the more complex models of today โ with property distributions based on object modeling and geostatistical analysis to distribute reservoir properties. Through the examples, the paper illustrates the point that reservoir studies have evolved from a time when the geologists and engineers often knew more about their reservoirs than the available modeling tools would allow them to implement in their models - dual porosity and flow across faults, for example - to the point where today we often have the modeling capability to model more complex phenomena than our knowledge of the reservoir may warrant - for example, object modeling with no data on the characteristics of lithofacies in our reservoir, or dual porosity flow models with no data on fracture spacing and distribution. The Integrated Study Conceptually Although the term "Integrated Study" only gained widespread use in the 1990's , the conceptual tasks needed to build a model of a reservoir have been identified and performed since the advent of multi-well full field simulation studies. Those tasks โ structural interpretation, petrophysical analysis, stratigraphic analysis, fluid PVT analysis, and reservoir simulation - have formed the basis for building models since the 1970's and continue today to be the backbone of the "Integrated Study" concept. What has changed in the Integrated Study concept is:The switch from the analog to digital form for the data input and analysis results of the "geo-science" tasks of the studies The development of ever more mechanistically sophisticated analysis tools, for exampleObject modeling in facies identification work Geostatistical methods in distributing petrophysical properties inter-well, Arbitrary connections in simulators to allow modeling of faults and fractures Many orders of magnitude faster computers and greater data storage capacity As a result of the sophisticated tools and greater computing capacity, the focal point of all of the model building process has moved from the reservoir simulation "dynamic" model in the integrated study concept of the 1980's, Figure 1, to the geologic "static" model today. This movement of the focal point is, we believe, a major reason for the greater interaction between the disciplines and tasks that is the emphasis of the 2003 integrated study concept, Figure 2.
- North America > United States > Texas (0.93)
- Europe (0.68)
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Stratigraphy (1.00)
- Geology > Sedimentary Geology > Depositional Environment (0.94)
- Geophysics > Seismic Surveying > Seismic Interpretation (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Digital Core Laboratory: Properties of reservoir core derived from 3D images
Knackstedt, M.A. (Australian National U., U. of New South Wales) | Arns, C.H. (Australian National U.) | Limaye, A. (Australian National U.) | Sakellariou, A. (Australian National U.) | Senden, T.J. (Australian National U.) | Sheppard, A.P. (Australian National U.) | Sok, R.M. (Australian National U., U. of New South Wales) | Pinczewski, W.V. (U. of New South Wales) | Bunn, G.F. (BHP Billiton Petroleum)
Abstract A facility for digital imaging, visualizing and calculation of reservoir rock properties in three dimensions (3D) is described. The facility includes a high resolution X-ray micro-computed tomography system capable of acquiring 3D images made up of 2000 voxels on core plugs up to 5 cm diameter with resolutions down to 2 ฮผm. Subsets of four sandstone reservoir core plugs (5 mm in diameter) from a single well of a producing gas field are imaged in this study. The four cores exhibit a broad range of pore and grain sizes, porosity, permeability and mineralogy. Computational results made directly on the digitized tomographic images are presented for the pore size distribution, permeability, formation factor, NMR response and drainage capillary pressure. We show that data across a range of porosity can be computed from the suite of 5 mm plugs. Computations of permeability, formation factor and drainage capillary pressure are compared to data from a comprehensive SCAL laboratory study on 70 cores from the same well. The results are in good agreement. Empirical correlations between permeability and other petrophysical parameters are made and compared to common correlations. The results demonstrate the potential to predict petrophysical properties from core material not suited for laboratory testing (e.g., drill cuttings, sidewall core or damaged core) and the feasibility of combining digitized images with numerical calculations to predict properties and derive correlations for individual reservoir rock lithologies. Introduction The petroleum industry is increasingly reliant on more effective reservoir characterization to reduce the risks associated with new field development, better delineate producing fields and identify new reserves. The primary tools for reservoir characterization are wellbore logging and limited core derived laboratory measurements for calibrating field logs and establishing relationships between log responses and the petrophysical properties of interest. These relationships are necessarily empirical and introduce considerable uncertainty in the interpretation of logging measurements and in the resulting reservoir description. A major source of the uncertainty is related to the present inability to effectively characterize complex rock microstructure at the pore scale. A significant reduction in the level of uncertainty requires the development of techniques to accurately characterize rock microstructure and to relate this information to measured petrophysical properties.
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.48)
Abstract To date eight gas/condensate fields have been discovered through exploration and appraisal drilling by Carigali Triton Operating Company Sdn. Bhd., Operator of Block A-18, JDA on behalf of its Shareholders Petronas Carigali (JDA) Sdn. Bhd., Triton Oil Company of Thailand (JDA) Ltd., and Triton Oil Company of Thailand Inc., Contractors to the Malaysia-Thailand Joint Authority (MT JA). Sequences 0-II of these fields include stacked shaly sand' reservoirs containing low contrast pay. The suppressed resistivities of these reservoirs are caused by cm-dm clay distributions, which vary between facies, making the identification and quantification of reserves difficult. An integrated petrophysical approach has been adopted to overcome these difficulties. Borehole image-log interpreted facies are treated as classes of clay distribution, and the log responses of each facies are calibrated to core data, acquired separately for each facies. Saturation-height functions are used with wireline formation pressures to project initial conditions capillary pressure saturations into all cored intervals, providing foot by foot log independent gas volumes. For each facies, the log data and Waxman Smits equation are calibrated to these gas volumes through the saturation exponent (n *) The role of n* as a core-log matching parameter is analogous to apparent fluid density in a core-log porosity evaluation. In addition, gamma ray is used to optimize n* for each facies. Results are supported by the fluid mobility seen on limited magnetic resonance logs, and all other available data. The technique provides a simple, reliable and inexpensive means to evaluate the hydrocarbon potential of low contrast pay. The determination of formation water resistivity (Rw) is circumvented and data acquisition costs are minimal as the required data has often been acquired for other purposes. In this case study its application will result in a gas reserves up-grade for CTOC, its Shareholders and the Malaysia-Thailand Joint Authority. P. 327
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Borehole Seismic Surveying (0.34)