Integrated Charge and Reservoir Evaluation

Ben Nevis Fault Zone Transect; East Coast Canada

Calibrated Model for Compaction & Quartz Cementation

(depending on level of participation)

Diagenetic Modeling

Fluid Inclusion Technologies, Continental Labs, the University of Aberdeen and Geocosm are conducting an evaluation of petroleum charge and reservoir quality in key wells from the Hibernia - Terra Nova area, East Coast Canada, to be offered as a non-exclusive study. The foundation for this study is fluid inclusion volatile analysis (Fluid Inclusion Stratigraphy or FIS) of 3,000-5,000 samples from 11-18 wells, representing an E-W transect in the vicinity of the Ben Nevis Fault Zone. This fault zone compartmentalizes distinctive oil types. Detailed fluid inclusion petrography, geochemistry and rock description will follow on potential reservoir sections that show significant FIS anomalies (possible migration pathways, paleo-hydrocarbon columns or present-day hydrocarbon columns). 1D basin modeling will be used to calibrate thermal histories for diagenetic modeling that will incorporate algorithms simulating the effects of compaction and quartz cementation on porosity and permeability. This model can ultimately be used to predict sandstone reservoir quality.

Classical geochemical techniques that analyze residual pore fluids are often inadequate for determining where petroleum fluids have been, and are typically hampered by contamination, fractionation and alteration issues. Subsurface fluid processes leave resolvable chemical traces in the form of crystallographically trapped fluids in diagenetic cements and healed microfractures. These fluid inclusions are not subject to evaporation during sample storage or loss of light ends during sampling from depth. They persist in the geologic record long after the parent fluids have moved on, but are continuously formed even up to the very recent past. Hence, fluid inclusion studies have the potential to provide a detailed account of petroleum distribution and charge history.

Reservoir quality is often a key risk factor in exploring for deeply buried reservoirs. Generally, compaction and quartz cementation are identified as key reservoir destroyers in these environments. Recent studies have shown that empirically calibrated process models can effectively simulate the evolution of porosity through time, particularly when sandstone composition, texture and coating materials are taken into account. These models provide the basis for reservoir quality prediction away from established control points.

Delivery date: December, 2000. Pricing: $25,000 USD before August 1; $30,000 thereafter (based on a minimum level of participation); project details subject to change.

Fax: (403) 291-9556

"An Alliance for Innovation"

sales@continental-labs.ab.ca

Web: www.fittulsa.com

Analytical Program

Terra Nova C09

North Dana I43

Cuttings and core samples from 11-18 key wells will be analyzed for their fluid inclusion volatile content with the Fluid Inclusion Stratigraphy (FIS) volatile mapping technique. The sample set represents an E-W transect in the vicinity of the Ben Nevis Fault Zone. Full-well profiles of key inorganic and C1-C13 organic species will be constructed from FIS results. These data will be interpreted in terms of petroleum inclusion presence, type and quality; possibility for deeper or lateral proximal pay; and prominent seals or reservoir compartments. FIS results and stratigraphic information will determine samples on which the following detailed analyses will be performed.

Zones within the analyzed wells that show elevated FIS hydrocarbon responses will be evaluated for their aqueous and petroleum inclusion populations via thin section analysis under plane light and UV illumination. Fluid inclusions will be characterized in terms of their relationship to the host (e.g., in cements or healed microfractures), fluorescence characteristics, origin (generated locally from intercalated source rock, or migrated into the section from a deeper kitchen) and suitability for determining quantitative information. Multiple petroleum populations will be distinguished and placed into a relative chronology.

Based on the results of the previous analyses, samples will be selected for quantitative fluid inclusion microthermometric determinations. Salinities and homogenization temperatures will be collected for aqueous inclusions. API gravity and bubble-point or dew-point temperatures will be evaluated for petroleum inclusions. Temperature data will be coupled with basin modeling information (described below) to assess timing of petroleum migration events, reservoir charging and cement formation. API gravities coupled with bubble-points or dew-points of petroleum inclusions will be combined with FIS data to evaluate hydrocarbon type and quality.

Selected samples will be analyzed with a novel fluid inclusion GC system to quantify the C1-C30+ fraction. These data will be used with results of previously described analyses to evaluate hydrocarbon type, maturity and extent of fractionation or alteration processes.

Burial-depth and temperature-history data will be constructed in selected areas using 1D basin modeling. This information will be used to place fluid inclusion temperature constraints into the context of time, allowing temporal assessment of petroleum migration, reservoir charging and significant porosity-occluding events.

Where FIS anomalies occur in potential reservoir sections, quantitative reservoir quality assessments will be performed. This will include point counting of rock constituents (framework grains and cements) and porosity. These data will be supported by selected SEM analyses (e.g., photography, elemental analysis and CL assessment of healed microfractures in quartz grains). The purpose of this step is to evaluate the potential for effective hydrocarbon reservoirs within intervals that have seen charge.

Several of the study wells will be selected for detailed petrographic characterization in order to provide calibration parameters for compaction, quartz cementation and permeability. These will be incorporated into a diagenetic model for the area that will ultimately form the basis for reservoir quality predictions away from well control.