Amoco Tulsa Technology Center, P.O. Box 3385, Tulsa, OK 74102-3385
1) Migration Detection and Migration Pathway Definition
Documentation of petroleum inclusions in basins with limited well control, reservoir-equivalent outcrop samples, or dry holes flanking untested structures successfully addresses the question of whether or not hydrocarbons have moved through targeted stratigraphic sections. Detection can be by UV-based thin section studies or bulk, destructive screening techniques (e.g., GC, MS, etc.). These observations can define the stratigraphic interval over which migration has occurred thereby allowing focusing of exploration efforts toward appropriate lithologies and allowing assessment of probable reservoir quality in these lithologies. It is necessary in these studies to address possible alternative sources of the petroleum, including (a) inherited inclusions in clastic rocks and (b) in-situ generation and entrapment of petroleum in mature source rocks (see Larese and Hall, this volume).
2) Extraction and Chemical Analysis of Petroleum from Inclusions
Recent advances have allowed meaningful organic geochemical data to be extracted from increasingly diverse sample types with fairly low inclusion abundance (see Jones et al., this volume). Biomarker analysis of liquid petroleum inclusions allows tying of oil inclusion-bearing rocks to source lithologies or produced oils, thereby placing useful constraints on migration pathways as well as allowing the distribution of the source rock kitchen, maturity at expulsion, and possibly volumetrics to be calculated. These analyses may define new play concepts by documenting unexpected source rocks and/or migration histories. Carbon isotopic ratios on dry gas inclusions can aid in distinguishing between biogenic and thermogenic sources. This, in turn, may impact exploration strategies; while the presence of biogenic gas does not necessarily affect an oil exploration focus, identification of thermogenic gas may indicate an overmature source rock. Furthermore, the distribution of biogenic gases may have quite different stratigraphic, facies and depth (temperature) controls as compared to those of thermogenic origin.
3) Timing Relationships
Relationships between hydrocarbon emplacement and porosity evolution are important for addressing risk associated with reservoir quality. Early hydrocarbon emplacement can preserve porosity in otherwise tight lithologies, while late, fracture-controlled migration of petroleum can occur through non-reservoir rocks, particularly those that have been deeply buried. Petrographic criteria can be used to evaluate these two endmember cases. Under special circumstances coupling of microthermometric data with the results of basin modeling or other geologic information can place absolute constraints on the timing of petroleum emplacement or the age of migration events.
4) Product Type and Quality
Once petroleum inclusions are identified, phase relationships observed during heating and cooling the inclusions, coupled with estimated PVT properties of petroleum fluids, can be used to evaluate risk associated with product type. In this way, dry gas, wet gas, condensate and oil can be distinguished, multiple migration episodes can be identified, and an evolution of petroleum types might be documented. Often, evidence for earlier oil migration is observed in reservoirs which currently produce gas--in these cases scenarios of in-situ cracking of oil to gas vs. displacement and deasphaltening of early oil by later gas can be addressed. In high temperature gas reservoirs with a source of dissolved sulfate, thermochemical sulfate reduction processes and the associated likelihood of sour gas reservoirs can be assessed.
5) Seal Identification and Quality
Evaluation of inclusion abundances and distributions can aid in identifying regional or local sealing intervals, as well as their effectiveness over geologic time. This is to be distinguished from instantaneous, present-day sealing capacities which are defined, for instance, by capillary entry pressures of core samples. Evidence for petroleum migration to shallow levels may indicate a lack of an effective seal and suggest loss or dispersal of migrating hydrocarbons.
6) Migration Mechanisms
The distributions of petroleum inclusions are often inconsistent with classical conceptual models of petroleum migration and suggest that thick stratigraphic intervals of rock can be exposed to laterally-migrating hydrocarbons. This, in turn, may indicate that buoyancy forces can be subordinate in controlling petroleum transport, as compared, for instance, to transient total pore pressure fluctuations, subsurface water potential gradients and/or inhomogeneously distributed capillary forces, all of which can impede or counter density driven flow.