Improved Interpretation of Reservoir Architecture and Fluid Contacts Through the Integration of Downhole Fluid Analysis With Geochemical and Mud Gas Analyses (original) (raw)
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Identification of Fluid Contacts by using Formation Pressure Data and Geophysical Well Logs
Proceedings of 19th International Multidisciplinary Scientific GeoConference SGEM 2019 (ISBN 978-619-7408-77-5, ISSN 1314-2704), 2019
The identification of fluid contacts (gas–water contact—GWC, oil–water contact—OWC and gas–oil contact—GOC) is essential for field reserve estimates and field development and, also, for detailed formation evaluation. For the accurate calculation of some petrophysical parameters, such as porosity, the reservoir interval has to be zoned by fluid type, to account for differences in fluid saturations and fluid properties (e.g., hydrogen index, density, sonic transit time) in the various intervals: gas cap, oil column and aquifer zone. The fluid contacts may vary over a reservoir either because of faults, semipermeable barriers, rock quality variations / reservoir heterogeneity, hydrocarbon-filling history or a hydrodynamic activity. Horizontal contacts are typically taken into consideration, although irregular or tilted contacts occur in some reservoirs. The methods used for determining the fluid contacts include fluid sampling, water and hydrocarbons saturation estimation from geophysical well logs, analyses of conventional or sidewall cores, and formation pressure measurements. The pressure profiles obtained with various formation testing tools over reservoir intervals are, frequently, the primary source of data for defining the fluid contacts. When good quality pressure data can be collected, the fluid contacts can be determined by identifying the depths at which the pressure gradients (pressure versus depth trends) change. This study addresses some issues related to the identification of GWC for two gas fields of Early Pliocene age (Dacian stage), belonging to the biogenic hydrocarbon system of western Black Sea basin-Romanian continental shelf. We show that the identification of these contacts based exclusively on pressure gradients analysis is uncertain or may be inaccurate. The pressure gradients approach should be checked against the results of the conventional interpretation of geophysical well logs (e.g. changes in the computed fluid saturations as a function of depth) and, if available, the results of nuclear magnetic resonance (NMR) log investigations, which are able to indicate the intervals with clay-bound water, capillary-bound water and movable fluids.
Understanding complex vanatlOns in pore geometry within different lithofacies is the key to improved reservoir description and exploitation. Core data provide information on various depositional and diagenetic controls on pore geometry. Variations in pore geometrical attributes in turn, define the existence ofdistinct zones (hydraulic units) with similar fluid-flow characteristics. Classic discrimination of rock types has been based on subjective geological observations and on empirical relationships between the log of permeability versus porosity. However, for any porosity within a given rock type, permeability can vary by several orders of magnitude, which indicates the existence of several flow units.
Understanding complex varcatlOns in pore geometry within different lithofacies is the key to improved reservoir description and exploitation. Core data provide information on various depositional and diagenetic controls on pore geometry, Variations in pore geometrical attributes in turn. define the existence ofdistinct zones (hydraulic units) with similar fluid-flow characteristics. Classic discrimination of rock types has been based on subjective geological observations and on empirical relationships bern'een the log of permeability versus porosity. However, for any porosity within a given rock type. permeability can vary by several orders of magnitude. which indicates the existence of several flow units.
SPE Production and Operations Symposium, 2013
A technique using interwell connectivity is proposed to characterize complex reservoir systems and provide highly detailed information about permeability trends, channels, and barriers in a reservoir. The technique, which uses constrained multivariate linear regression analysis and pseudosteady-state solutions of pressure distribution in a closed system, requires a system of signal wells and response wells. Signal wells and response wells can be either producers or injectors. The response well can also be either flowing or shut in. In this study, for consistency, waterflood systems are used in which the signal wells are injectors and the response wells are producers. Different borehole conditions, such as hydraulically fractured vertical wells, horizontal wells, and mixed borehole conditions, are considered. Multivariate linear regression analysis was used to determine interwell connectivity coeffients from bottomhole pressure data. Pseudosteady-state solutions for a vertical well, ...
2004
This report summarizes the work carried out during the period of September 29, 2000 to January 15, 2004 under DOE Research Contract No. DE-FC26-00BC15308. High temperatures and reactive fluids in sedimentary basins dictate that interplay and feedback between mechanical and geochemical processes significantly influence evolving rock and fracture properties. Not only does diagenetic mineralization fill in once open fractures either partially or completely, it modifies the rock mechanics properties that can control the mechanical aperture of natural fractures. In this study, we have evolved an integrated methodology of fractured reservoir characterization and we have demonstrated how it can be incorporated into fluid flow simulation. The research encompassed a wide range of work from geological characterization methods to rock mechanics analysis to reservoir simulation. With regard to the characterization of mineral infilling of natural fractures, the strong interplay between diagenetic and mechanical processes is documented and shown to be of vital importance to the behavior of many types of fractured reservoirs. Although most recent literature emphasizes Earth stress orientation, cementation in fractures is likely a critically important control on porosity, fluid flow attributes, and even sensitivity to effective stress changes. The diagenetic processes of dissolution and partial cementation are key controls on the creation and distribution of open natural fractures within hydrocarbon reservoirs.