Mapping The Downdip Limit Of Hydrocarbon Reservoirs: An Integrated Approach
Authors: Neff D.B. 
Published: October 2008

The downdip limits of a hydrocarbon reservoir can be better estimated when petrophysical and seismic amplitude data are correlated through forward seismic modeling. Knowledge of diagenetic and depositional processes are also essential to the integration scheme. In the course of mapping hydrocarbon reservoirs in both carbonate and clastic environments worldwide, a methodology was developed that provides better insights into the seismic expression of the petrophysical and fluid properties in the downdip regions of hydrocarbon reservoirs.

PROBLEM STATEMENT

Defining the downdip limit of a hydrocarbon reservoir is an exploration and development problem with significant economic ramifications. The disciplines of Geology, Engineering, and Geophysics have established procedures for predicting hydrocarbon/fluid contacts and free-water levels. Geologists use wireline logs and petrophysical analysis to determine hydrocarbon saturation levels. Engineers estimate capillary pore pressure trends to predict free-water levels and geophysicists rely on seismic "flat spots" and amplitude trends to estimate a reservoir's areal extent. In our studies of hydrocarbon reservoirs, several situations occurred which required integration and reconciliation of all three disciplines data because taken singularly, none of the techniques was able to adequately predict the fieldwide hydrocarbon limits. This integrated methodology is described and illustrated hereafter for both carbonate and clastic reservoirs.

CROSSPLOT ANALYSIS

Petrophysical analysis of reservoir formations is a primary component of this integrated process. We use measured values of water saturation and porosity through the reservoir interval, plus adjacent water-wet formations, crossplotted. Figs. 1 and 3(available in full paper) show subsea depth and/or seismic two-way time on the Y-axis versus water saturation on the X-axis. Crossplot symbols (Z-axis) are indicative of the formations effective porosity and can be used to estimate capillary pore pressure trends for a reservoir interval (line a-b-c).

Fig. 2(available in full paper) shows the same data crossplotted in the format of porosity (Y-axis) versus water saturation (X-axis) with subsea depth as the Z-axis variable. The format of Fig. 1(available in full paper) is used to extrapolate isoporosity trend lines to predict the depth of 100% water saturation and thereby determine the downdip limit of the hydrocarbon/fluid contact. This technique is particularly critical in exploration or appraisal drilling when wells do not encounter a hydrocarbon/fluid contact. The crossplot format of Fig. 2(available in full paper) provides insights as to whether the reservoir has been diagenetically altered by the presence of hydrocarbon. Fig. 2 also gives a numerical relationship between porosity and water saturation that is used in seismic modeling and reservoir mapping.

The value of the petrophysical data crossplot is best illustrated by comparing and contrasting a clastic, gas/condensate reservoir from the Gulf of Mexico (Fig. 5) to a chalk, oil reservoir from the North Sea (Fig. 6). The crossplot of Figs. 2 and 4 reveal two significant differences in these reservoirs, namely:The clastic reservoir of Well A was not diagenetically affected by the presence of hydrocarbon whereas porosity preservation in the chalk reservoir of Well B was strongly dependent on the presence of hydrocarbon.