Engineers can now can enjoy a head start in predicting reservoir production performance.

The acorn doesn't fall far from the tree. He's a chip off the old block. The idea that one's character is directly related to one's lineage may not always hold true for humans, but in the case of hydrocarbons, the idea is providing a new way to predict reservoir fluid behavior. Within a producing province, hydrocarbon properties can be directly correlated to source rock geology and geochemical character. Given enough actual fluid property measurements and an understanding of the hydrocarbon generation history of a basin, a relative few bits of information about a specific reservoir can be converted into a reasonable estimate of that reservoir's fluid's pressure-volume-temperature (PVT) properties. Utilizing this approach, GeoMark Research and Baker Atlas have formed a joint venture to offer PVTMOD, a unique service for accurately estimating reservoir fluid PVT properties from a fluid gradient measured via wireline formation tests. Key to the success of this approach is the combination of GeoMark's geochemistry and reservoir fluid database with real-time data retrieved using Baker Atlas' Reservoir Characterization Instrument (RCISM).

An accurate understanding of reservoir fluid PVT properties forms the basis of reservoir simulations, recovery estimates, well completion and facility design decisions, pipeline flow assurance choices, production optimization strategies - practically all aspects of both a field's initial development and subsequent operation. Often, decisions on these issues must be made days or hours after a zone has been tested. Conventional PVT laboratory analysis results often can take weeks or even months to be delivered to the customer. In addition, these results are typically based on the analysis of a limited number of downhole hydrocarbon samples retrieved by wireline sampling or flow testing. In some situations, sample contamination from oil-based drilling fluids can render these results invalid. The PVTMOD service provides a real-time method for characterizing fluid properties for any reservoir interval of interest, including zones that would not typically be sampled due to well conditions or rig costs. These properties can be assessed without concern for fluid contamination, because fluid samples are not required - only formation pressure gradient and temperature information is utilized.

According to Bob Gordon, product line manager, formation testing, for Baker Atlas, the service is currently available in the Gulf of Mexico and soon will be offered in other geographic regions. "The Gulf of Mexico database is an outgrowth of a major geochemical study completed in 2000 that incorporated hundreds of PVT reports and samples from 12 contributing companies," Gordon said. "Traditional PVT correlations were tested against the data set and then improved by tuning against three primary geochemical parameters: source rock type, thermal maturity, and level of biodegradation." New PVT correlations were then built based on inputs for these three parameters, plus measurements of reservoir pressure, temperature and fluid pressure gradient.

A total of 24 different PVT variables can be determined using these correlations. Their accuracy, as compared to measured values, varies depending on the amount of nearby examples available for tuning the correlations (see table). However, GeoMark reports that values within 10% to 15% of measured are typical, with some values averaging within ± 2% to 3%.

Obviously, since the measured fluid gradient is a primary correlating factor, its accuracy is critical. This accuracy depends on formation thickness, gauge accuracy and the number of pressure measurements obtained. GeoMark reports that if an appropriate number of measurements are retrieved, in most formations the resulting fluid densities are typically within a few percent of the values measured on samples in the laboratory. Baker Atlas also offers its Formation Rate Analysis (FRA) service for validating (and if necessary, correcting) pressure points to improve gradient accuracy, as part of the RCI service capability.

PVTMOD does not replace the need for conventional fluid sampling and analysis, but the service does promise to provide an option for defining fluid PVT behavior both early (at the point in time a formation is tested) and relatively accurately. The service also provides a way to fill in missing data for zones that cannot be sampled or where sample contamination has obscured results. Because PVTMOD results are obtained in real time, they also can be used to help select fluid sampling options or locations. Baker Atlas is currently implementing new measurements, such as bubble point determination, that further refine PVTMOD results.

"GeoMark's global database now includes nearly 8,000 oil analyses and 4,000 gas analyses," reports Stephen Brown, president of GeoMark Research. "We've created a Web- based version of our PVT database for clients and we're moving all our databases - oils, gas, waxes, asphaltenes - onto the Web (www.rfdbase.com)." A similar site is now available for PVTMOD clients at www.pvtmod.com, where pending and completed PVTMOD projects are maintained in a database and kept proprietary using multiple levels of security. Clients can search the database on well location and fluid properties or by using a GIS mapping application.