Dear Colleagues:

There is a contradiction between the positions taken by the AAPG and the SPE on the need for the routine use of property cutoffs in reservoir modeling.

The SPE tacitly supports an approach to model building that eliminates hydrocarbons initially in-place in rock of low permeability, where little or no flow is expected to occur. This implied backing derives mainly from refereeing and publishing the work of Worthington and Cosentino (2005), and Worthington (2008 and 2010). In fact, the SPE (2011) publishes PRMS (Petroleum Resources Management System) guidelines that explicitly call for the use of cutoffs, as follows:

"Typically, information on regional and local geology are (is) used to construct net-to-gross (NTG) maps (obtained from the nearby analogue reservoirs after applying parameter cutoffs to exclude portions of the reservoir that do not meet the minimum criteria to support production), and integrated with gross reservoir volume to yield net pay maps,"

and Board Members of the AAPG explicitly sanction the PRMS guidelines. This endorsement notwithstanding, a different slant is promoted by on-line websites of earth scientists - one in which models are built using estimates of total hydrocarbons in-place. The AAPG WIKI (2016) states that OOIP and GIIP, "refer to the total volume of hydrocarbon stored in a reservoir prior to production." The E&P Geology (2014) website is a "free on-line community that aims to bring petroleum professionals and geologists together and share valuable knowledge." The following is a quotation from their website:

"N/G cutoffs seem to come from an era when hydrocarbon accumulations were mainly calculated through map-based techniques either on paper or on simple workstations. With 3D reservoir modeling, the need for making a specific N/G property to cut out bad porosity and low HC saturation seems a little unnecessary. The low porosity and low HC-saturation cells simply add little extra hydrocarbon volume."

These websites have had tens of thousands of 'hits', thus widely promoting a changed approach to model building. An overly optimistic view of pore space connectivity and recovery factor results when reservoir models for dynamic simulation are built using the total hydrocarbon methodology. When this occurs, estimates of ultimate recovery factor will seldom be achievable due to an inability to produce noncontributing hydrocarbon volumes stored in non-reservoir rock. The difference between what's called "Net Reservoir" and "Net Rock" is at the heart of the matter.

The oil industry has gradually moved from the use of "Net Reservoir" to "Net Rock" during the last 25 years. It’s alleged the result has been a fall in production attainment (production planned at project sanction) and a systematic inflation of reserves. The story is told in "Too Much by Half: the Coming Cut in Proved Oil Reserves," and Reservoir Modeling: Pitfalls in Practice and Projects Gone Wrong,” books available on Amazon.

NET RESERVOIR VOLUME

The term "Net Reservoir Volume" has been used by reservoir and petroleum engineers for decades. Its use in reservoir modeling allows recovery efficiency to be evaluated meaningfully by dividing producible hydrocarbons by an initial volume of hydrocarbons held in rock that is capable of both storing and flowing reservoir fluids.

NET ROCK VOLUME

A different approach to model building began during the dominion of earth science, starting in the mid-1990s and replacing the routine, earlier use of "Net Reservoir Volume." The term "Net Rock Volume" was introduced to describe the proportion of the "Gross Rock Volume" (GRV) that is capable of storing hydrocarbons, without regard to the potential for fluid flow. "Net Rock Volume" includes all hydrocarbon-stained rock. It holds the highest estimate of hydrocarbons in-place, one that stores a portion of the total volume that will neither move nor support reservoir pressure, regardless of the applied recovery process.

Jim Dietrich
Member SPE & AAPG
Pasadena, CA, USA