Methodology to define hydrocarbon potential in a shale reservoir based on geochemical data and well logs
The office U.S. Energy Information Administration (EIA) has suggested significant volumes of hydrocarbon resources in unconventional Shale type reservoirs, which happens to be very interesting nowadays.
The complexity of these reservoirs, along with the high level of risk during the exploration stage, and the lack of laboratory data, are challenging for an adequate estimation of hydrocarbon volumes in shale reservoirs. An innovative methodology to estimate prospective resources on a Shale reservoir is proposed in this paper, based on petrophysical and geochemical data from well logs, such as porosity, hydrocarbon saturation, TOC (total organic content), gas content, thermal rock maturity, clay fraction, thickness, rock density, etc, all of them using Monte Carlo simulation.
Further, this paper proposes a new way of interpreting petrophysical data to obtain a clearer view of reservoir characterization, especially Brittleness, which is of great relevance to define the potential of fracturing and hydrocarbon production. The methodology was applied to the Tablazo Formation in the Middle Magdalena Valley Basin (MMVB) in Colombia. The results show a total best estimate of oil in place (OOIP) of 51 637 Bls/acre, gas adsorbed in place 39.72 Mcf/acre, and free gas in place of 177.18 MCF/acre. Comparing these results with those obtained by applying other methodologies, the best estimates of oil in place is 146 933 Bls/acre, gas adsorbed in situ 40.57 MCF/acre, and free gas in place of 504.07 Mcf/acre. Data reported in the literature, on the same area, corroborate these results.
To conclude, with this methodology a new approach is achieved for estimating prospective resources in Shale reservoirs with better results using the Monte Carlo simulation.