Some of My Source Rocks are Now Reservoirs— The Spectrum of Fine-grained Reservoirs from ‘Shale Gas’ to ‘Shale Oil’

Q. R. Passey, K. M. Bohacs, M. Rudnicki, and L. Esch
ExxonMobil Upstream Research Company, Houston, TX
[email protected]

A spectrum of combinations of rock and hydrocarbon properties in fine-grained rocks can result in commercial production, effectively spanning ‘conventional’ tight oil to ‘shale’ reservoir matrix production. Most currently producing ‘shale’ reservoirs are mature to overmature oil-prone source rocks. Through burial and heating these reservoirs evolved from organic-matter-rich mud. Their key characteristics include: total organic carbon (TOC), thermal maturity level, mineralogy, organic matter type, geomechanical properties, and thickness. Full characterization of these formations requires integration of sample-based analyses with full well-log suites, including high-resolution density and resistivity logs, and borehole images. Porosity, fluid saturation, and permeability derived from core can be tied to log response.

Shale oil reservoirs share many attributes with shale gas reservoirs, but also have some distinct differences. Key additional dimensions include fluid properties, especially hydrocarbon density, viscosity, and phase. Over geological time, fluid density and phase control fluid saturation in the matrix, and in the short term, viscosity and phase affect flow and production rates. Hence, two main classes of attributes affect ultimate ‘shale’ reservoir performance: rock properties (mainly permeability) and fluid properties (mainly viscosity). Overall reservoir permeability includes both matrix and fracture characteristics: matrix permeability is a function of original depositional composition, texture, bedding, and stratal stacking plus burial history (thermal stress, diagenesis). Fracture permeability is a function of the same controls as matrix permeability along with structural history (mechanical stress). Fluid properties (viscosity, density) are controlled by the original depositional properties and burial/uplift history, along with present-day reservoir pressure and temperature.

The higher thermal maturities of ‘shale-gas’ reservoirs result in some contrasts with ‘shale-oil’ reservoirs: they tend to have less smectite (inter-layer water) due to illitization, but develop significant porosity associated with kerogen and bitumen. SEM images of ion-beam-milled samples reveal development of a distinct separate nanoporosity system contained within the organic matter, in some cases comprising >50% of the total porosity, and these pores tend to be hydrocarbon wet, at least during most of the thermal maturation process. A full understanding of the relation of porosity and gas content will result in development of optimized processes for hydrocarbon recovery in shale-gas reservoirs. Appreciation of the similarities and differences between ‘shale-gas’ and ‘shale-oil’ enables more efficient, effective, and economic exploitation of the full range of resource types.

AAPG Search and Discovery Article #90154©2012 AAPG Eastern Section Meeting, Cleveland, Ohio, 22-26 September 2012