From Oil-Prone Source Rock to Gas-Producing Shale Reservoir – Geologic and Petrophysical Characterization of Unconventional Shale-Gas Reservoirs

Abstract

Many currently producing shale-gas reservoirs are overmature oil-prone source rocks. Through burial and heating these reservoirs evolve from organic-matter-rich mud deposited in marine, lacustrine, or swamp environments. Key characterization parameters are: total organic carbon (TOC), maturity level (vitrinite reflectance), mineralogy, thickness, and organic matter type. Hydrogen-to-carbon (HI) and oxygen-to-carbon (OI) ratios are used to classify organic matter that ranges from oil-prone algal and herbaceous to gas-prone woody/coaly material. Although organic-matter-rich intervals can be hundreds of meters thick, vertical variability in TOC is high (<1–3 meters) and is controlled by stratigraphic and biotic factors. In general, the fundamental geologic building block of shale-gas reservoirs is the parasequence, and commonly 10's to 100's of parasequences comprise the organic-rich formation whose lateral continuity can be estimated using techniques and models developed for source rocks. Typical analysis techniques for shale-gas reservoir rocks include: TOC, X-ray diffraction, adsorbed/canister gas, vitrinite reflectance, detailed core and thin-section descriptions, porosity, permeability, fluid saturation, and optical and electron microscopy. These sample-based results are combined with full well-log suites, including high resolution density and resistivity logs and borehole images, to fully characterize these formations. Porosity, fluid saturation, and permeability derived from core can be tied to log response; however, several studies have shown that the results obtained from different core analysis laboratories can vary significantly, reflecting differences in analytical technique, differences in definitions of fundamental rock and fluid properties, or the millimeter-scale variability common in mudstones that make it problematic to select multiple samples with identical attributes. Porosity determination in shale-gas mudstones is complicated by very small pore sizes and, thus, large surface area (and associated surface water); moreover, smectitic clays that are commonly present in mud have interlayer water, but this clay family tends to be minimized in high maturity formations due to illitization. Finally, SEM images of ion-beam-milled samples reveal a separate nano-porosity system contained within the organic matter, possibly comprising >50% of the total porosity, and these pores may 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.

Shale Gas Characterization of Sembar Formation, Khipro Area, Pakistan

“…The presence of low density grain (kerogen) organic matter, the density log response at organic rich source interval gives the low value. The normal average value of density in mixture of clay minerals is about 2.7 g/cm 3 . Thus the overall organic rich shale bulk density marked the effect on density log as low value.…”

“…The studies carry out to identify the zone of organic rich shale from non-source shale and to estimate TOC of Sember Formation in area under study, using methodology based on sonic and density log with the combination of resistivity Passive method [3]. Bilal North 01 well with complete well logging data is utilized for this purpose.…”

“…Kerogen is the insoluble fraction of organic matter which usually constitutes 80% to 90% organic content. Vitrinite reflectance is a key parameter that indicates the maturity of organic material to calibrate the thermal and burial history models (Figure 3) [3]. …”

“…where μ is shear modulus, ρ is density g/cm 3 , K is bulk modulus, E is Young's modulus and σ is Poisson's ratio. Kerogen content has a significant impact on the seismic properties of organic-rich shale as kerogen is the main source of TOC.…”

“…where C k = 0.7 -0.85 depending on maturity level; ϕ = porosity; ρ b = bulk density; ρ f = fluid density is 0.8 g/cm 3 for oil shale and 0.5 g/cm 3 for gas shale; ρ k = kerogen density vary from 1.2 -1.4 g/cm 3 depending on maturity. The volume of kerogen of study wells is calculated from above equation.…”