Summary Kerogen is often considered to be fully hydrocarbon–wet in reservoir characterization. However, wettability of kerogen is not well–understood and quantified. Thermal maturation induces changes in the chemical structure of kerogen and alters its oxygen (O) and hydrogen (H) content. This process affects the surface properties of kerogen and can influence its wettability. Assumptions made regarding the wettability of kerogen affect the interpretation of borehole geophysical measurements such as electromagnetic measurements. Therefore, it is important to quantify the wettability of kerogen as a function of its thermal maturity. The objectives of this research are to experimentally quantify the wettability of kerogen at different thermal–maturity levels and to quantify the influence of chemical composition of kerogen on its wettability. To achieve these objectives, kerogen was first isolated from organic–rich mudrock samples from two different formations at different thermal–maturity levels. The extracted kerogen samples were then synthetically matured. Variations in the composition and chemical–bonding state of carbon (C) present in kerogen at different levels of natural and synthetic thermal maturity were determined using X–ray photoelectron spectroscopy (XPS). The sessile drop method was used to measure the contact angle to quantify the wettability of kerogen. We then investigated the effects of thermal maturity and chemical composition/bonding of kerogen on its wettability. Kerogen samples from two organic–rich mudrock formations (Formations A and B) were tested, and it was demonstrated experimentally that the wettability of kerogen varies with thermal maturity. Kerogen from Formation A at low thermal maturity formed a 44° air/water–contact angle and 110° air/oil–contact angle. However, at higher thermal maturities (heat treated at 650°C), the air/water–contact angle increased to 122°, and the oil droplet completely spreads on the kerogen sample. The results suggest that kerogen is oleophilic and hydrophobic at high thermal maturity and hydrophilic at low thermal maturity. The air/water–contact angles in kerogen samples were also recorded after the removal of bitumen generated during synthetic maturation of kerogen using chloroform. The air/water–contact angle was shown to increase from 44 to 90° and from 111 to 125° with an increase in thermal maturity in Formations A and B, respectively, in the absence of bitumen. Thus, kerogen becomes hydrophobic with increasing thermal maturity in both the presence and absence of bitumen. The outcomes of this study can potentially improve the formation evaluation of organic–rich mudrocks, in addition to improving our understanding of fluid–flow mechanisms in unconventional reservoirs.
Calculation of mineral and fluid volumetric concentrations from well logs is one of the most important outcomes of formation evaluation. Conventional estimation methods assume linear or quasi-linear relationships between volumetric concentrations of solid/fluid constituents and well logs. Experience shows, however, that the relationship between neutron porosity logs and mineral concentrations is generally nonlinear. More importantly, linear estimation methods do not explicitly account for shoulder-bed and/or invasion effects on well logs, nor do they account for differences in the volume of investigation of the measurements involved in the estimation. The latter deficiencies of linear estimation methods can cause appreciable errors in the calculation of porosity and hydrocarbon pore volume. We investigated three nonlinear inversion methods for assessment of volumetric concentrations of mineral and fluid constituents of rocks from multiple well logs. All three of these methods accounted for the general nonlinear relationship between well logs, mineral concentrations, and fluid saturations. The first method accounted for the combined effects of invasion and shoulder beds on well logs. The second method also accounted for shoulder-bed effects but was intended for cases where mudfiltrate invasion is negligible or radially deep. Finally, the third method was designed specifically for analysis of thick beds where mud-filtrate invasion is either negligible or radially deep. Numerical synthetic examples of application indicated that nonlinear inversion of multiple well logs is a reliable method to quantify complex mineral and fluid compositions in the presence of thin beds and invasion. Comparison of results against those obtained with conventional multimineral estimation methods confirmed the advantage of nonlinear inversion of multiple well logs in quantifying thinly bedded invaded formations with variable and complex lithology, such as those often encountered in carbonate formations.
Reliable estimates of petrophysical and compositional properties of organic shale are critical for detecting perforation zones or candidates for hydro-fracturing jobs. Current methods for in situ formation evaluation of organic shale largely rely on qualitative responses and empirical formulas. Even core measurements can be inconsistent and inaccurate when evaluating clay minerals and other grain constituents. We implement a recently introduced inversion-based method for organic-shale evaluation from conventional well logs. The objective is to estimate total porosity, total organic carbon (TOC), and volumetric/weight concentrations of mineral/fluid constituents. After detecting bed boundaries, the first step of the method is to perform separate inversion of individual well logs to estimate bed physical properties such as density, neutron migration length, electrical conductivity, photoelectric factor (PEF), and thorium, uranium , and potassium volumetric/weight concentrations. Next, a multilayer petrophysical model specific to organic shale is constructed with an initial guess obtained from conventional well-log interpretation or X-ray diffraction data; bed physical properties are calculated with the initial layer-by-layer values. Final estimates of organic shale petrophysical and compositional properties are obtained by progressively minimizing the difference between calculated and measured bed properties. A unique advantage of this method is the correction of shoulder-bed effects on well logs, which are prevalent in shale-gas plays. Another advantage is the explicit calculation of accurate well-log responses for specific petrophysical, mineral, fluid, and kerogen properties based on chemical formulas and volumetric concentrations of minerals/kerogen and fluid constituents. Examples are described of the successful application of the new organic-shale evaluation method in the Haynesville shale-gas formation. This formation includes complex solid compositions and thin beds where rapid depth variations of mineral/fluid constituents are commonplace. Comparison of estimates for total porosity, total water saturation, and TOC obtained with (a) commercial software for multimineral analysis, (b) our organic-shale evaluation method, and (c) core/X-ray diffraction measurements indicates a significant improvement in estimates of total porosity and water saturation yielded by our interpretation method. The estimated TOC is also in agreement with core laboratory measurements.
Rock typing in carbonate reservoirs is challenging due to high spatial heterogeneity and complex pore structure. In extreme cases, conventional rock typing methods such as Leverett's J-function, Winland's R 35 , and flow zone indicator are inadequate to capture the heterogeneity and complexity of carbonate petrofacies. Furthermore, these methods are based on core measurements, hence are not applicable to uncored reservoir zones. This paper introduces a new method for petrophysical rock classification in carbonate reservoirs that honors multiple well logs and emphasizes the signature of mud-filtrate invasion. The method classifies rocks based on both static and dynamic petrophysical properties. An inversion-based algorithm is implemented to simultaneously estimate mineralogy, porosity, and water saturation from well logs. We numerically simulate the process of mud-filtrate invasion in each rock type and quantify the corresponding effects on nuclear and resistivity measurements to derive invasion-induced well-log attributes, which are subsequently integrated into the rock classification. Under favorable conditions, the interpretation method advanced in this paper can distinguish bimodal from uni-modal behavior in saturation-dependent capillary pressure otherwise only possible with special core analysis. We successfully apply the new method to a mixed clastic-carbonate sequence in the Hugoton gas field, Kansas. Rock types derived with the new method are in good agreement with lithofacies described from core samples. The distribution of permeability and saturation estimated from well-log-derived rock types agrees with routine core measurements, with the corresponding uncertainty significantly reduced when compared to results obtained with conventional porosity-permeability correlations.
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