This paper addresses the problems identified in current shale reservoir characterization practices. We also provide alternative approaches with relevant reflections on the determination of volumes in-place. Rock properties in unconventional reservoirs such as shales is of paramount importance. By comparison with conventional reservoirs, fluids are present not only in the intergranular porous media but also within the fine texture of the rock matrix (Clays, Kerogen and
Micro-Fractures) which usually are only recoverable with the aid of suitable stimulation and completion technologies. This paper questions current engineering practices related with the assumption of unrealistic cut-offs in the petrophysical
analyses which in turn may result in dangerously misleading estimates of in place volumes and thus inadequate development decisions being made.
The adsorption capacity of clays has been documented with observations on the correlations between the percentages of clay minerals in the rock and Langmuir volume (VL) determined in laboratory measurements of gas content from core
samples by means of Langmuir isotherms. Therefore it should be no surprise that clays in shale gas reservoirs are known to adsorb hydrocarbon gases and may contribute to the production when properly stimulated. We therefore recommend
that corrections for clay effects should not be arbitrarily applied in the petrophysical analysis of electric logs. The use of a total porosity-total water saturation model will help to avoid shortcomings in total gas in-place determination. Additional
reasons for the avoidance of clay porosity corrections; include the fact that there are no tools capable of differentiating between free gas and adsorbed gas.
Total porosity and water saturation methods give rise to total gas content determination with the appropiate model. Adsorbed gas content estimate, may be obtained by correlating geochemical data based on gas content from laboratory experiments and rock density measured on core and or logs.
Unconventional reservoirs have burst with considerable force in oil and gas production worldwide. Shale Gas is one of them, with intense activity taking place in regions like North America. To achieve commercial production, these reservoirs should be stimulated through massive hydraulic fracturing and, frequently, through horizontal wells as a mean to enhance productivity.
In sedimentary terms, shales are fine-grained clastics rocks formed by consolidation of silts and clays. In log interpretation of conventional reservoirs, it is very common to observe that the clay parameters used to correct porosity and resistivity logs for clay effects are in fact read in shaly intervals rather than in pure clay. Although no considerable deviation have been observed in shaly sandstones, anyway these concepts and procedures must be reviewed to run log analysis in shale gas. Organic matter deposited with shales containing kerogen that matured as a result of overburden pressure and temperature, giving rise to source rocks that have yielded and expulsed hydrocarbons. Shale gas reservoir type is a source rock that has retained a portion of the hydrocarbon yielded during its geological history so that to evaluate the current hydrocarbon storage and production potential it is necessary to know the kerogen type and the level of TOC - total organic carbon - in the rock. Produced gas comes from both adsorbed gas in the organic matter and "free" gas trapped in the pores of the organic matter and in the inorganic portions of the matrix, i.e. quartz, calcite, dolomite.
In these unconventional reservoirs, gas volumes are estimated through a combination of geochemical analysis and log interpretation techniques. TOC, desorbed total gas content, adsorption isotherms, and kerogen maturity among other things can be measured in cores, sidewall samples and cuttings, in the laboratory. These data are used to estimate total desorbed gas content and adsorbed gas content which is part of the total gas. Also in laboratory, porosity, grain density, water saturation, permeability, mineral composition and elastic modules of the rock are measured. Laboratory measurement uncertainty is high and consistency between different providers appears to be low, with serious suspicions that procedures followed by different laboratories are the source of such differences. The permeability is one of the most important parameters, but at the same time, one of the most difficult to measure reliably in a shale gas. Core calibrated porosity, mineral composition, water saturation and elastic modules can be obtained through electric and radioactive logs. All these information is used to estimate log derived total gas volume which results are also subject to a high degree of uncertainty that must be overcome.
Once this key information is obtained, it is possible to estimate different gas in-situ volumes. Indeed, an estimate of porosity-resistivity based total gas in-situ and, on the other hand, geochemical based adsorbed gas in-situ can be performed. Log total gas in-situ can be, and it is advisable to do, compared with adsorbed gas estimations and also with another gas measurement called direct method - total gas desorption performed on formation samples. The difference between log total gas in-situ and adsorbed gas in situ should be the "free" gas in situ. Free gas occupies the pores of kerogen and matrix; also it can be stored in open natural fractures if such fractures are present.
We have validated with superior results that the direct measurement of porosity using Nuclear Magnetic Resonance (NMR), in Naturally Fractured Clastics Reservoirs of very low porosity (˜ 3.5%) in the Devonian of the Bolivian Sub-Andean, reveals information till now incoherent compared with core data. As it is well known, when the rock does not have paramagnetic elements, the porosity measured with the NMR is not affected by the minerals within the matrix and the tool answers mainly to the contained fluids in the pores of the rock. This peculiar characteristic of the NMR response in these low porosity reservoirs, with complex and variable lithology, become fundamentally beneficial at the time of determining an immediate porosity value with less uncertainty in comparison to the one from conventional logging tools, such as the Neutron, the Density and the Sonic, where there is a need to assume variable values of density and transit time for the matrix.
To corroborate that the obtained effective NMR porosity, is the best to be easily and truthfully correlated to true formation porosity, core data information are available. The key to obtain a reliable and precise measurement of porosity through NMR in these complex environments is based on the optimum selection of the acquisition parameters for the tool, like the polarization time, the echo-spacing and the use of a fit-for-purpose T2 cutoff time, tailored for this type of reservoirs. Furthermore, it will be demonstrated that the effects of nuclear diffusion on the transversal relaxation time distribution (T2 mode), primarily caused by gas, are not significant in these reservoirs, since an underestimate of the porosity was not noticed with regard to the one from cores.
Additionally with the aim of obtaining a better correlation among cores and NMR porosities, it has been used a specific high resolution acquisition and processing method, achieving continuous porosity measurements with a dynamic vertical resolution of 22 inches, more suitable to the sampling core interval and to the real petrophysical characteristics of our fields.
The gas-condensate reservoirs from Devonian age of the Bolivian Sub-Andean that lie between the 3000 and 5500 m of depth, have been produced by the existence of a thick column of clastics sediments of scarce to null primary intergranular porosity, but with an important development of secondary porosity for fissures and fractures taking place during the characteristic tectonics of this region. The lithology of these Devonian formations is characterized mainly by shoreface sediments; quartzitic sandstones, litharenites, micaceous, and laminated sandstones together with shaly intervals that can be found in the productive formations of the region (i.e. Huamampampa, Icla and Santa Rosa). For e-log interpretation purposes, we have classified lithology of the Devonian formations under three main petrofacies: a) quartzitic sandstones, b) micaceous and laminated sandstones and c) shaly intervals. Sandstones composition is rather complex except for the massive quartzitic sandstone bodies because quartz, volcanic lithics, mica, and minor accessory heavy minerals are present in the rock composition concurrently with thin shale-silt laminations over certain intervals.
In these formations the petrophysical analysis is affected by strong limitations in core analysis and log interpretation, due to the very low porosity and naturally fractured reservoir environment. Despite of this, the measurement of a reliable porosity with the NMR technique in these naturally fractured clastics reservoirs, has demonstrated to be a viable and reliable alternative, this means, without the necessity of assuming a fixed lithology parameters that have turned out to be variable in these kind of formation and not easy to estimate with conventional logs.
The selection of the acquisition parameters for the tool takes here an important role. For the wells showed as example in this paper, the acquisition was done with a logging speed of 700 ft/hr corresponding to a wait time of 15.8 seconds, enough for the complete polarization of the fluids near the wall of the borehole, with a number of echoes of 3000 and an echo spacing of 0,2 ms (200ms). The high resolution EPM mode (Enhanced Precision Mode) allowed the acquisition of short CPMG pulses of 30 echoes each one with a repetition of 10 times for better signal/noise ratio at fast relaxation decay. After an exhaustive LQC, the data are reprocessed to improve the overall NMR response and signal by using the CMRTM application, part of the customary GeoframeTM software platform.
Determination of water saturation (Sw) from conventional resistivity and porosity logs has proved difficult in several gas fields within Bolivia. To address this challenge, a method was developed to determine Sw profiles based on pseudo-capillary pressure curves (Pc) derived from transversal relaxation times (T2 distribution) measured by nuclear magnetic resonance (NMR) logging tools.
Some of the Bolivian sand reservoirs, producing gas and condensate with a high gas/oil ratio, are characterized by a lack of resistivity contrast above and below the oil-water contact. This problem is attributed to complex mineralogy, including thin shale laminations within sand bodies of variable petrophysical quality, and mostly to very fresh formation waters that average a salinity of 5000 ppm of total dissolved solids. Also, the lack of lateral extension of each reservoir makes cross-well correlation very difficult.
The core hypothesis of this original method is to assume that the relation between capillary pressure and pore throat sizes is similar to that between T2 values and pore-size distribution. A consistent scaling factor is used to derive a pseudo-capillary pressure from an NMR T2 distribution. After the pseudo-pressure is calibrated with capillary pressure measurements from laboratory-derived core data, it is combined with density (difference between the produced hydrocarbon and the formation water) and free-water level (FWL) information to compute Sw along the wellbore trajectory.
Even so, in general terms, resistivity-based models are still the most consistent and documented foundation in order to compute water saturation; Examples demonstrate the success of this new standalone method of uncovering unforeseen hydrocarbon in place and obtaining accurate Sw as an alternative to the standard, but dubious or inadequate, resistivity method in Bolivia where cretaceous and carboniferous rocks with intergranular porosity are found within several sedimentary basins.