This one day course will include background material on hydrocarbon-bearing shales, methods of evaluation, and case studies of both gas and oil bearing shales. The course begins with a quick review of general information about hydrocarbon-bearing shales that will include: 1) areal distribution, 2) classification, 3) hydrocarbon resources, 4) key geological and engineering parameters, 5) a comparison of the mineralogy of an average shale to a hydrocarbon-bearing shale, 6) shale porosity and permeability, and 7) an expected shale production model. Next the log parameters [Rt, GR, ρb, ΦNls, and Pe] used for a quick log scan evaluation are presented along with the standard quick-look methods [Ro, Rwa, and Φw]. All of these quick methods are designed so that the geologist or engineer can evaluate the potential shale to determine if a more detailed log analysis is required. The parameters included in a more detailed log analysis include the determination of: 1) total organic carbon (TOCwt%), 2) effective porosity (Φe), 3) effective water saturation (Swe), 4) hydrocarbon-filled porosity (Φgas or Φoil), and 5) permeability (k in nannodarcies). There is also a section that reviews the methods that can be used to determine formation water resistivity (Rw) in shales.
The methods for determining the thermal maturity of organic shales will include: 1) vitrinite reflection (Ro), 2) coloration of spores and conodonts, and 3) determination of thermal maturity from log data [Maturity Index (MI; Zhao & others, 2007)]. The determination of thermal maturity is an important step in the analysis of an organic shale, because the level of maturity (i.e. oil or gas) determines how the log data will be analyzed. The next step is the determination of TOC(wt%) from log data. The methods outlined are Passey & others (1990), the Schmoker Equation, and uranium content from spectral gamma ray logs.
If the potential shale is a gas reservoir the next step is the determination of the adsorbed gas content (gc in SCF/ton). The two methods for determining adsorbed gas content that will be outlined are the Langmuir Isotherm and the TOC versus gc (SCF/ton) methods. A flow chart is provided to guide the geologist/engineer through the analysis. For example if the TOC(wt%) is greater than 2% the analysis should proceed to the next step the determination of: 1) volume of kerogen (Vke), 2) Volume of clay (Vcl), 3) volume of quartz (Vqtz), and total porosity (Φtotal) using the simultaneous equation method developed by Rick Lewis w/ Schlumberger.
Using the results from the simultaneous equations the total porosity (Φtotal) in corrected to effective porosity (Φe) using the volume of clay (Vcl) and the porosity of the clay (Φclay), and the effective water saturation (Swe) is calculated.
Then if the potential is a gas reservoir adsorbed gas content (gc SCF/ton) is converted to gc in SCF/Area and free OGIPscf (gas) or OOIPstb (oil) is calculated using the effective water saturation (Swe) and effective porosity (Φe). Permeability (k in nannodacies) is calculated using hydrocarbon-filled porosity (Φgas or Φoil).
There is a review of the application of non-standard well logs to the log analysis of hydrocarbon-bearing shales that includes Nuclear Magnetic Resonance (NMR) imaging logs, Geochemical logs, and SWS Multi-Frequency Polarized Dielectric Scanner. Next is a review of the Array Sonic logs, and their use in the evaluation of horizontal stresses and orientations [maximum (σHmax) and minimum (σHmin)] and fracture orientations, and the calculation of Brittleness Index.
Six case studies including the Devonian Woodford Shale [GAS], Jurassic Haysville Shale [GAS], two Permian Leonard shales [OIL], and two Permian Wolfcamp shales [OIL] are presented to illustrate the methods outlined in the course. OOIPstb or OGIPscf values in wells with GEOCHEM Log data will be compared to OOIPstb or OGIPscf determined using only a standard logging suite. At the end of this section is a list of an ideal data base (logs and core data) for hydrocarbon shale analysis.