The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). The TOC can be used in conjunction with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) in conjunction with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, hydrocarbon content, and mineral analysis can be assessed. This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as, total porosity and mineralogy. The data is compared to the actual core data from three Eagle Ford wells, and it will be shown how the proposed approach will eliminate some coring operations. Finally, it will be shown how these interpretation results can be rolled up to make decisions on where to drill the lateral.

Acceptable data quality for formation evaluation forms the foundation for understanding the petrophysical & reservoir properties, coal quality and properties and pay zones identification. The petrophysical logs are used in both subsurface modelling and to optimise the well completion strategy, ensuring effective coal dewatering and desorption for gas production. At the moment, the industry common practice for data acquisition is to use open-hole wireline logging tools, which were developed primarily for the oil and gas industry. These tools are designed for higher pressure and temperature specifications compared to the reservoir conditions normally seen in CSG operations. This results in heavier tools, bigger logging trucks and increased manpower requirements than seen in mining logging operations.Arrow's CBM development projects in Queensland, Australia, are designed with a large volume of wells (more than~1000 wells) that will need to be drilled and evaluated over the next ten years. At present, the cost of logging (direct wireline contractors and associated rig time cost) is forcing Arrow to choose between early data coverage (eroding project economics value) versus restricted logging (increasing project risk). In order to resolve this issue, Arrow has embarked on a series of technology trials to investigate various cost effective formation evaluation solutions, while still ensuring data quality and operational safety. This paper will present the results of a comparison (logoff) of state-of-the-art mining logging technology and conventional oil and gas logging technology. Also, the paper will focus on the miningstyle logging technology data quality, equipment footprint, tool handling, calibration procedures, limitations and general operational efficiency.

Porosity is a key reservoir property used in petrophysical evaluations. Obtaining realistic porosity estimates in unconventional reservoirs is challenging using only conventional logs. Conventional log porosity measurements are affected by the presence of kerogen in organic-rich reservoirs. Techniques such as ΔLogR can be used to predict total organic carbon (TOC) which can be converted to kerogen volume. The kerogen volume can then be used to apply corrections to conventional porosity measurements. However, these techniques require prior knowledge of thermal maturity or core measurements such as vitrinite reflectance (Ro). The predicted TOC can also be used in conjunction with geochemical elemental measurements for a more accurate assessment of formation kerogen and mineralogy, as well as for hydrocarbon volumes. Nuclear magnetic resonance (NMR) logs measure only the fluids present and represent a total porosity unaffected by solid components such as kerogen and bitumen. Recent observations in numerous unconventional resource plays indicate that NMR log porosity provides the best match to core porosity and does not require corrections for kerogen. NMR log porosity is available in real time as an input to the petrophysical model long before core measurements can be completed. The complex refractive index method (CRIM) in conjunction with mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, porosity, hydrocarbon content, and mineral analysis can be assessed. Based on previous work in the Eagle Ford Shale, a comprehensive workflow was developed for unconventional source rock reservoir interpretation. The workflow integrates conventional logs, a geochemical log, an NMR log, and a dielectric log to predict TOC, kerogen volume, mineralogy, total porosity, and hydrocarbon volume. This paper will show results from the Eagle Ford wells upon which this workflow is based. Then, we apply the workflow to the Utica-Point Pleasant Shale Play and compare those results to core measurements.

Reinvestment in, and the rejuvenation of, aging oil fields are becoming increasingly commonplace. Because the price of oil has stabilized at an equitable value and enhanced oil recovery methods have been proven, previously-depleted oil reservoirs are being revisited to determine their potential for tertiary recovery by means of CO 2 flooding. Accurate determinations of unswept oil and permeability distribution within the reservoir are critical elements in understanding and optimizing the CO 2 flood. This paper presents a pilot study in utilization of NMR logging in the redevelopment of a field that has been waterflooded since 1953.These mature reservoirs pose well-known challenges for formation evaluation. Resistivity-based saturation models are inadequate and uncertain because of previous waterfloods and variable formation water salinity (R w ) values. The variations in grain size and the onlapping of sand bodies cause uncertainty with the use of a porosity-permeability transform to estimate permeability.These challenges must be overcome for optimal well placement, infill drilling, CO 2 flood design, and other reservoir management practices. The standard logging suite for newly-drilled wells, triple combo and nuclear magnetic resonance (NMR), has evolved to address many of these challenges.This paper presents a pilot study that demonstrates the effectiveness of NMR logs for reservoir characterization. These reservoirs were evaluated for estimating formation porosity, bound and moveable fluid volumes, permeability, and remaining oil saturations. The log data were compared and calibrated with X-ray diffraction (XRD), Specialized Core Analysis (SCAL), and Capillary Pressure data from core. Pore-size distribution from NMR has been used to identify facies changes and for geomodeling purposes. Variations in the facies and the distribution of the sand bodies have been correlated to 3D seismic data. This has helped with the accurate mapping of the reservoir units to understand sweep efficiency. Production results are used to validate the log interpretations. A similar method can be used in other aging oil fields and to evaluate the development plan of a CO 2 flood.

The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). TOC can be used with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, porosity, hydrocarbon content, and mineral analysis can be assessed. This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as total porosity and mineralogy. The log data is compared to core data from three Eagle Ford wells. Based on the results from these three wells, a comprehensive workflow is developed for unconventional source rock reservoir interpretation. The workflow is then applied to two additional Eagle Ford wells and the results are compared to core data. While the workflow is demonstrated with Eagle Ford data it is believed that it will be applicable in other unconventional source rock reservoirs. It will be demonstrated how the proposed approach will help eliminate some coring operations and can be used to help make decisions on optimum lateral placement.