Reservoir Gas Content Research Articles

Analysis of oil and gas content in reservoirs of Savuisky-Samburgsky-Komsomolsky-Urievsky-Samotlorsky mega-cyclothem, Latitudinal Ob region

Analysis of oil and gas content in reservoirs of Savuisky-Samburgsky-Komsomolsky-Urievsky-Samotlorsky mega-cyclothem, Latitudinal Ob region

Methane Isotherms and Magnetic Resonance Imaging in Shales

Adsorption isotherms of light hydrocarbons on reservoir rocks are key data used to quantify the total gas content in reservoirs and isotherms are now being used to improve our understanding of the processes affecting subsurface gas flow associated with gas injection from Enhanced Oil Recovery techniques. This project combined elements of the traditional pressure-volume gas adsorption isotherm technique and an NMR-based adsorption isotherm approach to determine the adsorption isotherms of light hydrocarbons on to tight rocks from oil and gas reservoirs. The new approach allows isotherms to be derived from NMR data. First, a T2distribution of the gas is determined over a range of gas pressures. Next, the volume of pore gas is estimated using the pore volume of the rock and the Van der Waals gas equation. The adsorbed gas content is then calculated by subtracting pore gas content from the total gas content. This is repeated for a range of gas pressures to determine the adsorption isotherm. This project used the NMR method described above and measured the gas pressure decay in the NMR cell. This combined approach includes the advantages of the NMR method but it also produces a pressure-time curve that can be used to identify when equilibrium is attained in low permeability rocks and can be used to compare adsorption kinetics of different gases. The advantages of our approach are that 1) the samples remain intact and the measurements provide information on the pore size distribution; 2) analyses can be carried out at reservoir pressures; 3) isotherms can be measured for any gas containing hydrogen atoms; and 4) the results can be used to examine the processes controlling gas flow through the rock. Future work to develop this technique will improve our quantification of the amount of pore gas in the cell, which will improve our partitioning between adsorbed gas and pore gas as well as allow for an improved analysis of the pressure response of the sample after degassing.

The Research and Application of Bright Spot Quantitative Interpretation in Deepwater Exploration

Prospectors usually recognize the event with strong amplitude in seismic sections as bright spots. However, such a simple and rough method can’t distinguish whether these bright spots are related to favorable gas layer or water layer directly. In this paper, for the high correlation between reservoir gascontent and amplitude anomaly in research area, based on rock physical analysis of the wells drilled, using forward modeling technique respectively simulates and analyzes the seismic amplitude of gas layer and water layer. Then, combining the simulation result with corresponding statistics amplitude obtains the numerical relationship between each layer amplitude. At last, using the display technique directly recognizes the bright spots of gas layer in seismic profile and gets rid of those false bright spots caused by water layer, which improved the robustness in the bright spots interpretation and provided reliable basis for reducing exploration risks. Moreover, applying the method to the target zone, we obtain huge success.

Improved Procedures for Collection and Interpretation of Coal-Gas Reservoir Gas Content and Natural Fracture Geometry Data

The validity of quantitative coal-gas reserve analyses depends upon the accuracy of formation evaluation data used as input parameters for reservoir simulation of fluid productivity. Coal-gas reservoir deliverability is strongly influenced by gas-in-place resources, natural fracture (cleat) permeability, and gas desorption and diffusion characteristics. Estimates of these parameters are predicted upon knowledge of coal core-gas content and cleat geometry. Ironically many accepted procedures for collecting and interpreting these data are still incomplete, and therefore coal-gas reserve analyses commonly are erroneous. Improved procedures for collecting and interpreting gas content and cleat geometry data are highlighted using eight Gas Research Institute Fruitland Formation (Upper Cretaceous) wells in the San Juan basin (Colorado and New Mexico). Fruitland gas content values, in places, have been underestimated by 30-85% (786 SCF ton vs. 122 to 557 SCF/ton, dry, mineral-matter-free basis), and therefore the corresponding gas-in-place resource estimates are commensurably conservative. Gas desorption measurements must be performed at reservoir temperature: dry, mineral-matter-free normalizations and canister headspace corrections must be performed correctly; and gas composition must be periodically quantified to correctly estimate the actual methane reserves and sorption time. Collection of cleat geometry data on whole cores is routinely biased because only the most apparent cleat systemsmore » are analyzed. Detailed macroscopic and X-ray radiograph data on cleat geometry for slabbed polished blocks should be collected as a function of bed thickness, lithology, and interconnectivity to further define core-scale cleat permeability and diffusion coefficient distributions.« less