Summary Gas content and storage capacity are the key parameters for determination of the gas resources and reserves in unconventional reservoirs. These parameters must be obtained from laboratory experiments in core samples such as desorption canister tests and adsorption isotherm experiments. Desorption canister testing is performed to determine the total adsorbed gas content, gas composition, and the total desorption time. Adsorption isotherm experiments are conducted to determine the gas storage capacity with pressure and for CO2 sequestration purposes. Other analyses of coals include proximate analysis and bulk-density measurements of all samples. Shales are commonly analyzed for total organic carbon in lieu of proximate analysis. The gas content is estimated by placing selected freshly cut reservoir samples in airtight sealed canisters and measuring desorbed gas volume as a function of time at atmospheric conditions. Total gas content is the summation of three components: "lost gas," desorbed gas, and "residual gas." "Lost gas" is the volume of the gas that desorbs from the sample during the recovery process at the wellsite, before the core sample can be sealed in a desorption canister. "Residual gas" is the gas that remains sorbed on the sample at the completion of the canister desorption test. A disadvantage of this procedure is the estimation of "lost gas." The volume of the "lost gas" is usually estimated by extrapolation of desorbed data to time zero using linear and/or polynomial curve-fit to the plot of cumulative desorbed gas vs. square root of time. The differences between both methods can become more pronounced, especially in high-gas-content reservoirs. In this paper a new method, which is based on nonlinear regression of measured gas content, is presented. This technique offers an accurate estimation of lost gas, which, coupled with sorption isotherm, has an impact on the calculation of gas in place, the recoverable reserves, and production profiles.

The M_1 nested bimodal pore system is prevalent in many large limestone oil reservoirs in Saudi Arabia. Within this pore system is contained a large portion of these fields' oil in place. Very low initial water saturation in these large structural relief carbonate reservoirs results in oil emplaced into pores controlled by M macropore throats and also into pores controlled by much smaller Type 1 micropore throats. Approximately, seventy-five percent of the M_1 oil portion is stored in the macropore system and about 25% is stored in the Type 1 micropore system. This prevalent M_1 petrophysical rock type (PRT) is an example of nested bimodal pore system consisting of an instance from the distribution of Macro possibilities (M porositon) and an instance from the Type 1 micro porositon distribution. The maximum pore-throat diameters of the Type 1 micro porositon are on the average 53 times smaller than the M macro porositon average maximums. M porosity average is 17% with a mean maximum pore-throat diameter of 58 microns. The Type 1 microporosity average is 5.6% with a mean maximum pore-throat diameter of 1.1 microns. Thus, common in Arab-D carbonate reservoir matrix is a bimodal pore network with a very large hydraulic contrast between a fine network of well-sorted tubular Type 1 micropore throats, connected and adjacent to a network of much larger diameter moderately-sorted M macropore throats. In a previous publication by Clerke, it was shown that the very small micropore throats' contribution to the total permeability is commonly below the resolution and reproducibility of the permeability measuring device when in the presence of many much larger pore throats. The micropore network is permeable if only at a small value. For the two phase flow occurring in a waterflood for oil recovery, the M_1 PRT requires an understanding of the two phase recovery processes in each pore subsystem considering capillarity in the combined pore network. This paper demonstrates that the Type 1 micropores are themselves a permeable network to water and to both oil and water when under waterflood. Hence for our carbonate reservoirs, "pores with throat diameters less than one micron when filled with oil in a bimodal M_1 pore system contribute to oil recovery through a time dependent spontaneous imbibition process and thereby contribute to oil recovery by waterflood." Further, it is demonstrated that the multimodality porositon classification proposed by Clerke are a form of dynamic rock type that classify the position and the type of internal pore level capillarity spatial gradients that affect ultimate oil recovery. New high-precision laboratory data has been obtained at very low phase pressure: water imbibition into oil saturated M_1 pore systems at near zero phase pressures (spontaneous imbibition) and dispersion of D2O into water filled M_1 pore systems. These pore systems can now be analyzed to obtain the magnitude, direct time dependence and scaling behavior of this important and previously overlooked portion of the total carbonate oil recovery by waterflood.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractDepleted gas condensate reservoirs are becoming important targets for CO 2 sequestration.Since depleted below the dew point, retrograde condensate has been deposited in the pore system. CO 2 injection in the depleted gas condensate reservoirs may allow enhanced gas recovery by liquid re-vaporization and reservoir repressurization or pressure maintenance.The higher density of CO 2 relative to gas condensate means that CO 2 will tend to migrate downward. The larger viscosity of CO 2 ensures that displacement of hydrocarbon gas phase by CO 2 will be a displacement with a favorable mobility ratio. Furthermore, pressure diffusivity is typically several orders of magnitude larger than molecular diffusivity, making mixing by re-pressurization occur much faster than by molecular diffusion. This paper discusses an approach that relates primarily to the laboratory and modeling studies that precede compositional simulations and field pilot testing of CO 2 sequestration in depleted gas condensate reservoirs.The phase behavior of CO 2 /gas condensate system as a critical factor in determining the effectiveness of a reservoir to store CO 2 are reviewed along with its importance in building an accurate EOS model.In addition to PVT experiments, a special core flood test design to determine the micro-scale conformance of the CO 2 displacement, to identify CO 2 breakthrough characteristics at density and compositional level during liquid re-vaporization and re-pressurization process and to evaluate the recovery performance is discussed in detail.The results from experimental data can be used as a base for sensitivity case studies using a commercial compositional simulator to evaluate the feasibility of CO 2 sequestration in depleted gas/ condensate reservoirs with enhanced gas recovery component.

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A number of factors must be considered in the design of miscible displacement processes. This paper discusses a new approach that relates primarily to the laboratory and modeling studies that precede the EOS based compositional simulation of reservoir performance during the vaporizing/condensing gas drive process. The phase behavior of a solvent/oil system and determination of miscibility conditions by various special PVT experiments including swelling test, RBA, slim tube test and continuous multiple-contact experiment are reviewed along with their importance in building an accurate EOS model to be used in compositional simulation. In addition to experimental PVT data, a special core flow test design for measuring the relative permeabilities to generated fluids by forward/reverse multiple contact experiments is discussed. Based on laboratory PVT and SCAL data, a novel interfacial tension-dependent model of relative permeability and capillary pressure data is presented along with the advantages if incorporated in the commercial EOS based compositional simulation software packages.