Matrix permeability is one of the most important factors used to evaluate long-term production of hydrocarbon reservoirs. However, for shale reservoirs that have ultralow matrix permeability in the range of tens to hundreds of nanodarcies (nD), the laboratory measurement of the matrix permeability of intact (nonparticlized) samples has remained a challenge. The widely used measurement methods, such as pulse-decay and steady-state, have two primary limitations: (1) measurements take hours or even days; and (2) sample fractures that are frequently present affect the measured permeability value. In this study, a new pressure-decay permeability method is proposed for ultratight rocks to overcome these limitations. The principle of the pressure-decay experiment is that system gas pressure is higher than pore pressure of the core sample so that gas penetrates the core sample and permeability is derived from the decrease of system gas pressure. In order to validate the proposed pressure-decay technique, experiments were conducted on a set of different types of rocks including a Marcellus shale plug, a set of Eagle Ford shale plugs, and a Marcellus shale plug with open, connected fractures. A series of comparative studies of the permeability results from pressure-decay, pulse-decay, and steady-state experiments on these core samples confirmed that the proposed pressure-decay experiment can provide accurate matrix permeability of ultratight rocks. Tests can be completed within one hour and the measurement range is from 1.0 x 10(-1) to 1.0 x 10(-6) mD. Further, the proposed method has the following advantages: (1) measured matrix permeability by the new pressure-decay method isn't affected by the open, connected fractures, whereas these fractures can make the pulse-decay and steady-state permeability results increase by three orders of magnitude; (2) the new pressure-decay experiment is approximately 10 times faster than the pulse-decay experiment and 20 times faster than the steady-state experiment; and (3) the proposed pressure-decay experiment can provide the gas-filled pore and fracture volumes during the permeability measurement, whereas pulse-decay and steady-state experiments cannot.

Tight-gas reservoirs undergo unique and often complex burial, diagenetic, structural, fluid pressure and saturation histories. Porosity alteration from compaction, cementation and grain leaching can continue after hydrocarbon charge, further complicating saturation modeling. Many reservoirs have gone through multiple cycles of drainage and imbibition, often at different stages on the diagenetic pathway to current pore-scale morphologies. The understanding of saturation distribution and state is not only desired but required for predicting reservoir performance, estimating realistic recoverable volumes, and optimizing costs for development and production.The Almond Formation is characterized by three depositional facies associations: shoreface, deltaic and fluvial-coastal plain. These groups are commonly fine grained and well sorted. The differences in pore architecture arise from differences in primary depositional fabric and rock-frame mineralogy and their subsequent diagenetic alteration; yielding predictive trends in porosity permeability space.Drainage and imbibition saturation-height models have been developed from core studies and integrated with logs to verify that reservoirs are at primary drainage and to highlight any potential imbibition due to trap tilting or leaking. Centrifuge and multicycle mercury injection data were integrated to produce composite drainage capillary pressure curves. Stressed mercury extrusion tests are commonly used for modeling water saturation through the imbibition process. These tests display no correlation with rock quality at low capillary pressures. To circumvent these problems, mercury extrusion was integrated with maximum-trapped-gas measurements obtained by countercurrent imbibition experiments.Using the resistivity-derived water saturation model as reference, the free-water level for drainage and imbibition models was optimized by matching saturation height models in reservoirs free of resistivity shoulder bed effects. The accuracy of the match in different rock qualities provided insights on the likely saturation state of reservoirs. Such observations were used to develop successful interpretations of the special distribution of free-water level, reservoir architecture, and hydrocarbon charge.

Routine core analysis techniques used on the very low permeability “tight” sandstone reservoirs in Pinedale field failed to give reliable results sufficient to design and justify field development or to calculate gas productivity and the field's original gas in place. In part these problems arose because of the complex variety and textures of the clay minerals lining the pores in the producing intervals. Early in the core evaluation program, it became apparent that mineralogy, clay composition and texture, and the rock's low porosity and permeability warranted an unconventional approach to core analysis. Thus, new core analysis protocols had to be developed and tested to provide representative, meaningful data in a timely fashion. Examination of the effects of cleaning and drying core samples led to the adoption of “fresh state” core analysis methods. Core tests were employed to provide not only thorough characterization of clay-bound water but also an understanding of how this clay-bound water affected various rock and petrophysical properties. Almost every rock property was examined by multiple techniques, including well-documented traditional core analysis methods and newly introduced technologies and methods. Triplicate core plug sampling and fresh-core screening tests expedited the test programs. Rapid and extensive clay characterization resulted from simple staged drying. Routine core water saturations were supported with corrections via filtrate tracers, mainly tritium, in some wells. Special core analyses included updated core water salinity determinations with additional fresh-state tests for electrical properties, capillary pressure, and relative permeability. Fortunately, operators in Pinedale field understood the importance of reliable core analyses and provided 21 conventional cores, each 4 in (10 cm) in diameter, totaling more than 1000 ft (300 m) in length from 10 wells distributed along the anticline. These cores were cut from 2002 to 2005 early in the development of the field using a water-based mud system. Results of the core analysis program greatly improved understanding of the field's reservoir system, and allowed for quantitative and petrophysical characterization of the reservoir rocks. Fresh-state analysis techniques provided both routine and special core data to develop log models for gas in place. Furthermore, special core analysis revealed that the formation-water salinity typically ranged from 30,000 to 40,000 mg/l NaCl, which is substantially higher than earlier estimates of about 13,000 mg/l. All else being held equal in a resistivity model, these higher salinity values very favorably impacted the estimate of the field's gas in place.

New core analysis methods are presented for R-w, formation water resistivity, and Q(v), cation exchange capacity per unit pore volume. Accurate R-w values are needed for all resistivity-based water saturation models. Representative values of the rock property Q(v) are necessary for Q(v)-based shaly sand models such as Waxman-Smits-Thomas and Dual-Water. Traditional core analysis methods for R-w, and Q(v) in shaly tight gas sands are limited and tend to be inaccurate or impractical due to the clay-bound water, extensive cementation, and very low permeability that characterize these formations. The new methods address the influence of clay-bound water on results and include its quantification by nuclear magnetic resonance techniques. They are designed to overcome the limitations and inaccuracies of the traditional methods, particularly with respect to tight gas sands, and result in practical approaches for R-w, and Q(v).Additionally, an improved and unifying equation is presented for the shaly sand parameter B, the counter-ion conductance term found in the Waxman-Smits-Thomas model. Effective use of this model includes application of representative B values for both the laboratory and reservoir environments. Standard sources of B for each environment are identified and standard values are compared to those provided from published equations. The poor and biased comparisons lead to development of a single equation with results that compare more favorably with the reservoir-environment standard and exactly with the laboratory-environment standard.