We present isotherms calculated from density functional theory for the adsorption of argon in model slit-shaped carbon pores at 77 K. The model isotherms are used to interpret experimental argon uptake measurements and to obtain the pore size distributions of several porous carbons. A similar set of density functional theory isotherms, previously reported for nitrogen adsorption on carbon slit pores at 77 K, are used to determine pore size distributions for the same set of carbons. The pore size distribution maxima, mean pore widths, and specific pore volumes measured using the two different probe gases are all found to agree to within approximately 8% on average. Some of the differences in the pore size distributions obtained from argon and nitrogen porosimetry may be attributable to quadrupolar interactions of the nitrogen molecules with functional groups on the carbon surface.

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Permeability in tight sands and shale formations is a critical property that determines well performance, completion methods and field development strategies. Obtaining reliable permeability values in these reservoirs is challenging. Ultra low permeability and very strong stratification or heterogeneity in the formations require conducting long duration tests at multiple locations in a well to obtain a complete reservoir characterization. Because of these characteristics, existing tools or methods that work well for conventional reservoirs may not deliver reliable results. The objective of this work is to develop a technique that can provide permeability and pressure estimations as well as long term reservoir monitoring in multi-layer, tight formations. An innovative reservoir monitoring and testing tool system was developed and successfully applied to a dedicated reservoir observation well in Permian basin, Texas, USA. The tool system integrates the transient pressure tests for zonal formation property estimation and the long term reservoir performance monitoring in multi-layer, tight reservoirs. The tool string consists of 11 packers that isolated 10 major producing targets in tight sands and shale formations. Volume chambers and pressure sensors were installed in the string to create pressure pulses and record their corresponding responses from the isolated wellbore intervals for estimations of zonal in-situ permeability values and formation pressures. A fit-for-purpose transient pressure solution was also developed to analyze the data whenever the existing commercial software could not handle. Permeability and formation pressures in eight out of ten zones were obtained. The estimated permeability values have a range from tens of nano-Darcy in shale formations to hundreds of Micro-Darcy in tight sand layers, demonstrating the excellent flexibility and suitability of this technology to dynamic reservoir evaluation in tight and shale formations. After the impulse test, hydraulic fracturing operations in a near-by well induced a variety of pressure responses in different isolated intervals at the monitoring well. Strong correlations were obtained among the hydraulic fracturing induced pressure jumps, the zonal permeability values and depletions that were estimated from the earlier test. The results enable us to verify the estimated zonal permeability and formation pressures, pinpoint the height of fracture growth, calibrate fracture design models, improve well/fracture placement and construct a more representative reservoir model for field development optimization.

Summary Hydraulic fractures play a central role in the performance of multistage fractured horizontal wells (MFHWs) in tight and shale reservoirs. Fracture conductivity variations and connection quality between fractures and wellbore (i.e., choking skins) strongly affect well productivity. However, convincing and high-quality evaluations of hydraulic fractures for these reservoirs are rare in literature because quantifying fracture properties requires decoupling them from fracture geometry and formation properties, a difficult task in most field conditions. A data gathering and hypothesis testing program was implemented using six multifractured horizontal wells in a pad in the Delaware Basin to improve our ability to reliably forecast well performance. A systematic approach utilizing production, shut-ins, and bottomhole pressure measurements (BHP) was conducted and used to evaluate the apparent flow capacity of hydraulic fractures. Two independent techniques were used in the data analyses to characterize the hydraulic fractures; namely, pressure transients for individual wells and significant well-to-well interference signals. Both techniques render similar decline rate interpretations for the sets of fracture conductivity/permeability from analysis of the pressure data, but there is a large difference in the uncertainty of the estimated results from these two methods. The first method used a radial/linear flow regime in successive pressure buildups in three of the six wells. Simulations and theoretical analysis show that this flow regime allows decoupling fracture conductivity from fracture geometry and matrix properties. This flow regime yields the total apparent fracture conductivity (TAFC), which represents the lump sum effect of fracture conductivity. In addition, this technique characterizes the connection condition between the dominant fractures and borehole, which can be estimated from the early derivative horizontal line in pressure transient log-log diagnostic plots with minimum assumptions. Specifically, the estimated TAFC ranges from 1,140 to 1,630 md-ft at early time of well life to 525 to 855 md-ft after 100 to 139 days in production, or about a 45 to 61% reduction among these wells. The second method uses time-lag of pulse interference responses between an active and observation well. With assumptions of low, mid, and high values of fracture porosity, fracture compressibility, and fluid viscosity, characteristic fracture permeability can be estimated. Because of the large uncertainty related to the assumed fracture porosity and fracture compressibility, the pulse interference method is not likely to deliver the same certainty range as successive pressure buildups using the radial/linear flow regime. The results of this work provide a better understanding of the mechanisms of flow transport inside hydraulic fractures and at the connection between the hydraulic fractures and wellbore. The estimated TAFC and its significant decline help improve hydraulic fracturing designs and build representative reservoir models for more reliable well performance modeling and forecasting.