Driven by field logistics in an unconventional setting, a well may undergo weeks to months of shut-in after hydraulic-fracture stimulation. In unconventional reservoirs, field experiences indicate that such shut-in episodes may improve well productivity significantly while reducing water production. Multiphase-flow mechanisms were found to explain this behavior. Aided by laboratory relative permeability and capillary pressure data, and their dependency on stress in a shale-gas reservoir, the flow-simulation model was able to reproduce the suspected water-blocking behavior. Results demonstrate that a well-resting period improves early productivity and reduces water production. The results also indicate that minimizing water invasion in the formation is crucial to avoid significant water blockage. Water-Block Description and RemediationMultiphase-Flow Mechanisms. Scanning-electron-microscope (SEM) analysis of a core sample shows that two types of pores

Some shale gas and oil wells undergo month-long shut-in times after multi-stage hydraulic fracturing well stimulation. Field data indicate that in some wells, such shut-in episodes surprisingly increase the gas and oil flow rate. In this paper, we report a numerical simulation study that supports such observations and provides a potentially viable underlying imbibition and drainage mechanism. In the simulation, the shale reservoir is represented by a triple-porosity fracture-matrix model, where the fracture forms a continuum of interconnected network created during the well simulation while the organic and non-organic matrices are embedded in the fracture continuum. The effect of matrix wettability, capillary pressure, relative permeability, and osmotic pressure, that is, chemical potential characteristics are included in the model.The simulation results indicate that the early lower flow rates are the result of obstructed fracture network due to high water saturation. This means that the injected fracturing fluid fills such fractures and blocks early gas or oil flow. Allowing time for the gravity drainage and imbibition of injected fluid in the fracture-matrix network is the key to improving the hydrocarbon flow rate during the shut-in period.

Estimating basic properties of unconventional shale reservoirs—such as permeability and porosity—is critical for reservoir evaluation, formation damage prediction, hydraulic fracture design, and performance forecasting. Several techniques can be used to measure these properties. For instance, the Gas Research Institute (Luffel et al. 1993) uses crushed rock, modeling high-resolution images of micron-sized samples, pulse decay, steady-state techniques to evaluate the permeability, and gas expansion and mercury immersion for porosity of a shale sample. However, the accuracy and reliability of these techniques are not well-established for unconventional reservoir rocks because of concerns about the flow regime, the absence of net confining stress, the sample size, and the imaging technique resolution. This paper presents the results of a round robin permeability and porosity measurement performed at several commercial and research laboratories. The permeabilities of the evaluated samples vary from 10 nanodarcy to 10 microdarcy, and their porosities vary from 5 to 10%. A wide range of natural and synthetic material was computed tomography (CT) scanned and microscopically examined. Selected samples were used based on their suitability for the desired range of porosity and permeability. The samples were examined before and after drying in a vacuum oven and then tested under several stress cycles. Gas permeability was measured by use of steady-state, transient pulse decay techniques and derived from mercury injection data. Porosity was measured by use of the gas expansion technique and mercury immersion. Image analysis of focused ion beam-scanning electron microscope (FIB-SEM) was also used to model permeability. Klinkenberg permeability was derived from apparent permeability by use of a range of mean pressures to examine validity of the Darcy flow regime. The results of the round robin testing of porosity and permeability indicate: Darcy flow is the predominant flow regime in shales with permeability as low as 10 nano-darcy, based on Klinkenberg characteristics and flow rate-pressure drop criteria. Permeability measurement on 10 nano-darcy to 10 micro-darcy permeability core plugs, under 400 to 5000 psi, is feasible and repeatable with a reasonable uncertainty range, at qualified commercial laboratories. Porosity data showed uncertainties in the range of ±1.0 p.u. for the natural samples. Steady-state method provides similar results from different laboratories, as long as an identical procedure is implemented. Uncertainty in steady-state permeability data from different laboratories could be as high as ±150%. Liquid permeability testing by use of supercritical fluid or laboratory fluid (Decalin) provides a complementary and valuable piece of datum. Rotary sidewall core plugs may provide higher quality core standards for shale material testing because the core plugging takes place under reservoir temperature and stress conditions.

Driven by field logistics in an unconventional setting, a well may undergo weeks to months of shut-in following hydraulicfracture stimulation. In unconventional reservoirs, field experiences indicate that such shut-in episodes may improve well productivity significantly while reducing water production. Multiphase flow mechanisms were found to explain this behavior. Aided by laboratory relative-permeability, capillary pressure data, and their dependency to stress in a shale-gas reservoir, the flow-simulation model was able to reproduce the suspected water blocking behavior. Results demonstrate that a well resting period improves early productivity while reducing water production. The results also indicate that minimizing water invasion in the formation is crucial to avoid significant water blockage.

It is common in unconventional plays to have offset wells with very different productivity, even though these wells were drilled at the same time, in the same landing zone and with the same completion design. Such well behaviour is always puzzling because subsurface properties are not expected to vary significantly at a small scale. This problem has been identified in several pads in the Utica play. To try to understand this phenomena, a geological and statistical analysis has been performed on more than 400 wells and 7000 stages. The results show that differences between offset wells occur mainly when the two wells have their stages placed in slightly different facies. More precisely, we show that within a 40 feet thick landing zone, stages can be placed in 3 types of facies: (a.) facies A with a gamma-ray (GR) of ~70°API (~40% Vclay), (b.) facies B with a GR of ~60°API (~20% Vclay) and (c.) Facies C with a GR of ~50°API (~5% Vclay). Generally, for a given well, if more than 50% of its stages are in facies A, the production is 15% lower than a well with no stages in facies A. Analysis of pressure data from completion indicate that the productivity decrease originates from limited fractures propagations when the completion is initiated in the clay-rich facies. Stages completed in facies A show a high near well-bore pressure loss and a low net pressure, which is consistent with the notion of shale choke, where fracture propagation is limited to the near well-bore. On the contrary, stages placed in the brittle facies C show high net pressures and low near well bore pressure losses, consistent with well- developed fracture geometry in the far-field. This difference in hydraulic fracture geometry could explain the difference in production between two neighboring wells. Such results are important because it shows that stage placement is critical to productivity, even when the well has been accurately geosteered in the target zone. Optimizing the completion design by accounting for the heterogeneities should therefore significantly improve productivity and guide operation strategy.