Drill cuttings are powerful sources of information that have been used for several decades by well site petroleum geologists for qualitative evaluation of reservoir rocks. Additional cuttings work is carried subsequently in the laboratory. This includes, for example, the preparation of thin sections for petrographic work, and the evaluation of intergranular and microfracture porosity.
Drill cuttings, however, have not been used to full advantage in horizontal wells drilled through tight formation. This study proposes a method for quantitative determination of porosity, permeability and rock mechanics properties from drill cuttings collected in horizontal wells. These properties are determined through a combination of laboratory, analytical and 3D simulation work. The laboratory work includes the determination of porosity and permeability in cutting samples with sizes equal to 1 mm or larger. The results are used for determining key geomechanical properties such as Poisson's ratio and Young's modulus; and the estimation of a brittleness index. The data extracted from the previous two stages are useful in 3D hydraulic fracturing simulation for designing multi-stage hydraulic fracturing in horizontal wells
Data extracted from drill cuttings are important as the amount of information collected in horizontal wells drilled thought tight formations, including cores and well logs, is rather limited in most instances.
It is concluded that the proposed method provides a useful tool for evaluation of direct sources of information that are available in many cases (drill cuttings) but are rarely evaluated quantitatively. The proposed method allows improved design of multi stage-hydraulic fracturing jobs in horizontal wells.
Clarkson, Christopher R. (U. of Calgary) | Wood, James (EnCana Oil & Gas (USA) Inc.) | Burgis, Sinclair E. (University of Calgary) | Aquino, Samuel D. (University of Calgary) | Freeman, Melissa (University of Calgary) | Birss, Viola I.
The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize due to a wide pore size distribution, with a significant pore volume in the nanopore range. A variety of methods are typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range.
In this work, we investigate the use of non-destructive, low-pressure adsorption methods, in particular low pressure N2 adsorption analysis, to infer pore shape, and to determine pore size distributions of a tight gas/shale reservoir in Western Canada. Unlike previous studies, core plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure to be analyzed. Further, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which MICP and permeability measurements were previously made, allowing a more direct comparison with these techniques. Pore size distributions determined from two isotherm interpretation methods (BJH Theory and Density Functional Theory), are in reasonable agreement with MICP, for that portion of the pore size distribution sampled by both. The pore geometry is interpreted to be slit-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, SEM imaging and the character of measured permeability stress-dependence. Although correlations between inorganic composition and total organic carbon (TOC) and dominant pore throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore throat size and highest permeability, as estimated from MICP. The presence of stress-relief-induced microfractures, however, appears to affect lab-derived (pressure-decay and pulse-decay) estimates of permeability, even after application of confining pressure.
Based on the premise of slit-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, using dominant pore throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly over-predicted for samples that are unaffected by stress-release fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries.
In horizontal shale completions, one of the primary goals is to maximize contact with the most reservoir rock and effectively drain the complex fracture network that has been created during the stimulation process. This paper covers a five-well case study in the Marcellus Shale where completion diagnostics were used to evaluate and optimize the completion process. The case histories will detail key completion parameters and how they changed over time based on various diagnostic results.
Completion diagnostics such as proppant and fluid tracers can be integrated with production, stimulation and geologic data to provide useful information as to the effectiveness of the completion design. Proppant tracers have been utilized in horizontal shale basins throughout North America to evaluate near-wellbore fracture initiation, identify un-stimulated perforations, and evaluate proppant interference between stimulated wellbores. Fluid tracers are currently being used to analyze lateral clean-up over time and to quantify fracture fluid interference between wells.
In this case study, these diagnostic technologies were instrumental in addressing several completion design questions. Proppant tracers were used to evaluate cluster and stage spacing and also identified proppant interference with adjacent wells. Fluid tracers were utilized to evaluate overall load fluid recoveries for various wellbore trajectories and helped quantify the source and amount of interference between wells.
The Marcellus formation spans a majority of the Appalachian basin from the southern tier of New York through northeastern and western Pennsylvania, West Virginia and extends into eastern Ohio and the panhandle of Maryland. Covering roughly 44,000 square miles, the Middle Devonian age shale mudstone is 50 to 300 feet thick with an average porosity of 6%. The Marcellus is overlain by the Mahatango Shales and underlain by the Onandaga Limestone. Estimates of original gas in place have put the Marcellus Shale at 500 Tcf with approximately 50 Tcf of recoverable gas. Using technology the Marcellus Shale reserves can be maximized to provide abundant clean natural gas, lower energy costs, and create jobs for citizens in Appalachia.
Dutta, Riteja (Pennsylvania State U) | Lee, Chung-hao (Pennsylvania State U.) | Odumabo, Sijuola (Pennsylvania State U) | Ye, Peng (Pennsylvania State U.) | Walker, Stacey C. (Chevron Corp.) | Karpyn, Zuleima T. (Pennsylvania State U.) | Ayala, Luis Felipe (Pennsylvania State U.)
During hydraulic fracturing operations in low permeability formations, spontaneous imbibition of fracturing fluid into the rock matrix may be responsible for having a significant impact on the retention of water-based fracturing fluids in the neighborhood of the induced fracture. This may consequently affect the post-frac productivity of the well. However, there is lack of direct quantitative and visual evidence of the extent of retention, evolution of the resulting imbibing fluid front, and how they relate to potential productivity hindrance. In this paper, laboratory experiments have been carefully designed to represent the vicinity of a hydraulic fracture. The evolution of fracturing fluid leak-off is monitored as a function of space and time using X-ray computed tomography (CT). The X-ray CT imaging technique allows us to map saturations at controlled time intervals to monitor the migration of fracturing fluid into the reservoir formation. It is generally expected for low permeability formations to show strong capillary forces due to their small characteristic pore radii, but this driving mechanism is in competition with the low permeability and spatial heterogeneities found in tight gas sands. The relevance of capillarity as a driver of fluid migration and retention in a tight gas sand sample is interpreted visually, quantified and compared with high permeability Berea sandstone in our experiments. It is seen that although these formations demonstrate strong capillarity, the effect can be suppressed by the low permeability of the formation and the heterogeneous nature of the sample. However, saturation values attained during imbibition experiments are comparable to those previously obtained for high permeability samples, which can have significant implications in terms of phase mobilities in the neighborhood of induced fractures. Results from this investigation are expected to provide fundamental insight regarding critical variables affecting the retention and migration of water-based fracturing fluids in the neighborhood of hydraulic fractures, and consequently on the post-frac productivity of the well.
Our objective is to improve hydraulic fracturing through an understanding of the fracture evolution. We used real-time acoustic emission (AE) monitoring to study the samples subjected to varying pumping rates which are diametrically stressed at 650 psi. Velocity analysis indicates the compressional velocity variation is less than 2% throughout the sample, so they are treated as isotropic. Higher breakdown pressures were observed at rapid injection rates. Shear failures are commonly found at low to intermediate injection rates, whereas tensile fractures are observed at rapid pumping rates. Fracture initiation occurs at pressures lower than the breakdown pressure. However, the difference between the initiation and the breakdown pressure is less at slower injection rates. Secondary activity coinciding with the pump shutoff was commonly observed at intermediate and rapid injection rates. Higher pressurization rates were observed at rapid injection rates, but the relationship was not linear. The fracture width and length are observed to taper away from the borehole.
Using lattice-Boltzmann simulation of steady-state gas flow we show that apparent permeability values of nano-scale capillaries could be significantly higher than those predicted by the Klinkenberg slip theory. The difference is due to kinetic effects of gas molecules that have gone through inelastic collisions with the walls on those molecules that make up the bulk fluid in the capillary. The kinetic energy that the bouncing back molecules have and the associated momentum carried to the bulk fluid is not a trivial matter in capillaries with diameter h less than 100nm. It creates a molecular streaming effect that amplifies velocity profile developing across the diameter of capillary. In a sense, it is not only the molecules interacting with the wall that slip but also the bulk fluid, i.e., double slip. The double-slip effect is shown using measured permeability data of a crushed nanoporous material with a uniform pore size (10<h<40 nm) at varying pore pressures. Using the simulation results we propose a modification to the Klinkenberg equation. New double-slip Klinkenberg equation includes a characteristic length scale (LKE) that is proportional to the kinetic energy per capillary cross-sectional area of the bouncing-back molecules by the walls. The new length scale of the molecular kinetic effects of nano-capillaries is larger than the mean free path of the molecules. The double-slip Klinkenberg equation reduces to the classical equation for slip flow in large capillaries, i.e., h/ LKE >>1, and converges to the absolute permeability value at high pressures. Due to nanoporous nature of coals and organic-rich shales, the double-slip effect is likely to be significant near hydraulic fractures and production wells in depleted reservoirs.
The presented theoretical work brings new insights into the measurement of crushed particle permeability using gas uptake or release experiments. Although they are fast low-pressure laboratory measurements, there are widely-recognized uncertainties associated with them. In this paper we show that dramatic variation in the measured permeability is possible due to small changes in the measurement cell pressure. Hence, even when the crushed sample is considered to be representative of the reservoir, the measured permeability may not quantitatively be related to flow under the reservoir conditions. The double-slip permeability concept and the modified Klinkenberg theory eliminate some of the uncertainties associated with the laboratory measurement of permeability and lead to development of new measurement protocols for the unconventional resources industry. A double-slip Klinkenberg chart is developed including the effects of nano-capillaries on the permeability, and two procedures are presented with example calculations on how to use the chart to predict permeability of shale sample from its effective pore size and shape.
Laboratory procedures of isothermal gas permeation lead to higher apparent permeability for porous sample. Explanation for this behavior has been given by Klinkenberg (1941) in his seminal work that takes into account phenomena of slip. Accordingly, steady-state flow rate through small capillaries is higher due to slippage of gas molecules by the capillary walls. The slip is dependent on the type of permeating gas and the average pore pressure applied; consequently, the measured permeability values for the sample could vary significantly. The theory also yields a widely-known graphical technique that displays the permeability variations with respect to reciprocal of the average pore pressure on a straight-line with an intercept equal to the absolute permeability of the sample and a slope related to mean free path of the gas molecules.