Christopher R. Clarkson

Innovative methods for flow-unit and pore-structure analyses in a tight siltstone and shale gas reservoir

Tight gas reservoirs are notoriously difficult to characterize; routine methods developed for conventional reservoirs are not appropriate for tight gas reservoirs. In this article, we investigate the use of nonroutine methods to characterize permeability heterogeneity and pore structure of a tight gas reservoir for use in flow-unit identification. Profile permeability is used to characterize fine-scale (1 in. [2.5 cm]) vertical heterogeneity in a tight gas core; more than 500 measurements were made. Profile permeability, although useful for characterizing heterogeneity, will not provide in-situ estimates of permeability; furthermore, the scale of measurement is much smaller than log scale. Pulse-decay permeability measurements collected on core plugs under confining pressure were used to correct the profile permeability measurements to in-situ stress conditions, and 13-point averages of profile permeability were used to relate to log-derived porosity measurements. Finally, N2 adsorption, a new method for tight gas was used to estimate the pore-size distribution of several tight gas samples. A unimodal or bimodal distribution was observed for the samples, with the larger peak corresponding to the dominant pore-throat size, as confirmed by independent methods. Furthermore, the adsorption-desorption hysteresis loop shape was used to interpret the dominant pore shape as slot-shaped pores, which is typical of many tight gas reservoirs. The N2 adsorption method provides rapid analysis and does not suffer from some of the same limitations of Hg injection. In the future, we hope that the N2 adsorption method may prove useful for flow-unit characterization (based on dominant pore size) of fine-grained (siltstone-shale) tight gas reservoirs.

A New Analytical Method for Analyzing Linear Flow in Tight/Shale Gas Reservoirs: Constant-Flowing-Pressure Boundary Condition

Many tight/shale gas wells exhibit linear flow, which can last for several years. Linear flow can be analyzed using a square-root-oftime plot, a plot of rate-normalized pressure vs. the square root of time. Linear flow appears as a straight line on this plot, and the slope of this line can be used to calculate the product of fracture half-length and the square root of permeability. In this paper, linear flow from a fractured well in a tight/shale gas reservoir under a constant-flowing-pressure constraint is studied. It is shown that the slope of the square-root-of-time plot results in an overestimation of fracture half-length, if permeability is known. The degree of this overestimation is influenced by initial pressure, flowing pressure, and formation compressibility. An analytical method is presented to correct the slope of the squareroot-of-time plot to improve the overestimation of fracture halflength. The method is validated using a number of numerically simulated cases. As expected, the square-root-of-time plots for these simulated cases appear as a straight line during linear flow for constant flowing pressure. It is found that the newly developed analytical method results in a more reliable estimate of fracture half-length, if permeability is known. Our approach, which is fully analytical, results in an improvement in linear-flow analysis over previously presented methods. Finally, the application of this method to multifractured horizontal wells is discussed and the method is applied to three field examples.

Production Analysis of Western Canadian Unconventional Light Oil Plays

Unconventional low-permeability (tight) light oil reservoirs have emerged as a significant source of oil supply in North America. As with unconventional gas reservoirs, these low-permeability oil plays exhibit a wide variety of reservoir characteristics, and consequently well-performance profiles. Further, different drilling and completion strategies are used to exploit them. In this work, we suggest that a categorization analogous to that used for unconventional gas reservoirs (i.e. based on reservoir/fluid properties) be used for unconventional light oil reservoirs because of the significant difference in reservoir and production characteristics observed to date in Western Canada. We propose the term “Unconventional Light Oil” (ULO) to capture the spectrum of play types and to distinguish them from unconventional heavy (high viscosity) oil plays. We further propose the following categories of ULO, which can be used as a practical guide for exploration and development:

Case Study: Production Data and Pressure Transient Analysis of Horseshoe Canyon CBM Wells

The Horseshoe Canyon (HSC) CBM play of the Western Canadian Sedimentary Basin is unique to low-rank coal reservoirs because of lack of water production; the production characteristics are qualitatively similar to conventional low-pressure dry gas reservoirs. However, the complex geological history of the coals and non-coal interbeds has imparted strong vertical and lateral heterogeneities that make the play difficult to characterize using conventional methods. Recently, advances in production data analysis (PDA) methodologies have been made for CBM wells; techniques developed for conventional oil and gas reservoirs have been adapted by incorporating some CBM reservoir properties. For example, the popular flowing material balance (FMB) technique, as well as production type-curve and pressure transient analysis (PTA) have been modified to include relatively simple CBM reservoir behaviour (ex. equilibrium desorption). These methods, however, are primarily restricted to the analysis of single-layer reservoirs ; significant errors in estimates of original-gas-in-place (OGIP) and other reservoir properties may occur if strong contrasts exist from layer-to-layer. In this work, multi-layer analysis tools are discussed, including analytical simulators that are used to history-match layer-allocated rates and pressures, and layer-specific FMB, which is used as a PDA method for individual layers. The applicability of advanced PDA methods to the quantitative assessment of HSC reserves was investigated. Single-layer and multi-layer analysis tools were first tested against simulated data. Next, single-layer-equivalent analysis was performed on >40 real wells using type-curve, FMB, and analytical simulation. Finally, a more rigorous multi-layer analysis was performed on a subset of wells where spinner surveys and individual-seam pressure buildup data were available. Analysis of these wells included PTA of the individual seams, individual seam material balance, and multi-layer analytical model history-matching of total commingled flow rates, individual coal zone rates estimated from spinner surveys and shut-in pressures. The single-layer-equivalent analysis appears to yield conservative estimates of OGIP compared to the more rigorous multi-layer analysis in the cases analyzed. Future work will include continued comparisons of multi-layer vs. single-layer PDA, investigation of additional constraints on input reservoir properties used in multi-layer history-matching process, and time-lapse PTA work to quantify changes in layer permeability and skin during depletion.

On the use and abuse of N2 physisorption for the characterization of the pore structure of shales

PIETER BERTIER , KEVIN SCHWEINAR, HELGE STANJEK, AMIN GHANIZADEH, CHRISTOPHER R. CLARKSON, ANDREAS BUSCH, NIKO KAMPMAN, DIRK PRINZ, ALEXANDRA AMANN-HILDENBRAND, BERNHARD M. KROOSS, and VITALIY PIPICH Clay & Interface Mineralogy, RWTH-Aachen University, Bunsenstr. 8, D-52072 Aachen, Germany Department of Geoscience, University of Calgary, Calgary, Canada Shell Global Solutions International, Kessler Park 1, 2288 GS Rijswijk, The Netherlands Dynchem, Saarstrasse 98, D-52062 Aachen, Germany Institute for Petroleum & Coal, RWTH-Aachen University, Lochnerstr. 2, D-52062 Aachen, Germany Jülich Centre for Neutron Science JCNS, Forschungszentrum Jülich GmbH, Outstation at MLZ, Lichtenbergstrasse 1 85747 Garching, Germany e-mail: Pieter.Bertier@emr.rwth-aachen.de

A modified approach for modeling two-phase flowback from multi-fractured horizontal shale gas wells

Abstract Historically, high-frequency fluid production and flowing pressures (hourly or greater) have been gathered on nearly every multi-fractured horizontal well (MFHW), although this data has rarely been used by industry in a quantitative manner to characterize hydraulic fracture or reservoir parameters. Recently several authors have recognized the potential to extract key properties from this early-time data. This work will expand on the analytical flowback analysis model presented by Clarkson and Williams-Kovacs (2013a) and modified by Williams-Kovacs and Clarkson (2013a). These works presented a data-driven pseudo-analytical modeling approach for quantitatively analyzing two-phase flowback to estimate key frac properties including fracture conductivity and half-length. In these early attempts to model flowback from shale gas wells, multi-phase depletion from the fracture network was assumed to be the primary flow-regime. More recently, three flow-regimes have been observed in flowback data depending on data frequency: 1) transient flow of frac fluid within the fracture network prior to breakthrough of formation fluids (rarely seen in shale gas); 2) Single-phase depletion of water within the fracture network (also rarely seen); and 3) coupled formation and fracture flow following breakthrough of formation fluid. In this work, flow-regimes 1–3 are modeled rigorously. Flow-regime 3 is the focus of this study and will be modeled using a coupling of transient linear flow of gas from the matrix to the fractures with multi-phase depletion within the fracture network (conceptually more realistic than previous attempts). Further, dynamic fracture porosity and permeability are incorporated to better represent the physics of the problem and a modified material balance equation (MBE) is developed to account for additional drive mechanisms (fracture closure in addition to desorption and gas expansion). Finally a modified pseudo-pressure and pseudo-time are applied to before-breakthrough (BBT) single-phase rate-transient analysis (RTA) and after-breakthrough (ABT) multi-phase RTA (conducted after analytical simulation using pressure and saturation dependent outputs from simulation) to improve both parameter estimates (BBT) and flow-regime confirmation (ABT). The new model is compared to the previous model using a field case study.

Evaluation of Recovery Performance of Miscible Displacement and WAG Processes in Tight Oil Formations

Recent advances in well design and production techniques have brought considerable attention to exploitation of tight (low permeability, absolute permeability <1 mD) oil resources. Drilling of long horizontal wells and deployment of hydraulic fractures along these wells (multi-fractured horizontal wells) can substantially improve the primary production rates from such reservoirs. Nevertheless, the low effective permeability of the formation to oil hinders the sustainability of favorable oil rates and at some point applying some EOR technique becomes inevitable. In the current study, CO2 miscible flooding and WAG processes in a tight oil reservoir are investigated. Although several studies have investigated different aspects of the process in conventional oil plays, the design of an effective scheme in tight oil formations is more complex. These complexities are related to the proper design of the fractures (half-length, permeability, direction (transverse vs. longitudinal), etc.) and their relative arrangement in producers and injectors and the operational constraints on each well or segment of the well. In this work, we utilize an innovative EOR scheme design where multi-fractured horizontal wells are used for both injection and production, and the hydraulic fracturing stages are staggered to delay breakthrough and improve sweep efficiency. For a set of defined parameters, compositional simulations are conducted to optimize the WAG ratio and cycle length and injection starting point (in time) for the model. The recovery associated with EOR is compared with its corresponding base case model in which all wells are producing under primary recovery for the whole life of the reservoir. The results of this study show that the primary recovery factors (5-15%) can be increased to 25-35% under optimum flooding conditions, considering a reasonable economic framework.

Applicability of micro‐FTIR in detecting shale heterogeneity

Samples of Late Devonian/Early Mississippian New Albany Shale from the Illinois Basin, having maturities ranging from early mature to postmature, were analysed using micro‐Fourier transform infrared (FTIR) spectroscopy, ImageJ processing software and scanning electron microscopic X‐ray spectroscopy to explore the distribution, connectivity and chemical composition of organic matter, clay minerals, carbonate minerals and quartz, and to further test the applicability of micro‐FTIR mapping to study shale heterogeneity. Each sample was analysed in planes parallel and perpendicular to the bedding to investigate anisotropy in component distribution, with a possible implication for better understanding anisotropy in porosity and permeability in organic‐matter‐rich shales. Our results show that for low‐maturity samples, organic matter is better connected in the plane parallel to the bedding than in the plane perpendicular to the bedding. Organic matter connectivity decreases with increasing maturity as a result of kerogen transformation. Clay minerals are very well connected in both planes, whereas carbonate minerals are not abundant whilst dominantly isolated in most samples, independent of maturity. This study demonstrates that micro‐FTIR mapping is a valuable tool for studying shale heterogeneity on a micrometre to millimetre scale that becomes even more powerful in combination with scanning electron microscopy techniques, which extend observations to a nanometre scale. However, to obtain meaningful and comparable results, micro‐FTIR mapping requires very careful standardization, precise selection of peak heights/areas and mapping conditions (such as aperture size, scan numbers, resolution, etc.) well suited for the analysed samples.

Live Imaging of Micro-Wettability Experiments Performed for Low-Permeability Oil Reservoirs

Low-permeability (unconventional) hydrocarbon reservoirs exhibit a complex nanopore structure and micro (µm) -scale variability in composition which control fluid distribution, displacement and transport processes. Conventional methods for characterizing fluid-rock interaction are however typically performed at a macro (mm) -scale on rock sample surfaces. In this work, innovative methods for the quantification of micro-scale variations in wettability and fluid distribution in a low-permeability oil reservoir was enabled by using an environmental scanning electron microscope. Live imaging of controlled water condensation/evaporation experiments allowed micro-droplet contact angles to be evaluated, while imaging combined with x-ray mapping of cryogenically frozen samples facilitated the evaluation of oil and water micro-droplet contact angles after successive fluid injection. For the first time, live imaging of fluids injected through a micro-injection system has enabled quantification of sessile and dynamic micro-droplet contact angles. Application of these combined methods has revealed dramatic spatial changes in fluid contact angles at the micro-scale, calling into question the applicability of macro-scale observations of fluid-rock interaction.

Application of micro-FTIR mapping and SEM to study compositional heterogeneity of siltstones: Example from the Late Devonian–Early Mississippian Middle Bakken Member

This paper explores the applicability of micro‐FTIR mapping to study heterogeneity of organic matter‐lean siltstones. Closely spaced samples of Late Devonian dolomitic siltstones of the Middle Bakken Member were analysed with micro‐FTIR, powder X‐ray diffraction, and scanning electron microscopy (SEM) to explore the distribution and chemical properties of organic matter (OM), muscovite/feldspar/clay group, carbonates, and quartz, and their influence on porosity and permeability of these rocks. Our results show that quartz is the dominant component of the samples, and the main mineralogical differences between the samples are reflected in the abundance of carbonate minerals. Organic matter content is usually far below 1 wt. % and dominantly represented by terrestrially derived vitrinite and inertinite. Micro‐FTIR mapping demonstrates that the more spatially connected quartz and muscovite/feldspar/clays become, the larger permeability in the rock develops, and these correlations are especially strong for planes parallel to bedding. In contrast, carbonate connectivity shows a strong negative correlation with permeability. No correlations between connectivity of components and porosity have been detected. These observations suggest that micro‐FTIR not only can document compositional heterogeneity of siltstones, but also has potential to help understanding their permeability systems.