The economic trade-off between overcapitalization and ineffective hydrocarbon recovery has forced operators in shale plays to focus their efforts on understanding optimal wellbore spacing, both in the vertical and horizontal sense. Matrix permeability has a significant impact on the reservoir modeling results that drive many of these development decisions. Despite incorporating modern crushed-rock pressure-decay permeability datasets, well production is commonly degraded at wellbore spacing schemes much wider than the models indicate. The overstatement of permeability is likely due to experimentally derived flow-regime effects inherent to the analysis. Large helium gas molecules at low pressures are used in crushed-rock permeability experiments, which allow individual gas molecules to be quite far apart (they have a large mean free path, λ). Since shale pores are often smaller than λ, it is more likely a gas molecule will hit a pore wall than another gas molecule. This creates flow-regime effects, which tend to overstate permeability up to several orders of magnitude. To test this hypothesis, several crushed-rock samples from the Devonian Duvernay and Jurassic Nordegg Formations in the Kaybob area in the Western Canadian Sedimentary Basin (WCSB), as well as the Late Cretaceous Eagle Ford Formation in South Texas were analyzed with a pressure-decay apparatus at various λs. This was accomplished by manipulating the gas molecule used and the equilibrium pressure of the test. Although significant differences were observed, conventional approaches for correcting flow-regime effects, including slip and double-slip plots, were not successful in deriving the true (intrinsic) matrix permeability. A new technique, referred to as the λ plot, enables a reasonable derivation of flow-regime corrected permeability and effective pore size for all the samples. This permeability, k1λ, corrects the λ to a typical plug permeability experiment value of 1 nm, which we believe is quite close to the true (intrinsic) permeability. The results indicate that the median matrix permeability for all samples is 5 nD, down from over 200 nD when no corrections are made. Steady-state permeability measurements trend towards k1λ as confining stress is applied on plugs where microfractures appear to be minimal. Crushed-rock pressure-decay permeability, when corrected for flow-regime effects, offers the best measure of matrix permeability in shales.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (Korea Gas Corporation and Colorado School of Mines) | Jung, Hoiseok (Korea Gas Corporation and Colorado School of Mines) | Amini, Kaveh (Colorado School of Mines) | Abass, Hazim (Halliburton and Colorado School of Mines)
Tadesse Weldu Teklu, Colorado School of Mines; Daejin Park and Hoiseok Jung, Korea Gas Corporation, and Colorado School of Mines; Kaveh Amini, Colorado School of Mines; and Hazim Abass, Halliburton and Colorado School of Mines Summary Matrix and fracture permeability of carbonate-rich tight cores from Horn River Basin, Muskwa, Otter Park, and Evie Shale formations, were measured before and after exposing the core samples to spontaneous imbibition using dilute acid [1-or 3-wt% hydrochloric acid (HCl) diluted in 10-wt% potassium chloride (KCl) brine]. Permeability and porosity were measured at net stress between 1,000 and 5,000 psia. Brine and dilute-acid imbibition effect on proppant embedment, rock softening/weakening, and fracture roughness were assessed. The following are some of the experiment observations: (a) Formation damage caused by water blockage of water-wet shales can be improved by adding dilute HCl or by using hydrocarbon-based fracturing fluids; (b) matrix permeability of clay-rich or calcite-poor shale samples is usually impaired/damaged by dilute-acid imbibition; (c) matrix permeability and porosity of calcite-rich shales usually improved with dilute-acid imbibition; (d) effective fracture permeability of unpropped calcite-rich shales is reduced by dilute-acid imbibition; the latter is because of "rock softening" and "etching/smoothing" of fracture roughness on the "fracture faces." Nevertheless, dilute-acid imbibition is less damaging than brine (slickwater) imbibition; and (e) proppant embedment was observed during both brine (slickwater) and diluteacid imbibition. Introduction A statistical report in EIA (2016) shows that, in the United States, oil and gas production from tight formations have become increasingly significant since 2007. This is mainly because of the advancement of multistage hydraulic-fracture stimulation in horizontal wells. Even with multistage hydraulic-fracture stimulation horizontal-well technology, oil recovery from tight formations such as the Bakken is usually less than 10% (Alharthy et al. 2015; Sheng 2015; Teklu et al. 2017a). Hence, many researchers are devoted to improving this low oil recovery.
Next to the Alaska Highway 97 north of Fort St. John in the thick forests of northern British Columbia natural gas is trucked out from the Highway Natural Gas Liquids Plant in the North Montney shale formation. Unconventional oil and gas have come to dominate the exploration and development scene in Western Canada since 2005, much as they have in the US. Both countries share essential elements needed to launch and sustain unconventionals: A long history of drilling, publicly available data, well-understood sedimentary basins, extensive infrastructure, a diverse corporate sector, and regulatory regimes supportive of innovative resource development. Following closely on developments in the US, the “tight gas” concept was a key component of the Canadian oil patch in the 1980s and 1990s. Horizontal drilling and hydraulic fracturing were employed in ever-tighter reservoirs, and in the early 2000s, Canadian operators began to appreciate the true potential of oil and gas from shales, tight reservoirs, and coal seams.
The application of chemostratigraphy to problems in modern and ancient environments has a long and successful history. In particular, the use of high-resolution X-ray fluorescence (XRF) spectrometry for studying the elemental content of core and rock at the sub-millimeter scale to understand provenance, grain size, paleoredox state, terrigenous influence, and other aspects of strata is well documented in paleoclimatology literature.
Berner, U. and E. Faber, 1988, Maturity related mixing model for methane, ethane and propane, based on carbon isotopes, Organic Geochemistry, vol.
Teklu, Tadesse Weldu (Colorado School of Mines) | Park, Daejin (KOGAS, Daegu and Colorado School of Mines) | Jung, Hoiseok (KOGAS, Daegu and Colorado School of Mines) | Miskimins, Jennifer L. (Colorado School of Mines)
The geomechanics of a shale play: what makes a shale prospective.
However, successful hydraulic stimulation treatments can be challenging to implement, and require considerable forethought. Compositional variation, rock fabric, geomechanical stratigraphy, and natural fracture systems all interact to influence and complicate hydraulic fracture treatments in shale reservoirs (Gale et al., 2006; Passey et al., 2010). Previously published work has highlighted the interaction between natural and induced fractures in the Horn River Basin (Dunphy and Campagna, 2011). This indicates that effective well completions require the efficient utilization of natural fracture systems to enhance permeability and drainage volume. Since natural fracture systems are a significant factor controlling the response of shale reservoirs to hydraulic fracturing, it is essential to identify and understand the key parameters of natural fracture networks that influence the effectiveness of hydraulic fracturing treatments. This paper combines results from natural fracture network characterization with discrete fracture network (DFN) modelling to identify the key parameters that influence hydraulic fracture geometry in the Horn River Basin.
ABSTRACT: Discrete Fracture Network (DFN) models have advanced considerably, yet challenges remain for capturing attribute variation and uncertainty across scales. We highlight problems using examples from shale hydrocarbon reservoirs, and propose methods to tackle them. Adequate treatment of spatial organization is perhaps the most problematic gap in many DFN models. Analysis of spatial organization in horizontal image logs using a newly developed method yields insight on how to populate models by recognizing distinct patterns of clustering or even spacing. Fracture fill is absent or inadequately treated in most DFN models. We show recent progress on fill prediction, how fill history modifies fracture network flow characteristics and patterns, and how sealed fractures may govern potential interactions with hydraulic fractures. Heights and lengths remain difficult or impossible to measure in the subsurface and challenging to obtain from outcrops. To guide DFN construction, outcrop studies must extract meaningful length data and geomechanical models need to model the range of fracture sizes in 3D, simulate interfaces, and account for cement.
ABSTRACT: Fractures play an essential role in many unconventional reservoirs, yet our ability to see and characterize them is often limited. It is common to observe few vertical fractures in vertical image logs and many in horizontal or inclined well images. Core gives the highest resolution and the best characterization but has limited application because of the time and cost involved. Image logs are acquired more frequently and can be obtained from wells of all orientations and over long intervals. After de-biasing and comparing fracture intensities between vertical cores, vertical image logs and inclined/horizontal images there is a noticeable difference in the ability to detect/resolve fractures from the three data sources. Many fractures that are visible to the eye in core are not resolved in a wellbore image. There is clearly better visibility of fractures in the horizontal images than in the vertical images. In addition to the effect of well orientation on sampled fracture density, the effects of image coverage, obscuring features and altered stress at the wellbore wall influence the visibility of fractures. This paper examines these effects and compares the observed fracture abundance to a minimum size-intensity relationship derived from core observations.
Sheng Yang, University of Calgary; Nicholas B. Harris and Tian Dong, University of Alberta; and Wei Wu and Zhangxin Chen, University of Calgary Summary This paper documents the formation of natural fractures in the Horn River Group, a major Canadian shale gas play, and addresses relationships between natural-fracture development and rock-mechanical properties derived from cores and well logs. Most natural fractures in the Horn River Shale are narrow vertical fractures, sealed with carbonate minerals. In this study, the formation of observed fractures is primarily determined by a lithology type, mineral composition, and rock-mechanical properties at the timing of fracturing. Brittleness is an important geomechanical property controlling the formation of fractures, because brittle shale is more easily fractured than ductile shale, and fractures in brittle shale tend to persist when the fracturing pressure is released. In this study, a hardness value measured by a commercial hardness tester is found to be a good proxy for the brittleness of shale layers. On the basis of a statistical analysis, the threshold values of both hardness and brittleness are estimated to predict the distribution of natural fractures, assuming that the mechanical properties of the host rock were relatively stable from at least the time at which fractures formed. Hardness values are shown to be more reliable than brittleness. Introduction Researchers have conducted many studies on different aspects of natural fractures and fractured reservoirs (Lorenz et al. 1991; Laubach et al. 2004) [e.g., the characterization and effects of fractures in the carbonate and siliciclastic reservoirs of the Middle East (Ameen et al. 2009, 2010, 2014)]. In recent years, natural fractures in shale reservoirs have become a key focus of research (Curtis 2002; Kresse et al. 2011; Gale et al. 2014) [e.g., the comprehensive study of natural fractures in the Qusaiba shale conducted to evaluate shale reservoir proceptivity by Ameen (2016)].