Horn River Basin Research Articles

Investigation of regional seismicity before and after hydraulic fracturing in the Horn River Basin, northeast British Columbia

We systematically re-analyzed historical seismograms to verify the existence of background seismicity in the Horn River Basin of northeast British Columbia before the start of regional shale gas development. We also carefully relocated local earthquakes that occurred between December 2006 and December 2011 to delineate their spatiotemporal relationship with hydraulic fracturing (HF) operations in the region. Scattered seismic events were detected in the Horn River Basin throughout the study periods. The located seismicity within 100 km of the Fort Nelson seismic station had a clearly increasing trend, specifically in the Etsho area where most local HF operations were performed. The number of events was increased from 24 in 2002–2003 (prior to HF operations) to 131 in 2011 (peak period of HF operations). In addition, maximum magnitude of the events was shifted from ML2.9 to ML3.6 as the scale of HF operation expanded from 2006–2007 to 2011. Based on our relocated earthquake catalog, the overall b value is estimated at 1.21, which is higher than the average of tectonic/natural earthquakes of ∼1.0. Our observations highly support the likelihood of a physical relationship between HF operation and induced seismicity in the Horn River Basin. Unfortunately, due to the sparse station density in the region, depth resolution is poor for the vast majority of events in our study area. As new seismograph stations are established in northeast British Columbia, both epicentral mislocation and depth uncertainty for future events are expected to improve significantly.

Impact of rock fabric on water imbibition and salt diffusion in gas shales

Understanding water uptake of gas shales is critical for designing fracturing and treatment fluids. Previous imbibition experiments on unconfined gas shales have led to several key observations. The water uptake of dry shales is higher than their oil uptake. Furthermore, water imbibition results in sample expansion and microfracture induction. This study provides additional experimental data to understand the effects of rock fabric, complex pore network, clay swelling and osmotic potential on imbibition behavior.We systematically measure and compare the imbibition rates of deionized water and oil into wet/dry and confined/unconfined rock samples from different shale members of the Horn River Basin. We also measure the ion diffusion rate from shale into water during imbibition experiments. The results show that initial water saturation decreases the water uptake of shale samples. However, it has no effect on oil imbibition rates. The liquid imbibition and ion diffusion rates along the lamination are higher than those against the lamination. The results also suggest that confining the shale samples decreases the water imbibition rate, parallel to the lamination. However, it has a negligible effect on water uptake, perpendicular to the lamination. Furthermore, confining does not significantly affect the ion diffusion rates. The comparative study suggests that, for both confined and unconfined samples, water uptake is higher than oil uptake. However, previous experiments on crushed shale samples show that the oil uptake of crushed packs is higher than their water uptake (Xu and Dehghanpour, 2014). The data suggest that the connected pore network of the intact samples is water wet while the majority of rock including poorly connected pores is oil wet. This argument is backed by BSE images and complete spreading of oil on fresh break surfaces of the rock.

Characterization of an Earthquake Sequence Triggered by Hydraulic Fracturing in Harrison County, Ohio

Online Material: Tables of hypoinverse earthquake locations and velocity models. To extract oil and gas in tight shale formations, hydraulic fracturing is used to stimulate fracture growth and increase permeability. Typically, low (−3.0 to 0.0 M w) magnitude earthquakes are produced during hydraulic fracturing (Maxwell et al. , 2002, 2009). In a few cases, however, hydraulic fracturing has been linked to widely observed larger, so‐called positive magnitude, earthquakes. Examples include earthquakes felt by the general population in such areas as Blackpool, England, M L 2.3 (de Pater and Baisch, 2011), Horn River Basin, Canada, M L 3.8 (British Colombia Oil and Gas Commission [BCOGC], 2012), and Oklahoma M L 2.9 (Holland, 2011, 2013) and more recently in Ohio (Skoumal et al. , 2014). In this paper, we show the first evidence of positive magnitude earthquakes on a previously unmapped fault in Harrison County, Ohio, that can be related to a hydraulic fracture operation. A series of six earthquakes were located by the Array Network Facility regional seismic network using the Incorporated Research Institutions for Seismology (IRIS) EarthScope Transportable Array (TA) stations in Ohio on 2 October 2013. These earthquakes were located south of Clendening Lake in Harrison County near the town of Uhrichsville, Ohio, and included two M w 2.0 events. This series of earthquakes was followed by four more events with M w 1.7–2.2 from 3 to 19 October. There were no felt reports for any of these earthquakes. Upon inspection of the OhioSeis seismic network catalog (Hansen and Ruff, 2003) and other available historical catalogs in the region (Stover and Coffman, 1993), this series of earthquakes …

Water Loss Versus Soaking Time: Spontaneous Imbibition in Tight Rocks

AbstractThe combined application of multilateral horizontal drilling and multistage hydraulic fracturing has successfully unlocked unconventional tight hydrocarbon reservoirs. However, the field data show that only a small fraction of the injected water during hydraulic fracturing treatments is recovered during flowback operations. The fate of nonrecovered water and its impact on hydrocarbon production are poorly understood. This paper aims at understanding the relationship between water loss and rock petrophysical properties. It also investigates the correlation between water loss and soaking time (well shut‐in time). Extensive spontaneous imbibition experiments are conducted on downhole samples from the shale members of the Horn River Basin and from the Montney tight gas formation. These samples are characterized by measuring porosity, mineralogy and TOC. Further, a simple methodology is used to scale up the laboratory data for predicting water imbibition volume during the shut‐in period after hydraulic fracturing operations.

An overview of Canadian shale gas production and environmental concerns

Production of hydrocarbons from Canadian shales started slowly in 2005 and has significantly increased since. Natural gas is mainly being produced from Devonian shales in the Horn River Basin and from the Triassic Montney shales and siltstones, both located in northeastern British Columbia and, to a lesser extent, in the Devonian Duvernay Formation in Alberta (western Canada). Other shales with natural gas potential are currently being evaluated, including the Upper Ordovician Utica Shale in southern Quebec and the Mississippian Frederick Brook Shale in New Brunswick (eastern Canada).This paper describes the status of shale gas exploration and production in Canada, including discussions on geological contexts of the main shale formations containing natural gas, water use for hydraulic fracturing, the types of hydraulic fracturing, public concerns and on-going research efforts. As the environmental debate concerning the shale gas industry is rather intense in Quebec, the Utica Shale context is presented in more detail.

Shale Gas Production Rate Forecasting and Type Curve Estimation by Decline Curve Analysis of Horn River Basin in Canada

Shale Gas Production Rate Forecasting and Type Curve Estimation by Decline Curve Analysis of Horn River Basin in Canada

Spontaneous Imbibition of Brine and Oil in Gas Shales: Effect of Water Adsorption and Resulting Microfractures

We measure spontaneous imbibition of aqueous (deionized water and KCl solutions of various concentrations) and oleic (kerosene and iso-octane) phases in several dry organic shale samples selected from two wells drilled in the Horn River basin. We find that the imbibition rate of aqueous phases is much higher than that of oleic phases even when plotted versus scaling dimensionless time, contrary to capillary-driven imbibition models. The observed difference is more pronounced in samples with higher clay content. The results suggest that the excess water intake is due to (1) the additional driving force provided through water adsorption by clay minerals, and (2) the enhancement of sample permeability through adsorption-induced microfractures.

Liquid Intake of Organic Shales

Organic shales are exposed to treatment fluids during and after hydraulic fracturing operations. The fluid–shale interaction influences the petrophysical alteration of the fractured shale and the fate of the fracturing fluid. We systematically measured the spontaneous water and oil intake of five shale samples collected from the cores of two wells drilled in the Horn River basin. The samples represent three shale formations with different mineralogy and petrophysical properties. We characterize the samples by measuring the porosity, conducting X-ray diffraction, and interpreting the well logging data and scanning electron microscopy images. The water intake is higher than the oil intake for all samples. The excess water intake and the physical alteration degree correlate with the shale mineralogy and petrophysical properties. The ratio between the water and oil intake is much higher than the ratio between the water and oil capillary pressures, even for the non-swelling shales. The comparative study indica...

Bacterial Survival in Fractured Shale-Gas Wells of the Horn River Basin

Summary Traditional ideology on the upper temperature limits of life suggest that extreme temperatures such as those observed in the Horn River Basin shale-gas formation (i.e., up to 175°C) should alleviate microbiologically influenced corrosion and souring concerns associated with hydraulic-fracturing procedures. The present case history investigates the accuracy of this theory. Horn River basin wells currently in the flowback or production stage and the source water used to fracture these wells were studied for the presence and identity of viable bacteria. The effectiveness of two biocides (one glutaraldehyde-based and the other cocodiamine-based) in eradicating these bacteria in both the field and the laboratory was also studied. The results show that source ponds are highly contaminated with bacteria. Furthermore, the high-temperature, high-pressure downhole conditions in this region are not sufficient for eradicating bacteria introduced during the fracturing process. These bacteria survive and establish viable, proliferating communities. Biocide, applied continuously "on the fly" during fracturing, was effective at mitigating the downhole bacteria concern. Laboratory studies further showed that more-established bacterial communities were much more resistant to biocidal treatment. Therefore, early mitigation strategies will likely be key in the prevention of microbiologically induced corrosion and souring.

Geological controls on matrix permeability of Devonian Gas Shales in the Horn River and Liard basins, northeastern British Columbia, Canada

Abstract Controls of matrix permeability are investigated for Devonian Gas Shales from the Horn River and Liard basins in northeastern British Columbia, Canada. Mineralogy is varied with high carbonate, high quartz and moderate quartz, carbonate and clay rich strata. Quartz content varies between 2 and 73%, carbonate varies between 1 and 93% and clay varies between 3 and 33%. The TOC content ranges between 0.3 and 6 wt.% and porosity varies between about 1 and 7%. For Horn River basin samples, quartz is mainly biogenic in origin derived from radiolarians. TOC content increases with the quartz content suggesting the TOC and quartz both are derived from siliceous phytoplankton. A positive relationship between porosity and quartz content is due to the positive relationship between quartz and TOC. Matrix permeability parallel to bedding varies between 7.5E− 02 and 7.1E− 07 mD at an effective stress of 15 MPa. Variation in permeability is due to a complex combination of factors that includes origin and distribution of minerals, pore‐size distribution and fabric. Mercury intrusion capillary curves indicate that the higher matrix permeability values (> 2E− 03 mD) occurs in samples that contain interconnected pore apertures greater than 16 μm even when these samples may contain less macropores than low permeability samples. The fabric of high permeability samples can be either isotropic or anisotropic; however permeability of anisotropic samples is more sensitive to changes in effective stress than isotropic samples. More highly anisotropic samples contain moderate amounts of quartz, carbonate and in some, clay. High permeability samples that contain a more balanced ratio between micro-, meso- and macroporosity would not only have faster flow rates but also greater access to sorbed gas within the microporosity compared to samples that lack mesopores. Several Muskwa samples compared to Evie and Besa River samples contain higher quartz, moderate clay and high TOC content coupled with high permeability, less sensitivity to effective stress and balanced ratios between micro-, meso- and macroporosity would be a lower exploration risk due a greater propensity to fracture, the ability to produce and store hydrocarbons due to higher TOC contents and greater communication between macropores and micropores in the organic and clay fractions.

Integrated workflows for shale gas and case study results for the Horn River Basin, British Columbia, Canada

The variation in well performance observed between various shale gas plays, and indeed within individual basins and on individual pads, has gone some way to dispelling myths regarding the perceived homogeneity of “shale gas” targets. With increased quantities of data and more determined analysis, we show that understanding the micro- and mesoscale heterogeneity can be advanced through interdisciplinary studies that incorporate traditional and advanced geophysical data and methods with geological understanding and engineering measurements. This understanding is critical in optimizing well placement, the spacing and length of horizontal wells, and hydraulic fracturing effort to maximize recovery. Specifically, we illustrate that in the Muskwa Formation and the Otter Park, Klua, and Evie members of the Horn River Formation, reservoir quality can be predicted using lambda-rho and mu-rho data extracted from AVO inversion studies. From log data, we show that the most prospective reservoir intervals are characterized by decreasing lambda, increasing mu and/or a lambda:mu ratio less than one.

Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146489, ’Field Application of Very-High-Volume ESP-Lift Systems for Shale-Gas Fracture-Water Supply in Horn River, Canada,’ by Geoffrey C.J. Coppola, SPE, and Ryan C. Chachula, SPE, Encana Corporation, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. One challenge of the Horn River shale play in British Columbia, Canada, has been the increasing number of fracture stimulations required per horizontal wellbore. Critically important is the massive volume of water required to supply the continuous fracturing operations in the development. To eliminate reliance on surface water, it was decided to produce high volumes of sour water from a relatively unknown underpressurized saline aquifer. The challenge was designing an appropriate lift system capable of producing volumes up to 8500 m3/d per well while addressing unknown fluid inflows, fluid transmissibility and recharge, and reservoir-fluid-chemistry characteristics. Introduction The Horn River basin is in northeastern British Columbia, approximately 1600 km northwest of Calgary, Alberta (Fig. 1). The primary-target horizons are the Muskwa, Otter Park, and Evie formations, which are predominantly organic and silica-rich shale. Since 2005, slickwater fracture treatments have grown from 400 m3 of water with 10 t of proppant in a vertical well to 29 staged fracture treatments per horizontal well, with each treatment consisting of 5000 m3 of water with 200 t of proppant. As the volume and number of treatments have grown, so has the demand for fracture-treatment water. At 5000 m3/stage, approximately 150 000 m3 of water is required for one horizontal-well completion with 30 fractures. The Debolt formation was identified as a potential water source that could supply the required fracture-treatment water. A test well was drilled to determine reservoir properties and the compatibility of the water with the Horn River fracturing program. Subsequent testing of the Debolt water revealed 21 000 mg/L total dissolved solids, 60 ppm H2S concentration in the water phase, and approximately 5000 ppm of H2S in the vapor phase. The Debolt formation was determined to be underpressured, with a pressure gradient of 7.2 kPa/m.

When Unconventional Becomes Conventional

Summary British Columbia (B.C.) has seen near-exponential growth in the areas of the Horn River and Montney unconventional shale-gas plays situated in northeastern B.C. (Fig. 1). The original-gas-in-place volume for the Montney and Horn River basins has not been formally calculated, but it has been estimated at greater than 500 Tcf and continues to be revised upwardly as new and more-refined information is obtained and development takes place. The Cordova embayment and Liard basin, east and west (respectively) of the Horn River basin, are at early stages of assessment but promise additional massive gas-in-place values. Approximately 5 years ago, industry experts were predicting a dramatic reduction in viable gas production from the western Canada sedimentary basin, and from North America in general. Market predictions were favouring investment in import terminals for liquefied natural gas (LNG), in which gas from offshore suppliers could be imported and moved through the North American transportation grid to market. Regulators were anticipating an influx of LNG-facility applications and myriad infrastructure modifications to handle the resulting new flow regime. In 5 short years, this dire future has been reversed completely because of the advent of economically viable methods to access gas trapped in shales and similar tight formations. At the current rates of production and exploration, there are more than 20 years of gas reserves in B.C., reversing a previous decline, as shown in Fig. 2. B.C. is ideally positioned to provide gas to North America with ready access to a number of major gas-transportation pipelines, including systems operated by TransCanada Pipelines, Spectra Energy Gas Transmission, and the Alliance Pipeline. Many of these systems are undergoing significant capacity expansions to accommodate the influx of gas from these new plays. This paper will explore the challenges posed to regulators in rapidly moving from conventional vertical-well developments to unconventional multiwell pads consisting of multiple fracture-stimulated horizontal wells.

The influence of paleogeography in epicontinental seas: A case study based on Middle Devonian strata from the MacKenzie Basin, Northwest Territories, Canada

The history of Middle Devonian sea level changes are recorded in the Chinchaga Formation, Lonely Bay Formation, Horn Plateau Formation, and the Horn River Formations that originated in the MacKenzie Basin, which is located in the southern Northwest Territories, Canada. These strata record an almost consistent sea-level rise throughout the Middle Devonian with punctuated deepenings. Deposition began in the MacKenzie Basin in the Eifelian with restricted shallow water evaporites and dolomites of the Chinchaga Formation. Overlying the Chinchaga Formation are the open-marine carbonates belonging to the Lonely Bay Formation, which were overlain by the Horn Plateau Formation buildups. Pelagic shales of the Horn River Formation in the Late Givetian/Early Frasnian later covered these buildups. During the Early and Middle Devonian many continental basins in North America had limited interactions with open ocean waters. These restricted shallow-water basins were vulnerable to the effects of clastic shedding and evaporitic drawdown that commonly caused local lowstands. Several of these shallow basins, including the MacKenzie Basin, have been used to construct Devonian sea-level curves. Comparison of the Middle Devonian strata that formed in the MacKenzie Basin with well-established sea level curves shows that the Late-Givetian regression interpreted from some of those successions is not evident in the succession found in the MacKenzie Basin. This probably reflects the fact that the Mackenzie Basin was directly linked to the open ocean and was not influenced by the changes in sea level that affected many of the enclosed basins.

Montney Fracturing-Fluid Considerations

Summary The Montney gas reservoir has become a critically important component of current western Canadian gas supply and offers exciting future potential. However, this reservoir often presents variable and unique stimulation challenges. Unlike reservoirs that display little water sensitivity, such as the U.S. Barnett Shale and possibly the Muskwa in the Northeastern British Columbia Horn River Basin, recovery of water-based fluids in the Montney can be a key consideration in achieving economic production rates. The use of water-based fracturing fluids in low-permeability reservoirs can result in loss of effective frac half-length caused by phase trapping associated with the retention of the introduced water-based fluid to the formation. This problem is increased by the water-wet nature of most tight-gas reservoirs (where no initial liquid-hydrocarbon saturation is or ever has been present) because of the strong spreading coefficient of water in such a situation. The retention of increased water saturation (Sw) in the pore system after the injection of water-based completion fluids can restrict the flow of produced gaseous hydrocarbons, such as methane. Capillary pressures of 10 MPa-20 MPa, or much higher, can be present in low-permeability formations at low-water saturation levels. Inability to generate sufficient capillary-drawdown force using the natural reservoir-drawdown pressure can result in extended fluid-recovery times or permanent loss of effective fracture half-length. Furthermore, use of water in subnormally saturated reservoirs, where much of the connate water has been removed by long-term evaporation effects associated with gas migration, might also reduce permeability and associated gas flow through a permanent increase in Sw of the reservoir. Secondary costs, such as rig time for swabbing, can add to the negative economic impact. The Montney is found to be a dry-gas reservoir in some areas, transitioning to an oil reservoir in other areas. Because of this, it would not be surprising to encounter retrograde condensate production through transition areas. In such a case, if sufficient drawdown pressure is applied to reduce reservoir pressure below the dewpoint, liquid hydrocarbons might condense from the produced gas phase, resulting in two-phase flow and potential trapping of the hydrocarbon liquid phase. Also, some areas of the upper Montney exhibit reservoir pressures in the 30 MPa range, whereas other areas exhibit lower pressures in the 17 MPa-21MPa range. The same drawdown on a lower-pressured reservoir could therefore result in condensate condensing from the gas phase, where it would not have in the higher-pressured reservoir. If a third aqueous fracturing fluid is introduced, three-phase flow might occur. The resulting reduced relative permeability to gas might drastically reduce production rates. Also, emulsion-formation potential exists, which could present an additional reduction in fluid flow and recovery. Choice of fracturing fluid must be carefully determined for each area of the Montney, balancing economics with production. It is important to always keep in mind that key reservoir properties can vary dramatically in the Montney, as a function of both geographic location and depth. This paper presents laboratory test results of regained methane permeability vs. drawdown pressure and contact time with Montney core under representative reservoir conditions. Water, foamed water and hydrocarbon-based fracturing fluid systems are evaluated. The testing was funded by and arranged for by operators in preparation for actual fracturing treatments in two different fields. Core plugs, time and funding were limited; therefore, only tests deemed necessary for decision-making were run. Limited repeat testing was therefore possible.

Comments: Unconventional Interest

Editor's column High commodity prices and the need for new production are spurring great interest in unconventional oil and gas plays throughout North America. Majors, previously willing to cede mature areas to independents so they could focus on bigger prizes elsewhere, have taken renewed interest in their potential. Following the success of the Barnett Shale region in the US, attention has turned to the Haynesville Shale gas play in northwest Louisiana and east Texas, British Columbia, and the Bakken area in North Dakota. The Barnett Shale has been one of the great success stories in gas production in the past few years, thanks to advances in drilling and fracturing technology. That success, and the play's future potential, are discussed in-depth in an article in this issue that begins on page 48. Now other areas are attracting attention. An array of upstream acquisitions involving unconventional production have taken place in the past several months in North America involving both Canadian and US firms, and including independents and majors. In late July, BP became a participant in US shale gas with an acquisition of 90,000 net acres and 50 million ft3/D of gas production in the Oklahoma Woodford Shale gas area. That follows Shell's recent deal with EnCana for a joint exploration agreement to explore and develop the Haynesville Shale area. Chesapeake and its joint venture partner Plains Exploration & Production believe Haynesville Shale will eventually become the largest gas field in the US and the fourth-largest in the world. Shell also made the year's biggest acquisition to date when it paid USD 5.9 billion for Canada's Duvernay Oil, which has extensive acreage in western Canada's tight gas area. Of particular interest is the Montney Basin in northeast British Columbia, which has emerged as one of North America's most interesting gas plays. Traditionally, majors have sold off mature areas to independents as they looked for bigger and higher-potential fields outside of North America. But with resource nationalism limiting access and high oil prices making unconventional projects more economic, international oil companies (IOCs) are taking a new look at some areas in the US and Canada, particularly in light of the technological progress that has been made in fields such as the Barnett Shale. Independents such as Devon, Chesapeake, XTO, and EOG Resources have been the dominant players in developing North America's unconventional reservoirs, but that apparently is changing. Other newly active firms in these emerging plays include EnCana, which has begun investing heavily in the Haynesville Shale and the Horn River basin Shale in British Columbia and Hess, which is investing in Bakken. Most of the world's oil shale is in the US, with the US Geologic Service estimating about 2 trillion bbl of in-place deposits, but shale is very costly to develop and produce. But as IOCs continue to look for new sources of oil and access constraints hamper where they can go to find it, these challenging frontier areas—including shale, tight gas, heavy oil, and coalbed methane—should attract increasing attention going forward.

Characterizing the shale gas resource potential of Devonian–Mississippian strata in the Western Canada sedimentary basin: Application of an integrated formation evaluation

Devonian–Mississippian strata in the northwestern region of the Western Canada sedimentary basin (WCSB) were investigated for shale gas potential. In the subsurface, thermally mature strata of the Besa River, Horn River, Muskwa, and Fort Simpson formations attain thicknesses of more than 1 km (0.6 mi), encompassing an area of approximately 125,000 km2 (48,300 mi2) and represent an enormous potential gas resource. Total gas capacity estimates range between 60 and 600 bcf/section. Of particular exploration interest are shales and mudrocks of the Horn River Formation (including the laterally equivalent lower Besa River mudrocks), Muskwa Formation, and upper Besa River Formation, which yield total organic carbon (TOC) contents of up to 5.7 wt.%. Fort Simpson shales seldom have TOC contents above 1 wt.%. Horn River and Muskwa formations have excellent shale gas potential in a region between longitudes 122W and 123W and latitudes 59N and 60N (National Topographic System [NTS] 94O08 to 94O15). In this area, which covers an areal extent of 6250 km2 (2404 mi2), average TOC contents are higher (3 wt.% as determined by wire-line-log calibrations), and have a stratal thickness of more than 200 m (656 ft). Gas capacities are estimated to be between 100 and 240 bcf/section and possibly greater than 400 tcf gas in place. A substantial percentage of the gas capacity is free gas caused by high reservoir temperatures and pressures. Muskwa shales have adsorbed gas capacities ranging between 0.3 and 0.5 cm3/g (9.6–16 scf/t) at reservoir temperatures of 60–80C (140–176F), whereas Besa River mudrocks and shales have low adsorbed gas capacities of less than 0.01 cm3/g (0.32 scf/t; Liard Basin region) because reservoir temperatures exceed 130C (266F). Potential free gas capacities range from 1.2 to 9.5 cm3/g (38.4 to 304 scf/t) when total pore volumes (0.4–6.9%) are saturated with gas. The mineralogy has a major influence on total gas capacity. Carbonate-rich samples, indicative of adjacent carbonate platform and embayment successions, commonly have lower organic carbon content and porosity and corresponding lower gas capacity (1% TOC and 1% porosity). Seaward of the carbonate Slave Point edge, Muskwa and lower Besa River mudrocks can be both silica and TOC rich (up to 92% quartz and 5 wt.% TOC) and most favorable for shale gas reservoir exploration because of possible fracture enhancement of the brittle organic- and siliceous-rich facies. However, an inverse relation between silica and porosity in some regions implies that zones with the best propensity for fracture completion may not provide optimal gas capacity, and a balance between favorable reservoir characteristics needs to be sought.

The Solace of Open Spaces by Gretel Ehrlich

Reviews 255 Southwest’s best-known anti-ist writer. Edited by James Hepworth and Gregory McNamee, this group of essays is no conventional set of critical opin­ ions, no boxable package of pedantic assessments (when they asked me to contribute and I couldn’t think of anything nonacademic to say, I didn’t sub­ mit anything at all), no twentieth-century view. Instead, it matches its man. The selections include both formal and informal interviews with Abbey himself, somewhat serious looks at a couple of his books, personal bits of imaginative correspondence, some thoughtful musings, some gentle chidings, and two or three essays that bounce off the wall. That is, Resist Much, Obey Little echoes the strengths, the weaknesses, even the characteristics of its sub­ ject (and Abbey’sstrengths alwaysprevail). So I liked it. Some of the pages (Berry’s, Barry Lopez’s, the interviews) I liked better than others (Mairs’s and Houston’s, for example), but on the whole I found the collection not only provocative but fun to read. There is no pattern to my likes and dislikes, either, for my favorite essays included both the wildest and the tamest. The slim volume could have been (maybe should have been) longer, but I have only people like myself to blame. Because Resist Much, Obey Little is the kind of book to which one responds personally, it’s also the kind of book hard to review. Just as a reader either enjoys or misunderstands Abbey’s works, so he or she either will appre­ ciate or be annoyed by the eclecticism of this miscellany. “I love Edward Abbey,” says Sam Hamill at the end. “He’s a high-class quarrel.” I agree. And that’s what the editors who put together this book’s loving quarrels are trying to say, too. ANN RONALD University of Nevada Reno The Solace of Open Spaces. By Gretel Ehrlich. (New York: Viking/Penguin, 1985. 131 pages, $14.95.) In 1976, Ehrlich, a documentary filmmaker, left the cockroaches and carbon monoxide of Los Angeles to make a film in Wyoming. She finished her first book after eight years of herding sheep in the Big Horn River Basin, pulling calves in rainstorms in the Beartooths, fighting off lecherous hermitcowboys in town, and waiting out long Wyoming winters alone in her cabin. The manuscript, originally a journal sent to a friend, sings a lovesong to the West in a hard, lean, yet feminine prose. Ehrlich writes about the men and women of the Wyoming range with the same passion that Hemingway wrote about the aficionados of Spain, painting a coarse, raw picture of the person­ alities that drew her into the Basin’s world—a world where summers are dry and the winters’ winds howl. It is a land, writes Ehrlich, where wind reigns, sweeping out the big room of space daily, “leaving a bone yard of fossils, agates, and carcasses in every stage of decay. . . . Wind is the meticulous gardener, raising dust and pruning the sage.” 256 Western American Literature The values of the Basin, according to Ehrlich, crystallize quickly. People are strong on scruples but tenderhearted about quirky behavior. It is a place, she writes, which is “darkened only by the small-mindedness that seals people in. Men become hermits; women go mad.” Ehrlich highlights her book with piercing images of the sheeptown of Lovell, the Basin’s fierce summers and winters, the fading Indian customs, and the details of losing a lover and gaining a husband. She is a keen watcher of symbols and the harmony between man, animal, and the land, and writes only about events that have truly changed her life. JANET BENNION CANNON Utah State University This isDinosaur: Echo Park Country and Its Magic Rivers. Edited by Wallace Stegner. (Boulder: Roberts Rinehart, 1985. 93 pages, $24.95 hardcover, $8.95 paper.) This book, first published in 1955 by Alfred Knopf, figured prominently in the great Echo Park controversy of 1954-1955, when Dinosaur National Monument was threatened with two Bureau of Reclamation dams that would have dramatically altered the primitive setting of that spectacular region. It is reprinted now with a new foreword by Wallace Stegner, a note from...

What does the term 'Horn River Formation' mean?

What does the term 'Horn River Formation' mean?

The Horn Plateau Formation: A Middle Devonian Coral Reef, Northwest Territories, Canada

ABSTRACT The Horn Plateau Formation is a Middle Devonian limestone reef approximately 0.4 mi diameter and 400 ft thick which crops out the Interior Plains about 110 mi west of Yellowknife, Northwest Territories. The study is based on examination of material collected from the outcrop and 5 core-holes drilled on and near the reef. Corals are the most important framebuilders present and crinoid ossicles contribute most to the sediment volume. Three macrofacies of this coral patch-reef are recognized: 1) organic reef, an area where framebuilders grew profusely, 2) reef flat, an area characterized by sand-sized sediments, and 3) reef flank, an area of predominantly gravel-sized sediments. Strongly agitated water conditions prevailed over the organic-reef and reef-flank macrofacies whereas moderately agitated water covered the reef flat. Subdivision of the macrofacies has produced 11 microfacies of distinctive texture-composition combinations. Paleoecologic analysis of the individual organism or group permits recognition of 6 successive biotopes from a deeper offreef position up onto the reef flat, namely; (1) bryozoan, (2) solitary coral, (3) massive coral and stromatoporoid, (4) Thamnopora, (5) crinoid and brachiopod, and (6) Stachyodes; prevailing winds were from the northeast. The Horn Plateau reef may be analogous to the Recent Sahul Shelf reefs off Western Australia. A new interpretation of the age of the Horn Plateau reef results from consideration of the additional fauna collected. The reef is middle Givetian age, and is correlative with the middle Pine Point and upper Ramparts formations. It roots in the Lonely Bay Formation, and is overlain by the black shale of the Horn River Formation.