Repository for Oil and Gas Energy Research (ROGER)

Abstract:
New technologies combining hydraulic fracturing and horizontal drilling in oil and gas extraction are creating a sudden expansion of production. Residents of places where deep underground oil and gas deposits are found want to know about the broader economic, social, and environmental impacts of these activities that generate windfall income for some residents. We first review the literature on windfall spending patterns. Then, using the Marcellus region, the earliest area to be tapped using the new techniques, we estimate county-level employment and income effects. For robustness, we employ two methods. Using a propensity score matching approach we find no effect of fracking on income or employment. A panel-fixed effects regression approach suggests statistically significant employment effects in six out of seven alternative specifications, but significant income effects in only one out of seven specifications. In short, the income spillover effects in the Marcellus region appear to be minimal, meaning there’s little incentive at the county level to incur current or potential future costs that may be associated with this activity. We conclude with some ideas on how localities might employ policies that would allow natural gas extraction to move forward, benefitting landowners, while establishing some financial safeguards for the broader community.

Abstract:
The dramatic increase in oil and gas production from shale formations has led to intense interest in its impact on local area economies. Exploration, drilling and extraction are associated with direct increases in employment and income in the energy industry, but little is known about the impacts on other parts of local economies. Increased energy sector employment and income can have positive spillover effects through increased purchases of intermediate goods and induced local spending. Negative spillover effects can occur through rising local factor and goods prices and adverse effects on the local area quality of life. Therefore, this paper examines the net economic impacts of oil and gas production from shale formations for key shale oil and gas producing areas in Arkansas, North Dakota and Pennsylvania. The synthetic control method (Abadie and Gardeazabal 2003; Abadie et al., 2010) is used to establish a baseline projection for the local economies in the absence of increased energy development, allowing for estimation of the net regional economic effects of increased shale oil and gas production.

Abstract:
Carboniferous black mudrocks with known petroleum potential occur throughout Northern Germany. However, despite numerous boreholes exploring for conventional hydrocarbons, the potential for shale gas resources remains uncertain. Therefore, an integrated investigation was conducted to elucidate the shale gas potential for three different Carboniferous facies incorporating baseline parameters from sedimentological and organic-geochemical analyses. Tournaisian–Namurian fine-grained rocks of the Culm-facies, with Type II + III kerogen were deposited in the basin center. TOC contents of up to 7 % occur in the Lower Alum Shale (3.6 % VRr) and up to 6 % in the Upper Alum Shale (4.4 % VRr). Bands of organic-rich black shales, reflecting sea-level variations controlled by global eustatic cycles, occur within the Tournaisian–Visean “Kohlenkalk”-facies north of the Rhenish Slate Mountains and in the Rügen island area. In both areas the organic matter is characterized by a kerogen Type II + III with TOC contents of up to 7 % and maturities of up to 4.2 and 1.8 % VRr, respectively. Black hemipelagites intercalated with coarser-grained silt- and sandstones occur in the Synorogenic Flysch Formation of the Namurian A along the southern basin margin. TOC contents vary from 0.5 to 2.0 % with Type III kerogen dominated organic matter and maturities of up to 2.5 % VRr. The baseline parameters presented in this paper indicate a shale gas potential for the sediments of the Culm-facies on the southern basin margin and of the “Kohlenkalk”-facies in the Rügen area.

Abstract:
The Late Permian Zechstein Group in northeastern Germany is characterized by shelf and slope carbonates that rimmed a basin extending from eastern England through the Netherlands and Germany to Poland. Conventional reservoirs are found in grainstones rimming islands created by pre-existing paleohighs and platform-rimming shoals that compose steep margins in the north and ramp deposits in the southern part. The slope and basin deposits are characterized by debris flows and organic-rich mudstones. Lagoonal and basinal evaporites formed the seal for these carbonate and underlying sandstone reservoirs. The objective of this investigation is to evaluate potential unconventional reservoirs in organic-rich, fine-grained and/or tight mudrocks in slope and basin as well as platform carbonates occurring in this stratigraphic interval. Therefore, a comprehensive study was conducted that included sedimentology, sequence stratigraphy, petrography, and geochemistry. Sequence stratigraphic correlations from shelf to basin are crucial in establishing a framework that allows correlation of potential productive facies in fine-grained, organic-rich basinal siliceous and calcareous mudstones or interfingering tight carbonates and siltstones, ranging from the lagoon, to slope to basin, which might be candidates for forming an unconventional reservoir. Most organic-rich shales worldwide are associated with eustatic transgressions. The basal Zechstein cycles, Z1 and Z2, contain organic-rich siliceous and calcareous mudstones and carbonates that form major transgressive deposits in the basin. Maturities range from over–mature (gas) in the basin to oil-generation on the slope with variable TOC contents. This sequence stratigraphic and sedimentologic evaluation of the transgressive facies in the Z1 and Z2 assesses the potential for shale-gas/oil and hybrid unconventional plays. Potential unconventional reservoirs might be explored in laminated organic-rich mudstones within the oil window along the northern and southern slopes of the basin. Although the Zechstein Z1 and Z2 cycles might have limited shale-gas potential because of low thickness and deep burial depth to be economic at this point, unconventional reservoir opportunities that include hybrid and shale-oil potential are possible in the study area.

Abstract:
Natural gas from tight shale formations will provide the United States with a major source of energy over the next several decades. Estimates of gas production from these formations have mainly relied on formulas designed for wells with a different geometry. We consider the simplest model of gas production consistent with the basic physics and geometry of the extraction process. In principle, solutions of the model depend upon many parameters, but in practice and within a given gas field, all but two can be fixed at typical values, leading to a nonlinear diffusion problem we solve exactly with a scaling curve. The scaling curve production rate declines as 1 over the square root of time early on, and it later declines exponentially. This simple model provides a surprisingly accurate description of gas extraction from 8,294 wells in the United States’ oldest shale play, the Barnett Shale. There is good agreement with the scaling theory for 2,057 horizontal wells in which production started to decline exponentially in less than 10 y. The remaining 6,237 horizontal wells in our analysis are too young for us to predict when exponential decline will set in, but the model can nevertheless be used to establish lower and upper bounds on well lifetime. Finally, we obtain upper and lower bounds on the gas that will be produced by the wells in our sample, individually and in total. The estimated ultimate recovery from our sample of 8,294 wells is between 10 and 20 trillion standard cubic feet.

Abstract:
The study reports data from an economic choice experiment to determine the likely welfare impacts of hydraulic fracturing, in this case using natural gas extracted by hydraulic fracturing for household electricity. Data were collected from an Internet survey of 515 residents of New York State. The welfare analysis indicated that on average households incur a welfare loss from in-state hydraulic fracturing as the source of their electricity. The evidence suggests that households in shale counties bear more costs from HF electricity than households out of shale counties. The average welfare loss is substantive, estimated at 40–46% of average household electric bills in shale counties and 16–20% of bills in counties without shale. The evidence also suggests that relative proximity to HF well sites also increases cost borne by households.

Abstract:
We investigated whether the increase in the US shale gas production changed the structures of the US and Japanese natural gas markets using market data for the period 2002:5–2012:5. Our analysis consists of a structural break test and market integration analysis. The Bai and Perron structural break test detected a break point of natural gas prices and consumption in 2005 as well as other external shocks – Hurricane Katrina and the Lehman Shock – that are irrelevant to shale gas development. We eliminated the impact of these shocks by separating the data set using the breaks identified in our analysis. We found the breaks skewed the estimation; a market linkage existed between the US and Japanese markets in the original data set, while it did not in the separated data. The vector autoregressive (VAR) model also indicated a significant change before and after the break point; the US market had a one-side influence on the Japanese market before 2005, but the influence disappeared after 2005. Our results implied that the shale gas revolution, triggered by the increase in shale gas production in 2005, caused the change in the relationship between the US and Japanese natural gas markets.

Abstract:
An analysis of the energy return on investment (EROI) of natural gas obtained from horizontal, hydraulically fractured wells in the Marcellus Shale was conducted using net external energy ratio methodology and available data and estimates of energy inputs and outputs. Used as sources of input data were estimates of carbon dioxide and nitrogen oxides emitted from the gas extraction processes, as well as fuel-use reports from industry and other sources. Estimates of quantities of materials used and the associated embodied energy as well as other energy-using steps were also developed from available data. Total input energy was compared with the energy expected to be made available to end users of the natural gas produced from a typical Marcellus well. The analysis indicates that the EROI of a typical well is likely between 64:1 and 112:1, with a mean of approximately 85:1. This range assumes an estimated ultimate recovery (EUR) of 3.0 billion cubic feet (Bcf) per well. EROI values are directly proportionate to EUR values. If the EUR is greater or lesser than 3 Bcf, the EROI would be proportionately higher or lower. EROI is also sensitive to the energy used or embedded in gathering and transmission pipelines and associated infrastructure and energy used for their construction, energy consumed in well drilling and well completion, and energy used for wastewater treatment.

Abstract:
The use of high-volume horizontal hydraulic fracturing (fracking) has increased substantially over the past five years in the United States. Use of this drilling technology to extract natural gas from hitherto impermeable shale is expected to increase even more in coming decades. Two institutions, integration contracts and well spacing requirements, evolved to mitigate the common-pool economic wastes associated with conventional oil and gas drilling. U.S. regulators have applied these institutions to fracking. However, shale plays differ geologically from conventional plays and are subject to different extractive technologies. We theorize that the point-source pollution characteristics of conventional drilling allowed integration contracts and well space requirements to minimize local negative environmental externalities as an unintended byproduct of minimizing common-pool economic wastes. The non-point source pollution characteristics of fracking, however, make these institutions insufficient to minimize negative environmental externalities associated with drilling in shale plays, because the economic waste problem is different. If policymakers understand the crucial differences between conventional oil and gas plays and shale plays and the drilling technologies applied to them, they should be better equipped to craft fracking regulatory policies that internalize problematic externalities.

Abstract:
This paper presents a probabilistic decline curve workflow to model shale gas production from the Barnett, Fayetteville, Haynesville, and Woodford shales. Ranges of model input parameters for four gas shales are provided to guide the preparation of uniform and triangle probability distributions. The input parameter ranges represent realistic distributions of model parameters for specific gas shales.

Abstract:
This paper aims to quantitatively explore the uncertainty around the global potential of shale gas development and its possible impacts, using a multi-regional energy system model, TIAM (TIMES Integrated Assessment Model). Starting from the premise that shale gas resource size and production cost are two key preconditions for its development, our scenario analysis reveals the way these and other variables interact with the global energy system, impacting on the regional distribution of gas production, interregional gas trade, demand and prices. The analysis shows how the reciprocal effects of substitutions on both the supply and demand-side play an important role in constraining or enabling the penetration of shale gas into the energy mix. Moreover, we systematically demonstrate that the global potential for shale gas development is contingent on a large number of intervening variables that manifest themselves in different ways across regionally-distinct energy systems. A simple theoretical model is derived from the results of the scenario analysis. Its purpose is to simplify and explain the complex behaviour of the system, by illustrating the chain of actions and feedbacks induced by different shale gas economics, their magnitude, their relative importance, and the necessary conditions for the global potential to be realised.

Abstract:
Various analytical, semi-analytical, and empirical models have been proposed to characterize rate and pressure behavior as a function of time in tight gas and shale gas systems featuring horizontal wells with multiple hydraulic fractures. Despite a few analytical models, as well as a small number of published numerical studies, there is currently little consensus regarding the large-scale flow behavior over time in such systems, particularly regarding the dominant flow regimes and whether or not reservoir properties or volumes can be estimated from well performance data. We constructed a fit-for-purpose numerical simulator which accounts for a variety of production features pertinent to these systems—specifically ultra-tight matrix permeability, hydraulically fractured horizontal wells with induced fractures of various configurations, multiple porosity and permeability fields, and desorption. These features cover the production mechanisms which are currently believed to be most relevant in tight gas and shale gas systems. We employ the numerical simulator to examine various tight gas and shale gas systems and to identify and illustrate the various flow regimes which progressively occur over time. We perform this study at fine grid discretization on the order of 1 mm near fractures to accurately capture flow effects at all time periods. We visualize the flow regimes using specialized plots of rate and pressure functions, as well as maps of pressure and sorption distributions. We use pressure maps to visualize the various flow regimes and their transitions in tight gas systems. In a typical tight gas system, we illustrate the initial linear flow into the hydraulic fractures (i.e., formation linear flow), transitioning to compound formation linear flow, and eventually transforming into elliptical flow. We explore variations of possible shale gas system models. Based on diffusive flow (with and without desorption), we show that due to the extremely low permeability of shale matrix (a few nanodarcies), the flow behavior is dominated by the extent of and configuration of the fractures. This work expands our understanding of flow behavior in tight gas and shale gas systems, where such an understanding may ultimately be used to estimate reservoir properties and reserves in these types of reservoirs.

Abstract:
It is increasingly claimed that the world is entering a ‘golden age of gas’, with the exploitation of unconventional resources expected to transform gas markets around the world. But the future development of these resources is subject to multiple uncertainties, particularly with regard to the size and recoverability of the physical resource. This paper assesses the currently available evidence on the size of unconventional gas resources at both the regional and global level. Focussing in particular on shale gas, it first explores the meaning and appropriate interpretation of the various terms and definitions used in resource estimation and then summarises and compares the different regional and global estimates that have been produced to date. It shows how these estimates have increased over time and highlights their variability, the wide range of uncertainty and the inadequate treatment of this uncertainty by most studies. The paper also addresses coal bed methane and tight gas and identifies those estimates that appear to be most robust for each region. The paper concludes that unconventional gas could represent 40% of the remaining technically recoverable resource of natural gas, but the level of uncertainty is extremely high and the economically recoverable resource could be substantially smaller.

Abstract:
Demand for natural gas in most countries of the Middle East and North Africa (MENA) region has, since the start of the 2000s, been growing at a much faster rate than supply, resulting in a costly deficit. The issue of domestic gas prices, which are kept at artificially-low levels by MENA governments, is a key feature of the region's gas supply–demand picture. This contribution analyses the political economy logic informing domestic gas pricing policies in the MENA region and argues that unless these are revised to take account of the new regional gas market realities, MENA's role in international gas markets will in future be more that of a growing demand and import centre than as a major source of new supply. It argues that, in spite of its limitations and short-term failures, the recent Iranian pricing reform experiment is a useful case study from which lessons can be learnt for other countries in the region.

Abstract:
This study evaluates the economic feasibility of five emergent shale gas plays on the European Continent. Each play is assessed using a uniform field development plan with 100 wells drilled at a rate of 10 wells/year in the first decade. The gas production from the realized wells is monitored over a 25 year life cycle. Discounted cash flow models are used to establish for each shale field the estimated ultimate recovery (EUR) that must be realized, using current technology cost, to achieve a profit. Our analyses of internal rates of return (IRR) and net present values (NPVs) indicate that the Polish and Austrian shale plays are the more robust, and appear profitable when the strict P90 assessment criterion is applied. In contrast, the Posidonia (Germany), Alum (Sweden) and a Turkish shale play assessed all have negative discounted cumulative cash flows for P90 wells, which puts these plays below the hurdle rate. The IRR for P90 wells is about 5% for all three plays, which suggests that a 10% improvement of the IRR by sweet spot targeting may lift these shale plays above the hurdle rate. Well productivity estimates will become better constrained over time as geological uncertainty is reduced and as technology improves during the progressive development of the shale gas fields.

Abstract:
Low natural gas prices and stricter, federal emission regulations are promoting a shift away from coal power plants and toward natural gas plants as the lowest-cost means of generating electricity in the United States. By estimating the cost of electricity generation (COE) for 304 coal and 358 natural gas plants, we show that the economic viability of 9% of current coal capacity is challenged by low natural gas prices, while another 56% would be challenged by the stricter emission regulations. Under the current regulations, coal plants would again become the dominant least-cost generation option should the ratio of average natural gas to coal prices (NG2CP) rise to 1.8 (it was 1.42 in February 2012). If the more stringent emission standards are enforced, however, natural gas plants would remain cost competitive with a majority of coal plants for NG2CPs up to 4.3.

Abstract:
It is often assumed that natural gas exploration and development in the Marcellus Shale will bring great economic prosperity to state and local economies. Policymakers need accurate economic information on which to base decisions regarding permitting and regulation of shale gas extraction. This paper provides a summary review of research findings on the economic impacts of extractive industries, with an emphasis on peer-reviewed studies. The conclusions from the studies are varied and imply that further research, on a case-by-case basis, is necessary before definitive conclusions can be made regarding both short- and long-term implications for state and local economies.

Abstract:
How tangible are the costs of natural gas compared to the benefits of one of the fastest growing sources of electricity – wind energy – in the United States? To answer this question, this article calculates the benefits of wind energy derived from two locations: the 580 MW wind farm at Altamont Pass, CA, and the 22 MW wind farm in Sawtooth, ID. Both wind farms have environmental and economic benefits that should be considered when evaluating the comparative costs of natural gas and wind energy. Though there are uncertainties within the data collected, for the period 2012–2031, the turbines at Altamont Pass will likely avoid anywhere from $560 million to $4.38 billion in human health and climate related externalities, and the turbines at Sawtooth will likely avoid $18 million to $104 million of human health and climate-related externalities. Translating these negative externalities into a cost per kWh of electricity, we estimate that Altamont will avoid costs of 1.8–11.8 cents/kWh and Sawtooth will avoid costs of 1.5–8.2 cents/kWh.

Abstract:
This letter provides a first-order estimate of conventional air pollutant emissions, and the monetary value of the associated environmental and health damages, from the extraction of unconventional shale gas in Pennsylvania. Region-wide estimated damages ranged from $7.2 to $32 million dollars for 2011. The emissions from Pennsylvania shale gas extraction represented only a few per cent of total statewide emissions, and the resulting statewide damages were less than those estimated for each of the state’s largest coal-based power plants. On the other hand, in counties where activities are concentrated, NO x emissions from all shale gas activities were 20–40 times higher than allowable for a single minor source, despite the fact that individual new gas industry facilities generally fall below the major source threshold for NO x . Most emissions are related to ongoing activities, i.e., gas production and compression, which can be expected to persist beyond initial development and which are largely unrelated to the unconventional nature of the resource. Regulatory agencies and the shale gas industry, in developing regulations and best practices, should consider air emissions from these long-term activities, especially if development occurs in more populated areas of the state where per-ton emissions damages are significantly higher.

Abstract:
This research was funded by the Susquehanna Heartland Coalition for Environmental Studies (SHCES), an organization that "exists to promote collaboration in research, provide environmental education, improve water quality, and address other environmental concerns related to the Susquehanna River Watershed." All statements and conclusions expressed in this manuscript do not represent the views of SHCES or those of Bucknell University. Neither SHCES nor Bucknell influenced the writing of this document or assumed any editing authority. This paper utilizes a Contingent Valuation Method survey of a random sample of residents to estimate that households are willing to pay an average of US$12.00 per month for public projects designed to improve river access and US$10.46 per month for additional safety measures that would eliminate risks to local watersheds from drilling for natural gas from underground shale formations. These estimates can be compared with the costs of providing each of these two amenities to help foster the formation of efficient policy decisions.

Abstract:
Many studies find that areas more dependent on natural resources grow more slowly – a relationship known as the resource curse. For counties in the south-central U.S., I find little evidence of an emerging curse from greater natural gas production in the 2000s. Each gas-related mining job created more than one nonmining job, indicating that counties did not become more dependent on mining as measured by employment. Increases in population largely mitigated a rise in earnings per job and crowding out. Furthermore, changes in the adult population by education level reveal that greater production did not lead to a less educated population.

Abstract:
Unconventional natural gas drilling in Pennsylvania has accelerated over the past five years, and is unlikely to abate soon. Dairy farming is a large component of Pennsylvania's agricultural economy. This study compares milk production, number of cows, and production per cow in counties with significant unconventional drilling activity to that in neighboring counties with less unconventional drilling activity, from 1996 through 2011. Milk production and milk cows decreased in most counties since 1996, with larger decreases occurring from 2007 through 2011 (when unconventional drilling increased substantially) in five counties with the most wells drilled compared to six adjacent counties with fewer than 100 wells drilled. While this descriptive study cannot draw a causal association between well drilling and decline in cows or milk production, given the importance of Pennsylvania's dairy industry and the projected increase in unconventional natural gas drilling, further research to prevent unintended economic and public health consequences is imperative.

Abstract:
Improvements in technology have made it profitable to tap unconventional gas reservoirs in relatively impermeable shale and sandstone deposits, which are spread throughout the U.S., mostly in rural areas. Proponents of gas drilling point to the activity's local economic benefits yet no empirical studies have systematically documented the magnitude or distribution of economic gains. I estimate these gains for counties in Colorado, Texas, and Wyoming, three states where natural gas production expanded substantially since the late 1990s. I find that a large increase in the value of gas production caused modest increases in employment, wage and salary income, and median household income. The results suggest that each million dollars in gas production created 2.35 jobs in the county of production, which led to an annualized increase in employment that was 1.5% of the pre-boom level for the average gas boom county. Comparisons show that ex-ante estimates of the number of jobs created by developing the Fayetteville and Marcellus shale gas formations may have been too large.

Abstract:
What significance will developments in shale gas production have for European gas prices? Some commentators paint a gloomy picture of the future gas markets. But most forecasts for the oil market are positive. Consequently, a view appears to prevail that price trends will differ sharply between oil and gas markets. This article looks at developments in US shale gas production and discusses their impact on the movement of European gas prices. The relationship between oil and gas prices over time is also analysed.

Abstract:
The growing interdependence of the nation's electricity and natural gas systems presents challenges to the reliable and efficient operation of both systems. Shale gas developments, retirement of aging fossil units, and increases in variable renewable generation are likely to increase the prominence of natural-gas-fired generation and interdependence risks. The authors review factors at the intersection of electricity and natural gas markets and operations, and present ways to address the risks.

Abstract:
The Haynesville shale in Louisiana is one of several unconventional gas plays that have been discovered in the U.S. in the past decade and promise to dramatically change the course of future energy development given its enormous resource potential. Unconventional gas resources are abundant, but their development is particularly sensitive to technologic risk, geologic uncertainty, and gas price. To produce at commercial rates, shale gas wells require horizontal drilling and hydraulic fracturing which significantly increases the capital cost. The purpose of this paper is to examine the price sensitivity of Haynesville wells and the economic viability of the play. We characterize the operating envelope under which Haynesville wells are economic and describe the profit space based on a review of production and cost characteristics. The majority of Haynesville wells fail to break-even on a full-cycle basis at prevailing gas prices. This harsh economic reality will control future activity after new entrants fulfill their drilling requirements. For $5/Mcf gas, the average Haynesville well is expected to generate a 10% return when drilling and completion costs are $7 million and operating expenditures are $1/Mcf. We explore two-variable factor models using type curves and introduce functional relations for the multiple variable case.

Abstract:
Unconventional gas resources in the U.S. are abundant, but their development is capital intensive and subject to technologic risk, geologic uncertainty, and gas price volatility. In the Haynesville shale, wells are characterized by high initial production rates and rapid decline, and it is the tradeoff between these conditions and high investment that define the profitability of the play. The purpose of this paper is to examine the economic viability and sustainability of the Haynesville shale play. We characterize the operating envelope under which Haynesville wells are economic and describe the profit space based on a technical review of production and cost characteristics in the region. We explore two-variable factor models using type curves and construct before and after tax functional relationships. The majority of Haynesville wells fail to break-even on a full-cycle basis at prevailing gas prices. For $6/Mcf gas, average producers are expected to generate pre-tax returns between 1 and 11.5% for 1 to $0.5/Mcf operating expenses and $7.5 million capital expenditure. P10 wells are expected to generate a pre-tax return of 52 to 25% for $7.5 to $10 million capital expenditures and post-tax returns of 40 to 20%. We show that gas prices in the first year of production are an important determinant of well profitability.

Abstract:
Based on an analysis comparing the 580 MW Altamont Pass wind farm in California and the 22 MW Sawtooth wind farm in Idaho with natural gas-fired generation, this article finds that wind energy provides significant and quantifiable human health, wildlife, and climate change benefits not normally considered by energy planners and utility operators. These benefits make wind energy far cheaper than natural gas.

Abstract:
Improperly abandoned gas wells threaten human health and safety as well as pollute the air and water. In the next 20 years, tens of thousands of new gas wells will be drilled into the Marcellus, Utica, and Upper Devonian shale formations of Pennsylvania. Pennsylvania currently requires production companies to post a bond to ensure environmental reclamation of abandoned well sites, but the size of the bond covers only a small fraction of the site reclamation costs. The economics of shale gas development favor transfer of assets from large entities to smaller ones. With the assets go the liabilities, and without a mechanism to prevent the new owners from assuming reclamation liabilities beyond their means, the economics favor default on well-plugging and site restoration obligations. Policy options and alternatives to bonding are discussed and evaluated.

Abstract:
Recent advances in drilling technology have allowed for the profitable extraction of natural gas from deep underground shale rock formations. Several reports sponsored by the gas industry have estimated the economic effects of the shale gas extraction on incomes, employment, and tax revenues. None of these reports has been published in an economics journal and therefore have not been subjected to the peer review process. Yet these reports may be influential to the formation of public policy. This commentary provides written reviews of several studies purporting to estimate the economic impact of gas extraction from shale beds. Due to questionable assumptions, the economic impacts estimated in these reports are very likely overstated.

Abstract:
With Sichuan Basin as focus, this paper introduces the depositional environment, geochemical and reservoir characteristics, gas concentration and prospective resource potential of three different types of shale in China: marine shale, marine-terrigenous shale and terrigenous shale. Marine shale features high organic abundance (TOC: 1.0%–5.5%), high-over maturity (Ro: 2%–5%), rich accumulation of shale gas (gas concentration: 1.17–6.02 m3/t) and mainly continental shelf deposition, mainly distributed in the Paleozoic in the Yangtze area, Southern China, the Paleozoic in Northern China Platform and the Cambrian-Ordovician in Tarim Basin; Marine-terrigenous coalbed carbonaceous shale has high organic abundance (TOC: 2.6%–5.4%) and medium maturity (Ro: 1.1%–2.5%); terrigenous shale in the Mesozoic and Cenozoic has high organic abundance (TOC: 0.5%–22.0%) and mid-low maturity (Ro: 0.6–1.5%). The study on shale reservoirs in the Lower Paleozoic in Sichuan Basin discoveried nanometer-sized pores for the first time, and Cambrian and Silurian marine shale developed lots of micro- and nanometer-sized pores (100–200 nm), which is quite similar to the conditions in North America. Through comprehensive evaluation, it is thought that several shale gas intervals in Sichuan Basin are the practical targets for shale gas exploration and development, and that the Weiyuan-Changning area in the Mid-South of Sichuan Basin, which is characterized by high thermal evolution degree (Ro: 2.0%–4.0%), high porosity (3.0%–4.8%), high gas concentration (2.82–3.28 m3/t), high brittle mineral content (40%–80%) and proper burial depth (1500–4500 m), is the core area for shale gas exploration and development, the daily gas production for Well Wei 201 is 1×104–2×104 m3. ： 以四川盆地为重点，介绍中国海相、海陆过渡相、陆相三大类型页岩形成的沉积环境、地球化学与储集层特征、含气量与远景资源量。中国海相页岩是一套高有机质丰度（TOC为1.0%～5.5%）、高—过成熟（Ro值为2.0%～5.0%）、富含页岩气（含气量1.17～6.02 m3/t）、以陆棚相为主的沉积，主要分布在华南扬子地区古生界、华北地台古生界和塔里木盆地寒武系—奥陶系；海陆过渡相煤系炭质页岩有机质丰度高（TOC为2.6%～5.4%）、成熟度适中（Ro值为1.1%～2.5%）；中新生界陆相页岩有机质丰度高（TOC为0.5%～22.0%）、低熟—成熟（Ro值为0.6%～1.5%）。在对四川盆地下古生界页岩储集层研究中首次发现，寒武系和志留系海相页岩发育大量与北美地区相似的微米—纳米级孔隙。综合评价认为四川盆地发育的多套页岩气层系是勘探开发的现实领域，四川盆地中南部威远—长宁等地区的寒武系和志留系是页岩气勘探开发的核心区与层系，其特点是：热演化程度较高（Ro值为2.0%～4.0%）、孔隙度较高（3.0%～4.8%），含气量较高（2.82～3.28 m3/t）、脆性矿物含量较高（40%～80%）、埋深适中（1 500～4 500 m），有利于开采。图7表7参38

Abstract:
Both the number of oil and gas wells drilled annually2 (U.S. Department of Interior [U.S.D.I.], Bureau of Land Management 2009) and the number of producing natural gas wells3 (U.S. Department of Energy 2009) in the Rocky Mountain region4 more than doubled from 1998 to 2008. The proportion of U.S. natural gas production from the region increased from 16% in 1997 to 23% in 2007 (U. S. Department of Energy 2009) and the number of drilling rigs operating in the region grew from 131 in 2002 to 318 in 2009.5 This increase in natural gas drilling in the region has created boomtown conditions in several rural communities. While energy development can benefit rural communities, boomtowns in the Rockies experienced an influx of non-local workers, a rise in crime and emergency service calls, increased demand for public services, more wear and tear on local infrastructure, and upward pressure on local wages and housing costs. Natural gas prices had dropped dramatically by 2009, the drilling boom had subsided, and the bust phase may have begun (Figure 1). The recent energy boom-bust begs the question—how can communities learn from recent history to better take advantage of future energy development for both short-term and long-term benefits?