US Natural Gas Production Research Articles

Potential Underestimate in Reported Bottom-up Methane Emissions from Oil and Gas Operations in the Delaware Basin

Methane is a greenhouse gas and identified as a key driver of near-term climate change. Bottom-up approaches estimate annual methane loss from US natural gas production and transport at 6 Tg, but recent studies suggest this may be an underestimate. To investigate this possibility, an equipment-based emissions inventory, using EPA emission factors, was developed to calculate methane emissions from oil and gas operations in the Delaware basin, USA. Emission factors and activity data were then updated using contemporary and region-specific measurement data. The original inventory estimated emissions at 315 Gg CH4 y−1 (gas production-normalized rate of 0.6% loss), while the updated inventory estimated emissions of 1500 Gg CH4 y−1 (2.8% loss). The largest changes resulted from large fugitive emissions from oil production (+430 Gg CH4 y−1), updating maintenance activity emissions (+214 Gg CH4 y−1), considering flaring inefficiency (+174 Gg CH4 y−1), and the inclusion of associated gas venting (+136 Gg CH4 y−1). This study suggests that a systematic underestimate probably exists in current bottom-up inventories and identifies sources currently missing or may be incorrect. We also strongly recommend that emission factors should be validated through direct comparison against measurement campaigns that include long-tail distributions typical of oil and gas activities.

Journey to an “A” Grade Gas Certification

The August 2022 issue of JPT featured an article on the most common voluntary certifications that have at least some kind of methane emissions-related requirements. Since then, MiQ appears to have become a certification framework of choice for many industry players. According to Georges Tijbosch, CEO of MiQ, as of January 2023, about 20% of US natural gas production has gone through the MiQ process. Tijbosch noted that most of the currently certified production received grades A, B, or C. While this is no high school, we naturally tend to assume that getting an “A” is the ultimate goal of getting certified. It might be true for some; however, as we all realize after graduating schools and universities and upon entering the workforce, life is quite often more about continuous improvement over time vs. achieving the top grade as such. This article is aimed at exploring the MiQ grading framework in more detail and explaining practical pathways for industry participants to achieve any desired MiQ grade. For simplicity, we will focus on the MiQ Standard—Onshore Production, but the fundamental concepts are applicable to other industry segments. The MiQ Standard scores a facility based on three broad categories. - Methane-intensity quantitative metric - Monitoring technology deployment - Company practices related to the methane emissions management Each of these categories is scored by an auditor accredited to conduct MiQ audits and who is an independent subject matter expert in the fields of methane mitigation, monitoring, and accounting. The combined score across the three categories results in a letter grade on the MiQ certificate issued for that facility’s production. Natural gas buyers (typically utility companies or industrial users) then request certain volumes of certified gas and, depending on the targeted end use and other factors, may specify a desired grade. Roy Hartstein is an emissions subject matter expert, as well as founder and president of Responsible Energy Solutions, an organization that performs certification assessments and helps companies prepare for certification. Hartstein and his team have conducted over a dozen MiQ audits. He talks about three aspects of value that motivate natural gas producers to improve from a non-A to an A grade: 1) possibility of earning a higher premium on the sold certified gas; 2) internal risk management across several avenues such as safety, identification of malfunctioning equipment, or early detection of operational inefficiencies; and 3) alleviating environmental concerns of the investment community. He believes this advances a long-term strategy to secure oil and gas’s potential as part of the future energy mix. Regardless of the underlying motivation, most of us like to think we are straight-A students and don’t want to bring home a report card with a lower grade. But at the time a company initiates the certification process, they may find they qualify for a lower (i.e., non-A) grade. What are the potential implications of this?

Permian Basin Power Surge

_ Like its salty neighbor to the east, the Permian Basin of west Texas and southeastern New Mexico has been proclaimed dead on many occasions. Such proclamations of their demise, however, are mere exaggerations as the Gulf of Mexico and the Permian Basin continue to thrive. These historic oil and gas production powerhouses have delivered to global markets billions of barrels of oil and trillions of cubic feet of natural gas over the past century. Through the booms and the busts, the resiliency of each was made possible by the combination of ingenuity and perseverance and by advancements in techniques and technologies. Specifically, the Permian’s unconventional resources were “opened by the confluence of two major technologies—horizontal drilling and hydraulic fracturing—more than a decade ago. And since then, we have not stopped,” Nicole Champenoy, director of Chevron’s shale and tight-asset class division, said at the recent SPE Permian Basin Energy Conference (PBEC) held in Midland, Texas. “From incredible advances across the board—from completions optimization to execution efficiencies where one rig today is doing the work of three rigs from several years ago—the list goes on and on. We did that in a decade. The innovation and technology we have deployed has been remarkable,” she said. Growth Engines The basin’s remarkable success occurred in a decade that saw more than one market downturn and was capped off with a crude-oil supply glut eliminated by the global COVID-19 pandemic. Before the widespread pandemic-related closures began, the Permian produced 4.9 million B/D in March 2020, with production a year later dropping to 3.6 million B/D in February 2021, according to the US Energy Information Administration (EIA) data. Two years later, in March 2022, production finally shattered the 5 million B/D mark just as the world began to emerge from the pandemic. In November production in the region stands at more than 5.4 million B/D, according to the EIA’s Drilling Productivity Report. The Permian continues its reign as the largest oil-producing region in the US, with the Eagle Ford of south Texas and North Dakota’s Bakken plays coming in at 1.2 million and 1.1 million B/D, respectively. As for natural gas, the Permian produced more than 21.2 MMcf/D, second only to the Appalachia region’s production of 35.4 MMcf/D, per the EIA data. The US is on track to produce 11.8 million B/D in 2022, with that number growing to 12.3 million B/D in 2023, according to the EIA’s Short-Term Energy Outlook. Much of that oil will likely come from the Permian. In June 2022, the basin accounted for about 43% of US crude oil production and 17% of US natural gas production, the EIA said. “When we talk about the growth engines of the US hydrocarbon system, they are the Permian’s Midland and Delaware basins,” Chris Paulsen, vice president of business development and strategy for Pioneer Natural Resources, told PBEC attendees. “Everything else for the most part of the US is nominally increasing and not declining in terms of gas production.” He noted that it will be interesting to see how the growth trajectory plays out with companies pulling back on spending, citing concerns over ESG, free cash flow, and capital efficiency as inflation takes root. But he does see several positives that will help moving forward. “We’ve gone from standalone developments, growth at all costs, and a lot of urgency to people standing back and thinking about how to best complete reservoirs to ensure we’re not leaving behind hydrocarbons,” he said.

Attribution of production-stage methane emissions to assess spatial variability in the climate intensity of US natural gas consumption

Although natural gas is often viewed as a commodity fuel with limited variability due to standardization for pipeline transportation, life cycle impacts of natural gas vary substantially. Greenhouse gas (GHG) intensity is one of the most policy-relevant environmental characteristics of natural gas, particularly as decarbonization efforts proceed. Given that natural gas is mostly methane, a powerful GHG, methane emissions from the natural gas system contribute substantially to the GHG intensity of natural gas. Research has established that methane emissions from natural gas systems are climatically relevant and higher than long understood, in part due to variation in production-stage emissions by basin. This work combines recent estimates of basin-level US production-stage methane emissions, data on US natural gas production, consumption, and trade, and a spatial evaluation of pipeline connections between production basins and consumer states to generate first-order estimates of the production-stage methane emissions intensity of natural gas consumed in the United States. Although natural gas is a commodity product, the environmental footprint of a given unit of natural gas varies based on its origin and infrastructural needs. We find that production-stage methane emissions intensity of delivered natural gas by state varies from 0.9% to 3.6% (mass methane emitted from natural gas production sites per mass methane withdrawn). These production-stage emissions add 16%–65% (global warming potential (GWP)-100; 38%–157%, GWP-20) to combustion carbon dioxide emissions. Other sources of life cycle methane emissions downstream of production can be similar in magnitude. Natural gas consumed in Arizona, Kansas, and New Mexico has the highest estimated production-stage methane emissions intensity, largely due to reliance on high-emission basins. Limitations include emissions-related data gaps and sensitivity to allocation approaches, but results demonstrate decision-relevant variability in the GHG impact of natural gas.

Reduced methane recovery at high pressure due to methane trapping in shale nanopores

By 2050, shale gas production is expected to exceed three-quarters of total US natural gas production. However, current unconventional hydrocarbon gas recovery rates are only around 20%. Maximizing production of this natural resource thus necessitates improved understanding of the fundamental mechanisms underlying hydrocarbon retention within the nanoporous shale matrix. In this study, we integrated molecular simulation with high-pressure small-angle neutron scattering (SANS), an experimental technique uniquely capable of characterizing methane behavior in situ within shale nanopores at elevated pressures. Samples were created using Marcellus shale, a gas-generative formation comprising the largest natural gas field in the United States. Our results demonstrate that, contrary to the conventional wisdom that elevated drawdown pressure increases methane recovery, a higher peak pressure led to the trapping of dense, liquid-like methane in sub-2 nm radius nanopores, which comprise more than 90% of the measured nanopore volume, due to irreversible deformation of the kerogen matrix. These findings have critical implications for pressure management strategies to maximize hydrocarbon recovery, as well as broad implications for fluid behavior under confinement.

Surging US natural gas production sees summer prices sink to 20‐year lows

Oil and Energy TrendsVolume 44, Issue 9 p. 8-9 GAS AND POWER Surging US natural gas production sees summer prices sink to 20-year lows First published: 04 October 2019 https://doi.org/10.1111/oet.12730Read the full textAboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL Share a linkShare onFacebookTwitterLinked InRedditWechat No abstract is available for this article. Volume44, Issue9September 2019Pages 8-9 RelatedInformation

Lack of Critical Northeast Natural Gas Infrastructure Risks Regional Economic Development

At the start of the new millennium, technological advances in horizontal drilling and hydraulic fracturing have provided US producers with unprecedented access to vast natural gas reserves locked away in America's shale formations. Referred to as the Shale Revolution, the upsurge in US natural gas production has had a profound effect on the domestic and global energy landscape.

Guest Editorial: Growth in Unconventional Resources Adds to Technical Literature

Guest editorial Unconventional resources require technologies typically not used to produce conventional oil and gas reservoirs. In particular, starting in the late 1990s, the combination of horizontal wells and multistage hydraulic fracturing has been key to rapidly increasing success in exploiting unconventional resources. While the well completions in unconventional resources may be more expensive than those typically applied in conventional reservoirs, the advantage is access to the very large volumes of these resources, which include tight (low-permeability) gas in sandstone or carbonate rock, coalbed methane, and organic-rich source rocks classed as shale gas and tight oil. The exploitation of shale gas, along with tight gas and coalbed methane, enabled a stunning increase in US natural gas production of approximately 4 Tcf/D from 2005 to 2010. A similar story followed a few years later for US crude oil production. Tight oil production ramped up nearly 5 million B/D over approximately 5 years, starting in 2008, and continues to rise. And it is not just the US that is benefiting—unconventional resource development is now beginning to spread to other countries around the world. The technologies that accomplished these near miracles were developed, implemented, and continue to be improved largely by SPE members, and this has been reflected in an upsurge in conference presentations and journal publications related to unconventional resources over the past decade. This is illustrated by the chart (Fig. 1), which shows a dramatic increase in the percentage of peer-reviewed papers related to unconventional resources published in SPE Reservoir Evaluation & Engineering (SPEREE) beginning in 2011. Before 2011, there were only a handful of publications related to unconventional resources each year, primarily dealing with coal-bed methane and fundamentals of fluid flow in tight pore systems. Beginning in 2011, publications related to the analysis and prediction of shale gas reservoir production performance showed a sharp increase, followed a few years later by publications related to tight oil reservoir performance analysis and prediction. In addition, enhanced oil recovery from tight oil reservoirs has become an increasing area of focus. This year, over half of the publications in SPEREE will be related to unconventional resources. As further indication of the increasing importance of unconventional resources, in July SPE released Unconventional Gas and Tight Oil Exploitation, the first SPE monograph devoted exclusively to the topic.

Analyzing the Learning Path of US Shale Players by Using the Learning Curve Method

The US shale exploration and production (E&P) industry has grown since 2007 due to the development of new techniques such as hydraulic fracturing and horizontal drilling. As a result, the share of shale gas in the US natural gas production is almost 50%, and the share of tight oil in the US crude oil production is almost 52%. Even though oil and gas prices decreased sharply in 2014, the production amounts of shale gas and tight oil increased between 2014 and 2015. We show that many players in the US shale E&P industry succeeded in decreasing their production costs to maintain their business activity and production. However, most of the companies in the US petroleum E&P industry incurred losses in 2015 and 2016. Furthermore, crude oil and natural gas prices could not rebound to their 2015 price levels. Therefore, many companies in the US petroleum E&P industry need to increase their productivity to overcome the low commodity prices situation. Hence, to test the change in their productivity and analyze their ability to survive in the petroleum industry, this study calculates the learning rate using the US shale E&P players’ annual report data from 2008 to 2016. The result of the calculation is that the long-term learning rate is 1.87% and the short-term learning rate is 3.16%. This indicates a change in the technological development trend.

After Drop in Activity, Haynesville Shale Sees Resurgence

What was once old is now new again in US natural gas production. Once a crown jewel of shale in the US, the Haynesville has seen a resurgence in activity after a steady drop. Now, as natural gas consumption increases and the oil price remains low, companies are taking advantage of a potentially valuable opportunity in the area. Located in east Texas and northern Louisiana (Fig. 1) the Haynesville was the largest US producer of shale gas. In November 2011, it averaged a record high production of 10.4 Bcf/D—but as natural gas prices decreased in the years leading to the oil price downturn, other plays in the Appalachian region of the US such as the Marcellus and the Utica began to surpass it in production. By 2015, shale gas production in relatively liquids-rich areas such as the Eagle Ford and the Permian were also producing more than the Haynesville. The demise of the Haynesville appeared to be short-lived, though. In the past 18 months, the US Energy Information Administration (EIA) noted significant increases in drilling activity and well production rates, which have raised overall natural gas production in the region. Natural gas production reached 6.9 Bcf/D in September after remaining near 6.0 Bcf/D on average for the past 3 years. Beyond the Numbers Fig. 2 highlights some of the trends in the Haynesville. The EIA projected natural gas production to increase by 146 MMcf/D from October to November 2017. Rig count has nearly doubled from 2015 to the end of 2017. A drop in well costs has helped drive the surge in activity. In 2014, the Haynesville had the most expensive costs in the US primarily because of the challenges its fuel-bearing rocks presented. The formations were among the deepest in the country, with some as deep as 15,000 ft. In the Appalachian region, wells are in areas where formations range from 2,000- to 12,000-ft depth. The shale formation thickness in the Haynesville is slightly narrower than other US shale plays as well, ranging from 100 to 350 ft. In addition, the high pressure and temperature conditions led to stimulation treatments consisting of high-strength proppant and more thermally stable fluids. These fluids consisted of large polymer loadings of guar and sometimes derivatized guar gelling agents. Higher-quality resin-coated and ceramic prop-pants were commonly pumped as the primary proppant, increasing costs and forcing companies to adopt a strategy of “quality over quantity” in terms of production volumes (SPE 187315).

The causal relationship in North American energy production

Crude oil and natural gas production is examined to investigate the cross‐country causal relationship and interconnectedness of these markets, within the North American context. A vast infrastructure network, consisting of pipelines and railroads that connect the US and Canadian markets, with virtually all of Canada's crude oil and natural gas exports flowing south. The study is undertaken within the context of the recent US shale energy revolution based on technological advancements in drilling and hydraulic fracturing. Unique to this study is the use of production data, rather than the archetypal energy prices, to investigate the presence of bilateral relationships. Monthly, country level data on crude oil and natural gas production, over the period 2002 through 2015, is utilised. The results of standard unit root tests indicate that the production series are non‐stationary in levels, while cointegration test indicate that the markets are integrated. A bidirectional relationship is found for the crude oil market. In contrast, a unidirectional relationship is observed in the gas market – US natural gas production causes Canadian natural gas production.

A Retrospective Review of Shale Gas Development in the United States: What Led to the Boom?

In the past decade or so, natural gas produced from shale formations (shale gas), experienced an extraordinary boom in the United States, accounting for only 1.6 percent of total US natural gas production in 2000 but an astonishing 40.4 percent by 2012. This remarkable growth has spurred interest in exploring for shale gas resources elsewhere. A number of countries, including China, Mexico, Argentina, Poland, India, and Australia are beginning to develop their own shale gas resources. Although it is difficult to know definitively the necessary or sufficient conditions for stoking a shale gas boom, a historical review of the US experience can be informative.

Revitalizing Mature-Basin Liquids-Rich Plays: Tactics, Techniques, and Technology

Conference Review - 2014 SPE Liquids-Rich Basins Conference Learn, strategize, persevere, and optimize: In a nutshell, this was the message imparted in the eight sessions’ 24 presentations and the keynote luncheon speech at the SPE Liquids-Rich Basins Conference (LRBC), held 24–25 September in Fort Worth, Texas. Conference presenters talked mainly about US basins and plays. However, this summary focuses on presentations that might also yield insight into onshore unconventional plays around the world. Production Overabundance With US natural gas production at well over 70 Bcf/D, Dave Pursell, research principal at Tudor, Pickering, Holt, & Company, asked “What do we do with all this gas?” (Fig. 1.) He said natural gas liquids volumes are understated because producers are rejecting a lot of ethane and leaving it in the gas line. Ethane is used to make one of the world’s principal industrial chemicals, ethylene (also known as ethene). Ethylene is the most important organic chemical, by tonnage, that humans manufacture. It is a building block for a vast range of chemicals. Pursell thinks that the US might begin exporting ethane if prices improve. He also said that, in the US, “gas is terrible. It’s always going to be terrible. LNG [liquefied natural gas] can’t come soon enough.” A massive amount of processing and refining construction is under way along the US Gulf Coast, from Corpus Christi, Texas, to Mobile, Alabama, he said. But there is a labor shortage and a project backlog. In addition, projects are overbudget. Pursell points to high material costs and a lack of skilled labor as the primary roadblocks. “The peak oilers are right, the US has peaked—on conventionals— but they didn’t foresee the rise of unconventionals,” he said. The Myth of Sweet Spot Exploration “Sweet spot exploration is a destructive holdover from a ‘conventional’ mindset— that we want to drill the best possible location first,” said Bill Haskett, senior principal–energy strategy at Decision Strategies. “That tends to drive decisions, but it’s not good.” Above all, said Haskett, “You have to have good rock. Nothing can save you if you don’t.” In actuality, he said, with tight shales, “it’s only the top 10% to 20%— or maybe top quartile—that’s superior to your other wells. But most times we can’t predict coming in.” To just extrapolate from sweet spots, he said, “is statistically improper sampling and also impedes learning.” Haskett said the best approach is to implement a pilot—but with the caveat that “A pilot needs to characterize the opportunity as a whole. It should not attempt to high-grade the area of potential.”

Inshore Floating LNG for Liquefaction of Onshore Shale Gas

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 24091, ’Development Options for North American LNG Export: The Merits of Inshore-Deployed FLNG for Liquefaction of Onshore Shale Gas and Examination of Principal Technology Drivers,’ by Joe Verghese, WorleyParsons Europe, and Nancy Ballout, WorleyParsons Houston, prepared for the 2013 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2013 Offshore Technology Conference. Reproduced by permission. The advent of shale-gas production onshore North America, the resulting overhang of gas supplies, and the downward pressure on gas prices have led operators to consider the possibilities of liquid-natural-gas (LNG) liquefaction plants for the export of LNG from coastal locations to international markets. Several proposals for onshore liquefaction relate to the conversion of existing LNG regasification sites. The paper assesses the technology implications of migrating LNG floating production, storage, and offloading (FPSO) concepts to inshore service. Market Context The energy markets have seen a remarkable evolution in gas developments driven by a number of factors including the relative abundance of this energy resource and its global availability, flexibility in use, and low carbon number. According to the International Energy Agency (IEA), gas will increase its share of the global energy mix from 21% in 2009 to 25% by 2035. Against this backdrop, the shale-gas revolution in North America has already led to gas self-sufficiency, with North America poised to be a net exporter by 2016. According to the IEA, the introduction of horizontal drilling, hydrofracturing, and resource targeting technologies has led to a 27% increase in natural-gas production, from 2005 levels to 23 Tcf in 2011 (Fig. 1). A further increase of 44% from this 2011 level is foreseen by 2040. US natural-gas production has outpaced growth in demand by a ratio of 2:1 since 2005, leading to downward pressure on natural-gas prices. These factors have prompted owners of existing LNG regasification terminals to sense a shift in the demand/supply balance, and to seek approval to install liquefaction facilities for export of LNG. By the end of May 2012, 15 applications had been submitted to the US Department of Energy for export authorization, amounting to a staggering 145 million t/a of capacity. The sweet spot for floating liquefaction units lies precisely in the greenfield phase of the LNG-export scenario. For greenfield developments, the atshore or inshore deployment of floating LNG (FLNG) can offer interesting advantages over its onshore counterpart. These include potential for faster permitting, a faster construction schedule, and significant potentials for standardization and redeployment.

Comments: The Embargo at 40

Editor's column Forty years ago, the global oil market faced shortages, price shocks, and unanswered questions about security of supply. The global oil landscape is drastically different today, and many of the changes grew out of the events that occurred 4 decades ago. The most dramatic recent change is the growth in US production, revitalized by shale and tight oil output. The United States has drastically reduced its reliance on imported oil and is predicted to soon be the largest producer in the world, surpassing Saudi Arabia and Russia. US oil production has grown more than 50% in the past 5 years, and petroleum imports have fallen from a high of 60% in 2005 to 35% today, according to IHS CERA. That 35% figure is the same as in 1973, when the so-called Arab oil embargo jolted the US and other developed countries into realizing the significance of their dependence on oil supplies from the Middle East and the political and economic ramifications of that reliance. In addition to oil, US natural gas production has risen by a third since 2005, and shale gas now accounts for more than 40% of total gas output. Long thought a reliable future customer of natural gas, the US is now retrofitting import terminals into gas export facilities. The 1973 oil embargo—along with consumer governments’ reactive policies such as price controls—helped create gasoline shortages and political panic. It also spawned the encouragement of technological innovation and the opening of new frontiers for oil exploration and production. Developments in the North Sea, Alaska, deepwater US Gulf of Mexico and west Africa, and Canadian oil sands, as well as the growth of other non-OPEC production followed. Since 1973, OPEC production has remained relatively flat at 30 million BOPD, while non-OPEC production has doubled from 27 million BOPD. The crisis also led to increased consumption efficiency and research into alternative forms of energy. After the oil crisis, the leading consuming countries created the International Energy Agency to help guide the need to increase energy security and developed initiatives, such as the Strategic Petroleum Reserve to guard against shortages and potential price spikes. While OPEC members and national oil companies (NOCs) have lost market share since that time, they still own the vast majority of the world’s reserves and are much less beholden to private international oil companies (IOCs). NOCs have become much more technically and financially savvy, calling the shots inside their countries and competing head to head outside their countries. NOCs no longer have to rely on large operators to develop their resources. They have the ability to manage projects and apply the latest technology, or can seek help from the large service companies, which are increasingly offering one-stop shop project expertise.

Water production in enhanced coalbed methane operations

Coalbed methane (CBM) formations provides a considerable amount of the US natural gas production and have the potential of storing significant amounts of carbon dioxide (CO2) through enhanced gas recovery operations. Enhanced coalbed methane (ECBM) recovery by injection of CO2 or a mixture of CO2 and nitrogen (N2) has been proven to recover additional natural gas resources. However, since coalbeds are normally saturated with water and can be in communication with an aquifer, a large amount of water is often co-produced during the natural gas extraction.The conventional approach for CBM production relies on the reduction of the gas partial pressure in the coal seam. This can be accomplished by either pumping the formation water to the surface and/or by injecting gases such as N2 and CO2. Disposal of the produced water is an environmental challenge as harmful impurities must be removed by appropriate purification techniques. Consequently, a reduction of water production in CBM operations is desirable.In this paper we present a numerical investigation of the potential reduction in water production during ECBM operations that are commonly used to increase methane (CH4) recovery. We use a three-dimensional coalbed model with an aquifer located at the bottom to investigate the amounts of gas and water produced in ECBM operations per volume of coal seam as a function of aquifer strength and sorption characteristics including sorption induced strain. The amount of gas/water that is produced varies significantly depending on the aquifer strength and injection gas composition. We demonstrate that injection of CO2 and/or N2 in some settings reduces the water handling problem substantially.CBM is an important worldwide energy source with a large number of formations being excellent candidates for ECBM recovery processes. Our analysis of the interplay between coal characteristics, aquifer support and the resultant behavior in terms of gas/water production provides valuable input for optimization of future planning and operations.

Shale gas--the unfolding story

In the early 2000s US gas production was in slow but steady decline despite increasing drilling activity. As US natural gas prices rose in response to the resulting tight market, the only supply-side solution appeared to lie in the development of liquefied natural gas (LNG) projects in the Middle East and Africa for importation to the North American market. Almost unnoticed in its early stages, the US shale gas phenomenon gathered momentum from 2004 onwards through the combination and application of two proven technologies, namely horizontal drilling and pressure-induced hydraulic fracturing or 'fracking'. The pioneers of this approach were not the majors but the much smaller, domestically focused 'independent' upstream companies who, together with a well-established and adaptable service sector, instigated what is now commonly referred to as the 'shale gas boom' and which has increased US natural gas production to the point where only minimal imports of LNG are expected to be required for the foreseeable future. This paper looks at the genesis of the US shale gas industry, the intensive nature of its operations, and the factors which have underpinned its success to date. It also addresses the question of whether similar developments might be expected in Europe and what specific challenges would need to be overcome. In a world where increased LNG supply has created trade flow and price linkages between regional gas markets, the paper also examines the impact US shale production has had on other markets through the re-direction of LNG originally intended for the US market.

Comments: Fracturing Threat

Editor's column Legislation introduced in the US could place heavy restrictions on the widespread use of hydraulic fracturing, resulting in higher drilling costs and production delays. With a new administration and Congress in place, the US oil and gas industry appears to be facing a new era of regulation. Three Democratic congressmen introduced a bill in June that would eliminate an exemption for hydraulic fracturing under the federal Safe Drinking Water Act. Currently, individual states in the US regulate fracturing but not the federal government. The legislators claim that fracturing may be releasing harmful chemicals and contaminating underground water reservoirs. No federal or state studies have concluded that fracturing contaminates the water supply or has caused health problems. The exemption for hydraulic fracturing was part of the 2005 energy bill passed by Congress during the Bush administration and followed a US Environmental Protection Agency (EPA) report that found little or no threat to drinking water from fracturing. And in a report earlier this year, the US Department of Energy stated that "ground water is protected during the shale gas fracturing process by a combination of the casing and cement that is installed when the well is drilled and the thousands of feet of rock between the fracture zone and any fresh or treatable aquifers." The industry, including the American Petroleum Institute and the Independent Petroleum Producers Association, is gearing up for battle over regulating this common production practice. Fracturing is widely used in the US, and is critical in some of the country's biggest production areas, including the Haynesville, Barnett, and Marcellus shale plays as well as tight gas production in the Rocky Mountains region in the western US. The proposed legislation could give the EPA power to limit the type of fluids used in hydraulic fracturing, control chemicals used in the practice, or prohibit hydraulic fracturing altogether. The proposed bill also would require companies to detail what chemicals or additives they use in fracturing, information that is usually considered proprietary. Fracturing fluids are generally water-based fluids mixed with additives to help the water carry sand proppant into fractures. Water and sand make up 98–99% of fracture fluid, with the rest chemical additives. The use of fracturing is one reason why shale gas production has become economically feasible in the past few years. Eliminating the use of fracturing would cause a 45% drop in US natural gas production and a 17% decline in oil production within 5 years and continued declines after that, according to a study by IHS Herold. Restricting fracturing fluids would cut gas and oil production by 22% and 8%, respectively, while restricting chemical injection would lead to a 10% fall in gas output, according to the study. In addition, more regulation in this area would lead to higher costs, delays in drilling plans, and the possibility of litigation.

Reservoir and fracturing engineering challenges in tight gas development

Development of tight gas in continental North America has a long history. Some of the early attempts at stimulating and producing economically from microdarcy formations date back to the 1970s (Holditch et al., 1971, Fast et al., 1977, Wyman, 1980). The US price incentives in the Natural Gas Policy Act of 1978 spurred technology development, most notably massive hydraulic fracturing (MHF). Since then improvements in fracturing technology have continued unabated. Horizontal wells and more recently multi-stage hydraulically fractured horizontal wells represent the state of the art. Continued improvements in exploration/imaging tools, and advances in reservoir engineering interpretation techniques have helped identify what is actually occurring in the field. All of these factors have made tight gas a significant part of the current North American gas production. Kuuskraa (2006) estimated that unconventional gas (including tight gas, coalbed methane and shale gas) accounted for 40% of US natural gas production in 2004, and is rising every year.