By Lindsay Morris, Associate Editor
In January 2011, the Energy Information Administration released a preview of its Annual Energy Outlook. One result of the outlook: the U.S. has twice the amount of projected recoverable natural gas than previously thought, totaling 827 trillion cubic feet. Not only is the gas supply apparently abundant, but other reasons for power players to investigate gas alternatives also exist. Studies estimate that anywhere from 30 to 70 GW of coal-fired generation will retire in the next couple decades in order to meet Environmental Protection Agency emissions rules. And with its ability to cut emissions in half compared to what coal-fired units produced, gas is touted as a gateway to the future of power production in the U.S.
|Devon Energy’s discovery in the Cana shale in western Oklahoma has netted over 11 trillion cubic feet. Photo courtesy Devon Energy.|
Power Engineering magazine Associate Editor Lindsay Morris moderated this year’s Gas Development Executive Roundtable, which discussed increased demand for natural gas in the midst of coal-fired retirements and nuclear uncertainty, price volatility and supply chain issues.
Participants included Ed Walsh, executive vice president of Black & Veatch’s global energy business; Larry Nichols, CEO, Devon Energy; Darryl Shoemaker, director, Power and Energy Sector, HDR Inc.; John Adams, senior vice president of Power Operations, Calpine; and Martin Boller, vice president Sales & Marketing, Alstom Gas Business.
A year ago our roundtable participants used the term “pockets of opportunity” to describe a still-recovering market for new gas-fired generation. Is the demand for new gas-fired generation any broader than it was a year ago?
Ed Walsh: We think it is broader. Black & Veatch has done an energy market forecast which projects our generation demand for natural gas will grow about 2.6 percent year over year between now and 2035. Along with that, we also think that by 2035 natural gas will account for almost 40 percent of the nation’s energy mix, which would be a doubling of where it is today at about 20 percent. Part of the reason we are encouraged and bullish by those statistics is that if you look at the summer peaks that we reached last year, there were a lot of regions whose peaks were very close to what we saw in 2006. To us, that indicates a potential end to the period where we actually lost load growth. We think that’s positive for the industry.
Larry Nichols: It’s been a dramatic change during the last three years as utilities became aware of this incredible resource that we’ve developed. Hardly a week goes by that you don’t see a utility announcing that they’re going to build a new gas-fired plant or due course to convert a coal-fired plant to gas.
Martin Boller: Looking at a more global perspective, we believe there will be significant growth of gas from its load in 2010 over the next years to come back to pre-crisis levels in the next three to five years and then grow further. There are, of course, many drivers on this side. With GDP growth in electricity for the developing economies, we see a significant growth coming back already from the pre-crisis levels, particularly in the Middle East and in Asia. Certainly North America and Europe, particularly, are lagging behind with lower GDP growth for the last three years. And energy demand in these markets is still below pre-crisis level. It will be a while before European market demand revives.
In North America we see the replacement of coal-fired capacity as one of the most important drivers for the years to come, making it a very promising market for gas.
Darryl Shoemaker: Often the term “dash to gas” is used in the industry and it strikes me it’s been more of a stroll than a dash. Some of that is because of the continued economic uncertainty that’s out there, from utilities getting a little more comfortable with the price volatility. Certainly the recent events in Japan aren’t going to help that outlook in the short-term. The other factor we see in North America is the Boiler MACT (EPA rules involving maximum achievable control technology). It’s also creating a certain amount of demand in campus settings from central energy facilities and associated conversions. There’s certainly been a notable increase in activity.
John Adams: Calpine focuses on the North American market. We have seen a turn where the demand for power has started to increase. As a matter of fact, we had a 3 percent increase in generation last year in comparison to the year before. It looks like we’ve hit the bottom and we’re coming back out of it.
The one thing I would say for North America in particular is that it’s still very regional. When you get out to California, the forecast for the need for new generation is quite a ways out. On the other hand, they have a problem where they’re working with renewable integration and how can you manage adding new renewable power and manage the peaks and the valleys?
In Texas, for another example, the margins of capacity are getting to the point that in the next few years there will be a need for new power. In the eastern U.S., in particular, we see rules that have come in that will cause some of the plants to close. That gap will be filled with new gas, both in the east and the southeastern part of the U.S.
It’s a little different region to region, but it looks like we’re through the bottom and this is the beginning of the upward trend in North America.
Unconventional natural gas from shale and tight sand formations could be a game-changer for the industry. One wild card is environmental rules that could affect exploration and production companies. What model would you point to as appropriate to balance health and safety issues with ongoing resource development?
Nichols: There is no doubt that the resources we’ve discovered from natural gas are clean, abundant and here in the U.S. That is a great threat to environmentalists that want to develop alternate energy sources since they’re dramatically more expensive than natural gas. One effort they’ve been trying to do is giving the federal government control of all onshore drilling just as the federal government has control of offshore drilling. One has to only look at the state models that have been in existence for decades to see that the models we have are working perfectly accurately. Our industry has pointed out that hydraulic fracturing has been used for 60 years in well over a million wells and no one has been able to point to a single well where hydraulic fracturing has caused any problem with groundwater. We’ve said that in testimony before Congress; we’ve said that repeatedly over the last few years. And no one has ever come back to refute that. The model is there. Each of the states, whether run by Republican or Democratic governors, have been adamant in saying that the models we have are working. Show us the problem.
Shoemaker: It’s pretty obvious that the unconventional plays have already become a game changer. In the same way the market underestimated the market potential, in a lot of ways now they are overestimating resource recovery and that’s due in fact to what was just cited: the potential environmental concerns. Whether justified or not, you don’t often let a good story get in the way of the facts.
Ultimately what’s going to be available for resource recovery is going to come down to access versus key regulatory issues. A lot of those have been cited, whether that centers on availability of water, frack chemical disclosure issues, groundwater modeling or water transportation logistics, all which Larry pointed out are very manageable. But they all need to be proactively addressed. If the media is allowed to set the tone, then it becomes more difficult to manage those issues. You also see that with Interior Secretary (Ken) Salazar’s comments recently on looking into rules for frack chemical disclosure. In some ways, there’s an opportunity for the industry to look proactively at best practices for a development plan in conjunction with agencies. That’s ultimately what’s going to determine the access vs. restriction issues.
|Calpine’s Magic Valley Generating Station is a natural gas-fired, combined-cycle generating facility near Edinburg, Texas. Photo Courtesy Calpine.|
Adams: From our perspective, over the last 10 years, there’s been development in the Barnett Shale in the Dallas/Ft. Worth area. That to us looks at the model for going forward for the rest of the U.S. in terms of development. There really haven’t been any reported issues. It’s become mature and it seems to be the model. As far as managing the waste chemicals, I look at the power plants we’ve got right now. Throughout North America, we have zero-liquid discharge at a number of our plants that effectively takes the excess water, boils it away and exposes the chemicals in a proper manner. Those types of technologies will be and are available to continue the development of shale gas safely. We’re blessed with this natural gas in North America. This is the one game changer for us going forward and we really owe it to our children to develop it in a clean way.
Boller: Alstom is, of course, focusing more on the development of the equipment to burn the gas as efficiently and environmentally-friendly as possible. We continue to enhance the flexibility of our equipment to cope with the increased levels of renewables coming into the system to support the technology. There is a lot of development ongoing in this industry and this is not the first time that regulations have been in place. This is certainly a concern when it comes to expansion of such industry into other areas of the world where we’re looking at potential shale gas developments in the future, especially Europe and then China.
Walsh: Health, safety, good stewardship and respect for public concern are something that we all spend a great deal of time and energy making sure we stay focused on. I would agree with Larry’s comment that we believe the technology exists to protect the water table and we don’t think there are any show-stoppers in the development of this resource. Obviously, the cost for reclaiming water would become part of the gas production cost, but even with that additional cost, we think shale gas remains very competitive. We at Black & Veatch are working to address both the water cleanup and the energy needs to support the gas field development and the wastewater cleanup.
A recent study from the Energy Information Administration found the U.S. has twice the amount of projected recoverable natural gas (827 Tcf) than previously thought. How is this “abundant supply,” along with other developments, expected to affect natural gas prices in the years to come?
Adams: Thirty years ago when I graduated from engineering school, we had a moratorium on natural gas as a fuel for our power plants. The Use Act was in effect and we couldn’t build. The projections I heard from economists when I got out of school was that we had roughly a seven-year supply of natural gas and we were going to run out at that point, hence the moratorium.
Here we are now, 30 years later and there are projections that we have between an 80- to 100-year supply of natural gas. That abundant supply could allow us to have stable natural gas prices for years to come. These prices in North America would allow us to continue to build plants that would use the resource accordingly.
In checking with our group that trades gas long-term, there was a significant decrease in the long-term for natural gas prices between 2015 and 2050. It has dropped in this last year a lot. From the trading perspective, it’s reflected that we’re seeing a long-term expectation that the price will remain low and stable.
Boller: Gas is a major game changer in the U.S. and also globally. The gas reserves we’ve seen have increased in the last 10 years by more than 25 percent globally. Of course, a lot of these resources are still tied to the Middle East and Russia when it comes to the global markets.
Now in the U.S., already in effect is the decoupling of the oil price from the gas price, which has made gas much more affordable in power generation. This is an element that we do not see in the rest of the world for the time being. We expect that over the long-term, we’ll see power becoming the major user of gas globally. Power will consume more than 50 percent of the global gas production, which should lead the gas production industry to adapt to the needs of the power industry. This will lead to hopefully more stable, predictable gas prices and less volatility, as well as long-term agreement structures that will enable power production to further grow.
Walsh: Natural gas will take a much more dominant role as we go forward, moving from 20 percent to 40 percent over the next 25 years. That’s an outstanding step. We think natural gas will remain very competitive. Maybe one of the greatest benefits associated with this vast natural resource in North America will be that U.S. natural gas prices will become relatively independent from world oil pricing, so we’re very excited about that.
Shoemaker: As a data point, it does appear that the EIA projections have already affected the market. In March at the Power Supply Planning and Projects Conference, Xcel Energy announced that for the 20 percent additional gas use they’ll have to meet for the Clean Air/Clean Jobs legislation, what will be added into their portfolio was recently locked at less than $6 per Btu. I think that’s a pretty significant change from a year or so ago when there was still a lot of talk of hesitancy due to the volatility. It appears that in spite of a desire to have those longer-term contracts in place, it’s a more recent phenomenon where you’re able to get those longer-term contracts.
Nichols: The nature of the shale gas is really revolutionary because rather than finding relevantly small structural stratographic traps for natural gas as we have in the past, we now have the capacity to get natural gas out of the source rock itself: the shale.
As an example, Devon has drilled nearly 5,000 wells in the Barnett Shale. We have about 7,500 identified undrilled locations where we know the gas is there. That helps us respond to the market very, very quickly in a way that the industry has never been able to in the past. So the main benefit of this abundant supply is that it’s going to ameliorate the volatility that natural gas has had forever. In the past we never could bring on supply as quickly. Now if there’s an increase in demand, we can very quickly meet that demand by bringing on new supply. That makes natural gas more affordable and a more reliable fuel for everyone who wants to use it.
Do you foresee that natural gas will play an increased role in the power industry?
Nichols: I don’t think there’s any doubt about that. The fact that it produces half the CO2 of coal is going to make it a preferred fuel for utilities without any additional federal regulations. It’s already headed in that direction in a rather dramatic way.
Where does the price of natural gas need to be to sustain growth in gas-fired generating capacity? What are the primary factors that could affect that price?
Walsh: There is certainly more than enough gas at $5 to $7 to start a very significant new build program. Obviously, any increased costs associated with unconventional natural gas will have to effectively manage wastewater issues. We suggest that incremental cost is maybe $1 per MMBtu. If federal greenhouse gas programs are legislated, then that puts a little less pressure on the gas and we expect that to happen sometime in the future as well.
Nichols: There is not a single price, obviously. Different fields have different costs associated with them based on how deep the gas is and other factors. At $4 now, there’s very little that’s economically attractive on a full-cycle basis. As it gets about $5 and $6, then that opens a lot of additional reservoirs. I think that $4.50 to $7 is a good number to look at.
Shoemaker: The issue in some cases in the past hasn’t been as much price as volatility. That being said, there’s starting to be some confidence built that the cyclic nature of gas is certainly going to be dampened compared to what it’s been in the past and that’s certainly as telling as anything.
Adams: Getting rid of the cyclic nature is really the most important part. If we have a stable gas price going forward, it allows us to build. The numbers: $5, $6, $7 are low enough that it makes natural gas combined cycle power plants cost effective against other technologies. If you look at the other technologies out there (coal, nuclear, wind and solar) those are all more expensive from a cost standpoint (dollars per killowatt). Having a stable fuel price in that range, we can use natural gas as the most cost-effective approach.
Boller: We are looking at between $5 to $7. Stability and predictability at this point are the main drivers for new gas generation going forward. What’s going on in the U.S. with the shale plays frees up LNG capacity that has globally developed quite aggressively and will have to stabilize most likely in all the markets that are depending on LNG imports for the time being.
Nichols: The industry has been remarkably successful at bringing the cost of drilling these wells down as we learn how to deal with this resource. If you look at 2002, when Devon drilled our first-ever horizontal hydraulically fractured well, it was taking us well over three weeks to drill one well. We just completed a program of some 25 wells at an average time of 11 days per well. As we learn how this resource works, we’re able to bring those costs down so that we can make a decent profit. This makes the service supply companies and the utilities happy.
Calpine’s newest natural gas-fired combined cycle plant, the York Energy Center in Peach Bottom Township, Penn., commenced operations in March 2011. Photo courtesy Calpine.
Studies released by several consulting firms and power industry groups during 2010 suggested thousands of megawatts of older, less efficient coal-fired generation could retire for economic reasons in the next several years as environmental rules take hold. What’s your estimate of the scale, timing and technology mix of replacement capacity?
Shoemaker: The numbers seem to vary quite a bit, but the general consensus seems to be that the magnitude of retirements will certainly be significant, in the 40 to 70 GW range. I think what’s probably also noted is that a lot of that capacity that’s been identified is not first-run baseload. It tends to be your smaller, older plants. As we’ve already seen with a lot of the announcements, in spite of the lack of definition of federal regulations, gas is already playing a key role in replacing that generation, along with renewables, other forms of clean energy and efficiency improvements.
Adams: Over the next few years, our forecast is that between 30 and 50 GW would retire. Those are predominantly the 300 to 400 MW coal plants that are more than 30 years old and don’t justify further expense to bring them into compliance. As far as technology and what the mix will be, we believe it will be a combination of combined cycle power plants, peaking power plants and renewables.
Walsh: Our forecast is that about 15 percent of the U.S. coal base capacity— approximately 50,000 MW—is expected to be retired by the time the EPA regulations go into effect in five to seven years. Our numbers and work indicate that the biggest part of those megawatts is in the Eastern Interconnect, probably as much as 75 or 80 percent of that 50,000 MW.
As far as mix, gas and renewable energy will probably be the mainstays of that replacement and a lot of that mix will be based on the various RPS (renewable portfolio standard) requirements and natural gas prices. We also see energy efficiency as being one of the options to take up some of that retired capacity. We’re spending a lot of energy right now working with various owners to capture some of the energy efficiency associated with their operating units.
Let’s talk about supply chain issues. In the case of Devon Energy, are rig counts high enough to continue to deliver natural gas in reliable quantities and for reliable prices?
Nichols: Absolutely, rigs are adequate. For instance, in the Barnett Shale, Devon used to have 36 rigs running when we were building up our capacity. With our current efficiency, we can keep our production of 1.2 billion cubic feet per day flat for seven years to come with just 12 rigs. We could obviously expand that with more rigs if the market was there. We’re just sitting on those leases waiting for the market to arrive. You can see that the rig count is high enough to satisfy the market by the very low price at which gas is selling.
In regard to the distinction between oil and gas rigs, in some cases there is a distinction, but in many cases, there isn’t. Many of the rigs that have been built recently have been designed for horizontal drilling and we’re using exactly the same rigs in oil. So if there were a need for shifting rigs between oil and gas, that could be done fairly quickly.
As for the power-focused panelists, what supply chain issues are you currently working to resolve?
Walsh: As of a couple weeks ago, we really didn’t see any immediate, major supply chain issues. But we do expect to see something maybe inside of the next 12 months or maybe by the end of 2011. The types of things that we anticipate are a result of what we think is some kind of contraction in the capacity, primarily around human resources. It could be manufacturing, engineering or construction professionals. As that market starts to tighten up a bit, we would expect to see some type of commodity and equipment escalation and price adjustments. What we’re working on right now is trying to better understand and communicate with the manufacturers that we work with.
Boller: For Alstom, there are no immediate critical issues on the supply chain. In the last few years and months, there has been extreme volatility in terms of international currencies and material prices. So this is one of the major focuses, that we have to spread out our manufacturing and supply base to get natural access on both materials and on the exchange rate issue.
Adams: We look at it in two ways. From a building standpoint, we haven’t had any issues. The supply chain has been very adequate. A caveat recently has been the impacts in Japan, which have made a number of people nervous about the ability to get some products out of Japan. We’re watching that very closely short-term.Beyond that, the normal supply chain with respect to building power plants, we have not had any issues.
On the other side, being a huge consumer of natural gas, we do have to balance what we would have in respect to firm contracts for buying natural gas with short-term contracts for buying natural gas. How that balance is made over time is critical to how we go forward.
Shoemaker: The biggest issue is not so much an equipment issue but a system balance issue. In other words, the bottleneck on renewables (and certainly where gas comes into play) is the ability to load balance. Gas only goes so far in that it doesn’t help you with market timing. That’s where you’re going to see an increased look at energy storage in portfolios. We’re already starting to see that emerge as it’s been an area of expertise for HDR. The limiting factor, however, appears to be the lack of long-term certainty in prices. Right now it’s considered an auxiliary service in a lot of cases. The other factor to consider is shipping bottlenecks, certainly on the collection system side. How quickly will that infrastructure be able to respond?
What natural gas project stood out to you in 2010 and why?
Boller: For Alstom, 2010 was an exceptional year for the gas business, coming from a boom period in 2006 to 2008. When I look at early 2011 and the end of 2010, especially outstanding was the success that we could land in Singapore where there was quite a short-term boom of about 2,000 MW of combined cycle capacity being ordered in just a few months.
Adams: Our Russell City Energy Facility really stands out. It’s a 2-on-1 “F” combined cycle energy facility in California. What sets it apart is that it’s the first power plant in North America where we as an owner have made CO2 guarantees. That plant was actually developed and permitted where we have an absolute limit on a pounds-per-million Btu basis of the CO2 that the plant makes. Certainly the U.S. hasn’t gotten federal mandates out there yet; we’ve gone ahead and done it and we have permitting going forward on that plant.
Shoemaker: An interesting reflection of the rapidly changing dynamics in the last 18 months in the U.S. natural gas market is what Cheniere Energy has done with its Sabine Pass LNG facility in Louisiana. As a result of what’s gone on domestically, they’ve announced that they’ve been looking at the ability to export gas from that facility. This is a reflection of what we’ve seen with the shale market plays. That bi-directional capability, depending on how much that catches on in terms of other facilities, will make it interesting to see what market dimension is added to domestic natural gas pricing.
Nichols: For Devon, the development of our Cana field in western Oklahoma is undoubtedly our major excitement for 2010. The development of this field ratifies a decision we made in November 2009 to completely sell all of our offshore international properties and our Gulf of Mexico properties, which ended up netting $10.1 billion, in order that we could refocus on the shale gas in the U.S. To put it in perspective, that field, which has about 11 trillion cubic feet net to Devon, is actually larger than the four discoveries we’ve had in the Gulf of Mexico and it comes with little risk compared to the deep Gulf.
Walsh: The projects that we’ve been involved with that are most notable are the ones I’d describe as using advanced machines or “G” technology. The efficiency associated with these machines really takes a step change in terms of greater production and output. It addresses the concerns of a lot of different constituents from some of the special interest groups, to owners and their customers. Also, the fast-start capabilities associated with a number of these machines really help us address the needs of the various systems, recognizing the portfolio of renewables that are being built around the country.
Do you foresee that the proposed “nuclear renaissance” in the U.S. will be slowed or stopped as a result of what has happened in Japan and could that result in an increase of natural gas generation?
Walsh: It’s a little too early to measure accurately what the impact will be. There’s obviously going to be a number of questions that need to be asked and answered and that information will be coming out in the weeks and months ahead. In the short-term, until we hear answers to those questions, I’m sure some people have already been considering slowing down their decisions to move forward.
Adams: The nuclear renaissance that was predicted a few years ago included roughly 34 plants that were being licensed to go forward in the United States. Of those 34, only a handful looked like they were going to make it or were proceeding on a fast, timely basis. Having now this occurrence on top of that would certainly deter or make it even harder to go forward. The point being that the renaissance didn’t really happen in the way it was forecasted that it would. Now we have this tragedy on top of it, which will actually slow it further.
Nichols: The nuclear problems in Japan will focus the minds of both the public and policy-makers on why we would provide loan guarantees of $38 billion for new nuclear plants. Some will be paid for by taxpayers, while we have such an abundant cheap and clean resource like natural gas, which comes with minimal risk.
What is Shale Gas and Why is It Important?
Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States. This Q&A from the Department of Energy’s Energy Information Administration offers a basic overview of shale gas.
Q. Does the U.S. Have Abundant Shale Gas Resources?
A. Of the natural gas consumed in the United States in 2009, 87 percent was produced domestically; thus, the supply of natural gas is not as dependent on foreign producers as is the supply of crude oil, and the delivery system is less subject to interruption. The availability of large quantities of shale gas will further allow the United States to consume a predominantly domestic supply of gas.
According to the EIA “Annual Energy Outlook 2011,” the United States possesses 2,552 trillion cubic feet (Tcf) of potential natural gas resources. Natural gas from shale resources, considered uneconomical just a few years ago, accounts for 827 Tcf of this resource estimate, more than double the estimate published last year. At the 2009 rate of U.S. consumption (about 22.8 Tcf per year), 2,552 Tcf of natural gas is enough to supply approximately 110 years of use. Shale gas resource and production estimates increased significantly between the 2010 and 2011 Outlook reports and are likely to increase further in the future.
Q. Where is Shale Gas Found?
A. Shale gas is found in shale “plays,” which are shale formations containing significant accumulations of natural gas and which share similar geologic and geographic properties. A decade of production has come from the Barnett Shale play in Texas. Experience and information gained from developing the Barnett Shale have improved the efficiency of shale gas development around the country. Another important play is the Marcellus Shale in the eastern United States. Surveyors and geologists identify suitable well locations in areas with potential for economical gas production by using both surface-level observation techniques and computer-generated maps of the subsurface.
Q. How is Shale Gas Produced?
A. Two major drilling techniques are used to produce shale gas. Horizontal drilling is used to provide greater access to the gas trapped deep in the producing formation. First, a vertical well is drilled to the targeted rock formation. At the desired depth, the drill bit is turned to bore a well that stretches through the reservoir horizontally, exposing the well to more of the producing shale.
Hydraulic fracturing (commonly called “fracking” or “hydrofracking”) is a technique in which water, chemicals and sand are pumped into the well to unlock the hydrocarbons trapped in shale formations by opening cracks (fractures) in the rock and allowing natural gas to flow from the shale into the well. When used in conjunction with horizontal drilling, hydraulic fracturing enables gas producers to extract shale gas at reasonable cost. Without these techniques, natural gas does not flow to the well rapidly and commercial quantities cannot be produced from shale.
Q. How is Shale Gas Production Different?
A. Conventional gas reservoirs are created when natural gas migrates toward the Earth’s surface from an organic-rich source formation into highly permeable reservoir rock, where it is trapped by an overlying layer of impermeable rock. In contrast, shale gas resources form within the organic-rich shale source rock. The low permeability of the shale greatly inhibits the gas from migrating to more permeable reservoir rocks. Without horizontal drilling and hydraulic fracturing, shale gas production would not be economically feasible because the natural gas would not flow from the formation at high enough rates to justify the cost of drilling.
Q. What Are the Environmental Issues?
A. Natural gas is cleaner-burning than coal or oil. The combustion of natural gas emits significantly lower levels of carbon dioxide (CO2), nitrogen oxides, and sulfur dioxide than does the combustion of coal or oil. When used in efficient combined-cycle power plants, natural gas combustion can emit less than half as much CO2 as coal combustion, per unit of electricity output.
However, there are some potential environmental concerns that are also associated with the production of shale gas. The fracturing of wells requires large amounts of water. In some areas of the country, significant use of water for shale gas production may affect the availability of water for other uses and can affect aquatic habitats.
Second, if mismanaged, hydraulic fracturing fluid — which may contain potentially hazardous chemicals — can be released by spills, leaks or various other exposure pathways. Any such releases can contaminate surrounding areas.
Finally, fracturing also produces large amounts of wastewater, which may contain dissolved chemicals and other contaminants that require treatment before disposal or reuse. Because of the quantities of water used and the complexities inherent in treating some of the wastewater components, treatment and disposal is an important and challenging issue.
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