A First-Hand View of Fracking in Pennsylvania's Marcellus Shale

• Producing shale gas requires drilling numerous wells, often in regions that have seen little or no oil & gas activity for decades. Addressing environmental and other community concerns is crucial to acceptance.
• On a recent visit to a shale operation in Lycoming County, PA, I was impressed by the rigorous attention I saw to safety, spill prevention, soil conservation, and other impacts. 

It’s easy to talk about the shale gas revolution in the abstract and forget that it is the cumulative result of thousands of operations in locations across the country. It combines the technological marvel of precisely planned and executed drilling more than a mile below ground with the efforts of teams of skilled workers on the surface, and affects the surrounding community in many ways. Last month I had my first opportunity to visit one of these sites, near Williamsport in north-central Pennsylvania. I also saw several nearby sites in different stages of development. Although I was consistently impressed, I also tried to observe with the concerns of shale gas critics in mind.



The Anadarko Petroleum well site, or “pad” that I toured is located in Cogan House Township in rural Lycoming County, atop the Marcellus shale formation. API arranged this site visit for bloggers and other media and paid for accommodations in Williamsport. Anadarko provided experts from its local engineering and public affairs staffs and hosted a dinner with members of the community the evening before the site tour. No one paid me to write about the visit, nor was there any expectation that I would report anything other than my candid, objective opinion of what I saw.

I’m no stranger to industrial sites or oil fields. I’ve also invested countless hours researching and discussing shale drilling and hydraulic fracturing. When it comes to complex technical subjects like this, however, no amount of reading or Youtube videos can substitute for seeing the real thing and being able to talk to the people actually doing the job about how it all works.

One example of that is safety. Safety plans, targets and slogans are important, but it carries more weight when the site engineer looks you in the eye and says emphatically in his own words, “The most important thing is that everyone goes home at night,” and then proceeds to explain the stop-work rules, the “red zones” that have to be clear of workers when the fracking pumps are running, and other aspects of onsite safety. We were constantly reminded to watch where we stepped and to make sure we had multiple points of contact with the ground whenever we looked at something or photographed it.

Concern for environmental impacts was similarly thorough. I consider surface spills a much bigger potential risk to groundwater than fracturing a layer of shale thousands of feet below any aquifer. The first thing I noticed at the site, all five wells of which had already been drilled and prepared for fracturing, was the floor. The entire pad was covered with a three-layer mat of black felt, HDPE plastic and fabric, to isolate any spills from the ground. The pad was also surrounded by a berm to contain any spills, which would promptly be vacuumed up by a waiting truck. They even vacuum up rainwater. Yet the real key to spill control is prevention, which in Anadarko’s case is reinforced by its “Eyes On” program. This requires an extra observer any time a liquid other than fresh water is being handled or transferred. Soil conservation efforts looked similarly scrupulous.

Another issue I asked about was noise. I couldn’t gauge it for myself, because aside from trucks delivering supplies the site was shut down during our visit. It’s not prudent to have untrained people wandering around when 30,000 HP of truck-mounted pumps are running, injecting fluids down a well at nearly 10,000 psi. When I inquired, I was told that the pumps themselves were loud, requiring ear protection nearby but not at the perimeter of the site. How far the sound carries beyond the site is a function of terrain, foliage and weather conditions.

Then there were the fluids themselves. An Anadarko engineer described the company’s approach to the five wells at this site as minimal and “green”. The fracking fluid was a simple “slickwater frac”. The main ingredients consisted of around 4 million gallons of water per well--much of it filtered and recycled from nearby gas wells--and 4-6 million pounds of sand, to prop open the fractures created by high-pressure water. The formula also includes a little hydrochloric acid for downhole cleanup, and two other ingredients: a low dose of “biocide” to prevent corrosion from bacterial growth in the well, and a friction reducer, without which significantly higher fracking pressure would be required. The details of the chemicals used at the pad will be available on the public disclosure site www.FracFocus.org once the wells are complete.

I also inquired about methane emissions during well completion. Some critics claim--incorrectly, per independent analysis--that such emissions, along with other leakage, negate the climate benefits of shale gas. Although I was told Anadarko wasn’t specifically employing “green completion” techniques at this site, it was taking steps to minimize emissions, starting with having the gas gathering pipeline ready to go. As each well is completed, it’s hooked up to production so no methane escapes. That maximizes revenue. The site also had a temporary flare to burn off any excess gas from operations before the well could be connected to the pipeline. That sounds wasteful but is environmentally preferable to venting gas.

Of course for all the precautions and evident best practices there’s no disguising that while it is being prepared, drilled, fractured and completed, each drilling site is a compact industrial operation and hub of activity. Numerous trucks carry water, sand, chemicals and equipment back and forth. Anadarko has improved over 200 miles of country roads to handle this traffic, while minimizing freshwater haulage by the use of water pipelines connecting its sites.

The consolation for the neighbors is that the entire process runs its course like any construction project. A few weeks or months of intense activity are followed by years of unobtrusive operation, during which gas flows into pipelines and royalties into the community. The employment and other local economic benefits this creates are significant, especially for communities that have lost many of the industries that sustained their economies in the past.

Several of the participants at the dinner the evening before drew comparisons to wind turbines, which are much taller than the drilling rigs used for gas wells, and remain on-site for decades. That got me thinking about relative energy contributions. At Anadarko's estimated lifetime gas production (EUR) of 8 billion cubic feet each well could generate more than 1.1 billion kilowatt-hours (kWh) of electricity in an efficient gas-fired power plant. By comparison, a 1.5 MW wind turbine would normally generate less than 80 million kWh over 20 years. So when brought online the five wells on the one pad I visited will together produce energy equivalent to a wind farm of more than 70 turbines.

Even if the ultimate recoveries from these wells turned out to be closer to the lower figures estimated by third parties from the limited data available to them, compared to those used in Anadarko's calculations, it would still represent a very substantial energy yield for such a small site.

I came away from the tour with a strong impression of a well-trained and experienced team, focused on doing the job right — safely and with minimal impacts, because this is where they and their families live; the landowners from whom they lease their sites are their neighbors. And for all the truly impressive technology deployed, what really counts is the people using it.I can understand skepticism about the balance of risks and benefits from shale gas development--this is a skeptical age--but nothing I observed in Williamsport would validate such concerns. Instead, I saw a well-tuned operation that is a microcosm of the biggest US energy revolution of the last 40 years.

A different version of this posting was previously published on Energy Trends Insider.

Will Water Limit Fracking in Arabia?

• Poor water availability could hamper efforts to develop Saudi Arabia's shale gas resources, in order to meet growing gas demand from Saudi industry.
• Water recycling and alternative fracking fluids could provide the solution.  

Recent comments by Saudi Arabia's oil minister, Ali Al-Naimi, indicated that Saudi Aramco would soon begin exploring the country's shale gas resources. As another means of reducing oil consumption in the Kingdom's electricity sector, in order to preserve oil exports, this appears to make both practical and economic sense. However, as noted by the Wall St. Journal, compared to the US Saudi Arabia has much less water available for the hydraulic fracturing of shale and tight gas reservoirs. Absent a reallocation of its substantial conventional gas production, Saudi shale gas could become a key factor in global energy security. However, the techniques employed to extract it might be different from those that currently dominate the US shale gas scene.

It must seem odd that Saudi Arabia would even be interested in shale gas, a resource that wasn't exploited in the US until conventional gas production was declining steadily. Saudi Arabia might still be the world's largest oil producer, at least for now, but it is not the "Saudi Arabia of natural gas". Although the country has proved gas reserves comparable to those of the US, it apparently didn't win nature's gas lottery on the Arabian Peninsula. Saudi gas reserves and production amount to only about 10% and 19%, respectively, of the Middle East's gas totals. Iran and Qatar are far ahead. And while Saudi gas production has doubled since 2000, output in neighboring Qatar has expanded by a factor of six in the same interval.

Much of the Kingdom's conventional gas reserves are associated with oil production and are often required to be reinjected to maintain reservoir pressure and oil output. Available Saudi gas has been preferentially allocated to industrial projects, such as petrochemicals expansion. As a result, little new gas was supplied for power generation, so the Saudi electricity sector has been burning large and increasing quantities of oil that could otherwise be exported. The need for additional gas has become acute, but exploration in the vast Empty Quarter has not yielded the expected gas bonanza, while the internal price of natural gas has been constrained at levels well below even recent low US natural gas prices--too low to make most new production attractive on its own merits.

As if the economics of shale gas development weren't challenging enough in such an environment, the key ingredient that has fueled the US shale revolution, water, is in short supply in Saudi Arabia. The needs of cities and industry in this arid country exceed the water supply from aquifers to such an extent as to require 27 desalination facilities, delivering nearly 300 billion gallons annually. At several million gallons of water per hydraulically fractured shale gas well, the logic of burning oil to desalinate water to produce gas looks questionable. Fortunately, there are multiple emerging pathways for reducing or eliminating net water consumption in "fracking".

For starters, many US producers now routinely recycle the 10-30% of injected water that typically flows back from the well after hydraulic fracturing, for use in subsequent wells. Recycling has become the standard in places like Pennsylvania's portion of the Marcellus shale, reducing the call on fresh water for fracking. The oil services industry offers various techniques for cleaning "flowback" water, and new ones are under development, including the use of algae.

Drillers can further reduce freshwater consumption through the use of nitrogen in foam or other forms. ERDA, a precursor of the US Department of Energy, conducted research on that technique in the 1970s, and it has been refined since then. Nitrogen is readily available from air separation plants and does not depend on water, though it does require energy.

Another approach for waterless fracking has been field-tested in Canada, using gelled propane. A blog post in Scientific American described some of the pros and cons of this method, which is more expensive where water is cheap but might fit the bill in dry regions where LPG is readily available. For that matter, it might make sense in New Mexico if the Mancos Shale of the San Juan Basin turns out to be another viable tight oil play.

The upshot is that a shortage of fresh water shouldn't constitute an insurmountable obstacle to exploiting Saudi Arabia's unconventional gas resources, which Mr. Al-Naimi cited at 600 trillion cubic feet. However, it remains to be seen whether shale gas development is the best answer to a problem that has been created by selling natural gas to industry for as little as $0.75 per million BTUs, while burning $100 oil ($17 per million BTU) to generate electricity. Whether the ultimate solution is shale gas or something else, resolving this gap in Saudi industrial policy could have a significant impact on future oil prices.

A slightly different version of this posting was previously published on the website of Pacific Energy Development Corporation.  

The "Water-Food-Energy Nexus"

A summary of annual risk forecasts in a Linked-In group led me to a very interesting presentation on global risks from the World Economic Forum, the body that puts on the annual movers-and-shakers shindig at Davos, Switzerland. Among the risks they highlighted are those associated with what they termed the "water-energy-food nexus". The food vs. fuel concerns I explored in Friday's posting make up just one subset of this much larger and more complex set of interactions. These can be further expanded--and complicated--by incorporating the relationships between this triad and climate change. Although the WEF identified a number of steps that could be taken to address this poorly-appreciated challenge, it requires a leap of faith to imagine we could tackle this issue as systematically as it seems to merit, in light of our track record on other big but comparatively simpler challenges such as energy security and the ongoing deficit and debt problems of the developed world.

The extra complexities resulting from adding water to the already thorny food-fuel relationship are nicely illustrated by a systems chart in the WEF's analysis. It shows food security, water security and energy security linked by a series of sometimes reciprocal inputs, and influenced by other factors such as population and energy growth and environmental pressures, along with two overarching risks of global governance failures and economic disparity. All of this leads toward geopolitical conflict. It's a sobering assessment, even without including the missing arrow flowing back from food security to energy security. Biofuel produced from food crops makes up an increasingly important source of global liquid fuel supplies, so the "food intensity of energy production" deserves inclusion with these other factors, too.

This isn't the first time that I've seen a diagram portraying these interactions. I can't help wondering whether the WEF viewpoint was influenced by some scenario work that I encountered through my involvement with Global Business Network in the 1990s and early 2000s. I was fascinated by Gerald Harris's description of the triangle connecting water, food and energy, which has become much more apparent in the years since I first saw it. Although at the time the traditional energy industry understood its relationship with water pretty well, the water intensity of corn ethanol wasn't yet an issue, because US ethanol production was under 2 billion gallons a year, less than a sixth of its current level. And while some oil and gas wells have been hydraulically fractured for decades, the mass application of this technique to unlocking shale gas resources was still in its early days and hadn't percolated into the public's consciousness. Yet while the use of (and impact on) water in energy has become a much higher profile issue, metrics for comparing the water intensity of energy produced from different sources are still evolving. And we've barely begun to think about how for example water, which requires energy to capture and distribute, is used in producing energy, affecting the availability of water for growing food, some of which is then turned into energy. You can start similarly convoluted chains with food or energy, too.

We've typically looked at issues such as those in the examples above in terms of simple, binary decisions, rather than complex tradeoffs calling for integrated resource planning among all affected parties, at both the regional and local level, and markets that account for as many of the real costs and relevant externalities as possible. Yet without taking anything away from the work of the groups that the WEF mentions are looking at these problems in Indochina, Jordan, and elsewhere, we simply don't have the kind of governance in place to do this globally. If the UN can't come to grips with climate change and nuclear proliferation, then the future of the "water-food-energy nexus" seems far likelier to play out either in isolation or as a series of one-off efforts among highly motivated (desperate?) parties. And with last year's favorite governance body, the G20, heading into what some are calling a "G-Zero" world, it's not clear who else could take up this mantle. In the absence of some improbably comprehensive global approach to managing these interdependencies, it's up to those working in the affected industries to ensure that these factors are at least reflected in the planning and analysis of major projects and investments.

Hydrocarbons and Geothermal Energy

Geothermal power is probably the lowest-profile renewable energy option we have. It doesn't get nearly the attention that wind and solar power do--even from me--although it has been quietly cranking out about 0.4% of the US electricity supply for many years. That roughly matches the expected output of all the wind turbines likely to be installed here this year. I've commented previously on the striking similarities between geothermal exploration and production and the processes and risk profile of oil and gas E&P, but I don't believe I've ever mentioned a small but potentially important overlap between the two: geothermal heat extracted from the fluids produced from oil and gas wells. The potential contribution of "geothermal hydrocarbon co-production" (GHCP) might not be as large as from conventional hydrothermal reservoirs or engineered geothermal systems (EGS), but this approach has the advantage of capitalizing on additional energy from a source that's already being exploited.

In its report on the US geothermal industry earlier this year, the Geothermal Energy Association listed five projects involving GHCP and related efforts to tap the mechanical energy of high-pressure gas reservoirs, or geopressured fluids. The Department of Energy has recognized this potential and provided partial funding for several of these projects under its stimulus programs. GEA also cited an estimate from Southern Methodist University's Geothermal Energy Program that GHCP from the onshore Gulf Coast region alone could provide up to 5,000 MW of reliable power. That doesn't include the potential for using the large volumes of produced water in new or abandoned wells to tap the energy of higher-temperature rock formations underlying the hydrocarbon reservoirs using engineered geothermal systems (EGS).

The benefits of these approaches for low-emission power generation seem obvious, but it's worth considering why they might be attractive for oil and gas companies that are mainly focused on producing hydrocarbons for processing and sale, not electricity. GHCP addresses two key, related problems of many mature US oil fields. The first is water, which in many cases is injected underground as part of "secondary recovery", in order to increase the total fraction of hydrocarbons recovered from an oil field during its life. Together with water already present in these reservoirs (as distinct from the shallower aquifers used for drinking water and irrigation) this contributes to high "water cuts"--large volumes of water produced with the oil and gas that sometimes exceed oil volumes by a factor of 20:1. If this water is in contact with hot rock, it will bring some of that heat to the surface, where it can be recovered using binary geothermal technology. SMU estimated total produced water from US oil production at 50 billion barrels per year.

That's an enormous volume of water for the industry to handle and dispose of in an appropriate manner, and it gives rise to another problem that GHCP can help tackle. It takes a lot of electricity to pump all that water out of the ground, process it, and pump it back down. That power must either be purchased or generated onsite. If GHCP can just provide enough power to cover an oil field's operating power requirements, it represents a significant savings in the cost per barrel of oil produced. The SMU study suggests that there is also an opportunity for net electricity production, representing another potential revenue source for an oil project. Depending on the investment required, that could improve overall project economics.

I see another, less obvious benefit for geothermal hydrocarbon co-production. The US geothermal industry hasn't attracted anything like the investment that's gone into wind and solar power; it is starved for capital. As a result, it can only tap a small fraction of the potential power from US hydrothermal reservoirs, let alone the orders-of-magnitude larger potential of EGS. If these projects don't offer quite the economic payoff of oil and gas production, they at least closely resemble what the oil industry does day in and day out, while being almost completely unlike what firms involved in wind, solar or even biomass power do. GHCP could be a natural bridge for more of the oil and gas industry, which its much larger capital, skills and technology base, to expand into geothermal energy that doesn't involve any hydrocarbons.

The Water Behind Ethanol

US ethanol producers didn't need more bad news. Despite federal and state blending subsidies and a steadily increasing federal mandate for the use of their product, the US ethanol industry has been suffering badly from low margins in the wake of last year's oil-price collapse. A number of companies, large and small, have been forced to seek Chapter 11 bankruptcy protection. The bankrupt VeraSun, a former industry leader, recently sold seven of its plants to independent oil refiner Valero, and several others to its creditors. But while last year's "food vs. fuel" controversy has largely died down, thanks to lower corn prices, a new study from the University of Minnesota suggests that some ethanol production uses even more water than previously estimated--as much as 2,000 gallons of it for every gallon of ethanol produced in states where crops must be irrigated. This finding further undermines the environmental benefits of a fuel that saves significant amounts of oil but requires large inputs of natural gas and other fossil fuels, and thus offers only modest greenhouse gas improvements over gasoline.

As with its other environmental liabilities, most of ethanol's water impact occurs upstream of the ethanol plant. Process water for slurrying corn and boiling, fermenting and distilling fuel ethanol only accounted for 3% of the total water consumption analyzed by Chiu, Walseth and Suh in their paper, "Water Embodied in Bioethanol in the United States". They also reported a remarkably wide range for the ratio of total water consumption (irrigation and process) per unit of produced ethanol by state: under 10:1 in Iowa, Kentucky and Ohio, and over 1000:1 in California, Colorado, New Mexico and Wyoming. Fortunately the latter states contributed just 3% of the 2007 ethanol production tallied in the study, resulting in a national average of 142 gallons of water per gallon of ethanol. However, two significant ethanol-producing states, Kansas and Nebraska, accounted for 14% of ethanol production but more than half of all US water consumed for ethanol, with ratios above 500:1. A useful chart in MIT's Technology Review illustrates these variations from state to state.

These findings add to an already daunting list of concerns about the long-term sustainability of an alternative energy policy that has so far relied mainly on biofuel produced from a food crop requiring extremely high inputs of water and natural-gas-derived fertilizer. The water dependency of corn ethanol looks even more unsustainable under various scenarios of climate change, which ironically this fuel is intended to help mitigate. Simply put, if water in the West and Southwest is likely to be in even tighter supply in the future, the last thing we should be doing with it is to divert it to the production of such a water-intensive oil substitute. The urgency of converting biofuel production to cellulosic feedstocks requiring little or no irrigation is high, at least for those states with water:ethanol ratios above the national average, but unfortunately urgency and bigger research budgets don't guarantee making today's demonstration-scale cellulosic ethanol technologies economical at larger scales. Breakthroughs don't arrive on demand.

The results of Chiu, Walseth and Suh provide further support for a thorough reevaluation of US biofuel policies. Rather than trying to squeeze ever more ethanol into gasoline, with uncertain consequences for motorists, and stretching our agricultural resources by expanding unsustainable crop-based biofuels of questionable value for reducing greenhouse gas emissions, the administration should ask the Congress for authority to freeze the conventional ethanol portion of the Renewable Fuel Standard at its current level of 10.5 billion gallons for 2009. That still represents a 9% increase over 2008's consumption of 9.6 billion gallons, which took well over a trillion gallons of water to produce. Further increases should await either economic cellulose-based biofuel, or the imposition of prudent standards limiting the embodied water and fossil-energy content of this fuel. That won't help today's overbuilt ethanol industry, but it would ensure that its survivors enjoy a more viable, sustainable future.

Climate Change, Water, Food and Fuel

Few of the reports I've seen about the current heat wave and drought in the West explicitly mention a connection to climate change. After all, climate is what we expect, weather is what we get, and the two often seem disconnected from each other. But in this case, they are linked in at least the following way: current conditions out West exemplify what climate scientists have been telling us to expect more frequently, as the earth warms. It's hard to look at the situation and not see numerous feedback loops with significant potential consequences for the growing population of the Sunbelt, and for the entire economy. Sustained dry conditions in the Western US could jeopardize food supplies and amplify the mechanisms of global warming.

Having spent much of my life in California, I'm conscious of the way that water and development have always been tied together in the West. Los Angeles only grew to its present scale because of the contracts and infrastructure that bring water from the eastern Sierra Nevada and the Colorado River to SoCal. In the semi-arid southwest, residential and agricultural demand for water have historically been in tension with conservation interests, and the balance among them has gradually shifted towards the latter in the last few decades. If climate change yields a significantly drier pattern in the West than what has prevailed for the last fifty years, then the entire system will be stressed. Given the migration rate into the region, with metro areas like Las Vegas and Phoenix growing at multiples of the national rate, it's hard to see residential water use ending up as the lowest priority use of scarce water. Homeowners and businesses can outbid farmers, and the agricultural bounty of places like the central valley of California, which depends heavily on irrigation, could be at risk.


But just as climate change can influence these conditions, the reverse is also true, via the basic mechanisms of climate change. The drier the West becomes, the less vegetation it can support. That reduces the region's natural uptake of CO2, which helps to mitigate the impact of man-made emissions. But it also creates the conditions for putting large quantities of stored carbon back into the air, via the wildfires that become more frequent and extensive during a severe drought. That could ultimately force us to make even deeper cuts in the greenhouse gases emissions from transportation and industry, in order to stabilize the concentration of these gases in the atmosphere. The climate neither knows nor cares whether a ton of CO2 came from a car's exhaust, from a coal power plant, or from a forest fire. The global effect is exactly the same.

Now throw biofuels into the mix. While they represent an important strategy for reducing our use of the fossil fuels that contribute to climate change, their cultivation under drought conditions adds to the competition for water among food crops, natural systems, and the increasing demand from development. In this context, food vs. fuel becomes a subset of a larger fight over water, fed by climate change but affecting climate change in turn. Compared to this, the geopolitics of oil are simple.