In just half a decade, hydraulic fracturing of oil and gas wells has greatly improved the economic competitiveness of America. This is leading to new employment opportunities for hard hats and also lab coats. What does the future look like?
Many lecturers addressed the impact of hydraulic fracturing at a 2.5-day Symposium at the 248th ACS National Meeting, held August 10–14, 2014, in San Francisco, CA. Dr. Ken Golden of Exon Mobil focused on the energy needs up to 2040.1 At the macro level, global energy consumption will increase about 70% from 418 quadrillion BTUs in 2000 to 710 QBTUs in 2040. During this period, the energy diet for the OECD (Organization for Economic Co-operation and Development) countries is forecast to be constant at about 226 QBTUs. The mix of fuels will change. Coal will be constant at 133 QBTUs from 2010 to 2040, while gas and oil will grow from 115 to 190 and 178 to 221 QBTUs, respectively. Nuclear will double from 29 to 59 QBTUs. All other sources are much smaller. They may show high percentage growth, but off a small base, so their contribution is not very significant.
However, prophets are quick to point out the many dependent problems with continued reliance on fossil fuels. CO2 emission is one, poor sustainability is a second, and third is the large greenhouse footprint of methane, which could initiate several positive-feedback cycles, accelerating global warming.
But when prophets are pressed for solutions, their vision is not clear. Nirvana and the path to get there from today are shrouded in thick fog. Specifically, how do we get there from here? And how would nirvana really work? For example, solar and wind power are great, but they are intermittent and thus require energy storage. High watt-hour storage is not yet on the horizon. One of the many tracks at the ACS National Meeting focused on the history, present status, and future of hydraulic fracturing for oil and gas production. This is changing America’s energy and chemical vision. As chemists, we will play an important role.
Background of hydraulic fracturing
Hydraulic fracturing (HF) for improving the production of oil and gas wells has been used for decades. Depending on the particular location and even the geochemistry of the well, it generally delivers modest production improvement in existing wells, which vertically traverse the producing formation. In 2008, the technology changed due to improved fracturing fluid properties and realization that horizontal drilling in the production strata could increase the effective production zone. It is certainly less expensive than drilling several vertical-only wells. Hydraulic fracturing is the general name for the high-pressure process and also applies to vertical wells. “Fracking” applies to the process in a well with a horizontally drilled production zone.
We are only six years into the fracking revolution. The technology is evolving rapidly. Beyond that, generalizations are confounded by the wide range of variables associated with the idiosyncrasies of the particular oil or gas field, and even each well.
The fracking process
First a well is drilled into a target formation. The borehole is about 12–20 in. in diameter. Steel casing is inserted into the well. Cement is pumped in, sealing the casing to the wall of the borehole. The specific cement is formulated to expand on curing. Common Portland cement contracts about 0.5% on curing, which produces leaks along the well bore. Failure of cement seals is the major failure mode responsible for contaminants traveling from one stratum to another. Cementing failure is blamed for about two dozen instances of groundwater contamination in Pennsylvania. All of these were in older vertical wells.
Once the well casing is cemented in place, the pipe and peripheral cement layer in the potential production strata are perforated at specific points. This is done with explosive-driven projectiles that are forced about a foot into the formation. The well is washed out with a slug of concentrated acid (usually HCl), which can increase the cavity significantly, especially if the rock is a carbonate. If the rock is predominately a silicate, as is the case for most oil and gas shales, acid treatment is much less effective.
The fracking process usually starts with mechanically plugging off sections of the perforated well bore. Each section is washed with a bolus of HCl. At the top of the well the water tanks are connected to the mixing tanks, which feed an armada of 20 2000-hp-pumper trucks in parallel. They produce a flow of 4000 gal/min at 10,000 psi (ultrahigh-performance liquid chromatograph [UHPLC] pressures).
In shallower wells, high-pressure water is sufficient to fracture the formation, creating fissures emanating as much as 100 ft into the formation. If the pressure is reduced the elastically deformed formation relaxes, collapsing the pores and expelling the water back up the bore. This is called “flowback water.” To minimize relaxation, strong silica sand is slurried in the water, which carries the silica into the pores, propping them open; hence the sand is called “propant.” The high linear velocity has a Reynolds number greater than 10,000, which is consistent with turbulent flow, and keeps the propant from settling in the casing.
In deeper wells, say 10,000 ft, the pressure drop from the high flow passing through a several-mile-long 4-in.-i.d. pipe is about 10,000 psi. Thus there is no excess pressure left to fracture the formation. Typical bottom-hole pressure in the target strata can be several thousand psi. To fracture, one needs to overcome this pressure by several thousand psi.
To reduce the pressure loss, one can add slip agents, such as guar. This reduces the viscosity and line loss by up to 90%. Now the solution chemistry gets complicated. Guar is a polysaccharide that reduces water’s viscosity in flowing pipes. Borate can be added as a thickening agent, which takes over under lower-velocity conditions. Thus borate + guar have low flow resistance at high flow velocity, but high viscous flow in the target stratum. This helps open fissures in the shale strata. However, the guar + borate mixture can plug off the fissures when the pressure is removed. So an encapsulated, timed-release strong oxidizer (conc. hydrogen peroxide) is added to the fracking slurry. The pressure is removed, and the next segment is isolated to focus the fracking routine. But back in the collapsing fissures, after a few hours, hydrogen peroxide emerges from the pellet to oxidize the guar to CO2 and small alcohols, which are washed up and out in the flowback water. The 200-min fracking process is repeated in each of the sections. Fissures can extend radially as far as 100 ft.
When the pressure is relieved, some of the flowback water is expelled typically over a week or two. Over time, the flowback water is diluted by water native to the formation, which is called production water (PW). Its composition varies with the formation. In the Marcellus Shale, PW brine contains toxic levels of barium, strontium, and radium. In some fields in California, PW is low in dissolved solids and suitable for agriculture. In others, the brine content, including boron, exceeds toxic limits. In Long Beach, CA, PW is augmented with seawater and is reinjected into the producing formation to prevent land subsidence in the harbor.
Objections to fracking
New shale gas and oil are creating discontinuous shifts in the economy. Some will win and win a lot (lease and well owners and drillers) and others will lose (e.g., coal and quality of life). Many lives will be changed as the land use changes. For example, farms or forests are turned into sterile, noisy drill pads or pipeline easements. There is an understandable NIMBY (not in my backyard) effect, especially among people who are not winning financially. Some objections are:
- Water pollution: A large fraction of the antifracking reports deal with the risk of water pollution. The rush to get wells into production compounded this. The operators proceeded without establishing a base case, and this exposed them to claims that could not be disproven. Best practices today require monitoring the potentially affected water prior to drilling and then monitoring the operation and abandonment. Even postabandonment monitoring may be called for since failures of abandoned wells have been implicated in several old fields that are now targets for HF.
- Air pollution: Air pollution is also a quality-of-life concern. Oil and gas wells, pipelines, storage tanks, etc., can leak. Some of the volatiles really stink. Big motors are often powered by fuels with loud, smelly exhaust. Again, in the rush to drill, shortcuts were taken and confidence suffered. Best practices will require that air quality be considered in the well design and permitting process. Jennifer Maclachlan of PID Analyzers, LLC (Sandwich, MA) described a portable gas chromatograph with a flame ionization detector that is designed to help identify volatile organics in air, at-site in real-time.
- Radiation: Production water from some wells in the Marcellus region contains high concentrations of naturally occurring radioactive materials (NORM), principally decay products from uranium deposits below the shale. Radium and radon are of particular concern, but their daughter isotopes include lead and polonium. This was discussed in several lectures. The problem is that NORM is present in the sediment and scale that forms around pipes. Marcellus PW also contains calcium, barium, and strontium. These group 2 elements are notorious scale formers. Radioactivity trapped in sediment and scale can exceed radiological safety limits by significant factors. The problem with NORM appears to be limited to the Marcellus Shale. However, it is a general concern, especially in the planning stage for new wells.
- Aesthetics: Some oil and gas fields are in desolate areas. Others, such as the Marcellus, are in forested areas of PA, NY, OH, etc. Wherever you call home, well drilling and production will probably change the surrounding landscape and infrastructure. Several lectures described studies undertaken to help planners understand the impact of drilling, production, and well abandonment. Mr. Earl Hagstrom, a lawyer with Sedgwick, LLP (San Francisco, CA), described how local zoning and permitting can effectively block drilling. Some states are trying to prevent local restrictions, while others seem to support local “opt outs.”
Mr. Kyle Farrar of FracTracker Alliance (Oakland, CA) described his NGO’s interest in studying the location of wells and the relationship to businesses, residences, and different socioeconomic groups. This study required gathering historical data across many files. FracTraker is particularly looking for evidence that petroleum development activities are disproportionally located in areas with lower economic status.
This would be interesting since the old adage is that oil is where you find it. Producing oil wells exist even in Beverly Hills, Huntington Beach, and Long Beach, CA. These are some of America’s most affluent communities.
Regulatory
California is a major producer of petroleum, with more than 50 years’ experience with HF in vertical wells. Dr. Steven Bohlen, California’s Oil and Gas supervisor reporting directly to Governor Brown, discussed the rapid information-gathering, risk assessment, and regulation drafting required by California’s Senate Bill 4 (SB-4).2 SB-4 places encompassing demands for information from potential drillers. For example, the state has compiled a list of 200 analytes associated with HF that are of potential concern.
This extensive list was reviewed by John Connor of GSI Environmental, Inc. (Houston TX), who pointed out that the list could be reduced to about 30 analytes if one selected specific chemical markers for the potential problem materials (crude oil, produced water, flowback water, methane gas). He made the point that 200 analytes could be excessive and expensive.
When SB-4 was drafted about two years ago, the experience level and data availability were low. The legislators responded by casting a wide net. It seemed to me that SB represented the fledgling state of public knowledge two years ago. When nontechnical people are dealing with lots of potential risk, which is confounded by the claims of lobbyists, the public are probably best served by requesting more information. Expediency has a place in legislation. “Paralysis by analysis” is the other, too familiar, extreme. The State of New York’s moratorium was cited critically by several lecturers.
Despite the reputation that California regulators are difficult to work with, California has earned an enviable reputation for leading in public protection. Thus one might want to monitor California’s regulations. They may be ahead of other jurisdictions.
Regulatory philosophy
Regulatory philosophy is an important topic since much of the early problems reported in the press were created or at least compounded by drillers cutting corners or claiming “trade secrets” privilege to avoid responding to questions about their process and results. Dr. Briana Mordick of the Natural Resources Defense Council (San Francisco, CA) noted that available data may be incomplete, and thus the risks associated with fracking are unknowable. Hence, she advocates fracking should be delayed until the risks can be tabulated, evaluated, and mitigated.
In contrast, Dr. Steve Bohlen explained that, from where we are today, natural gas as an energy source is both less expensive and has a lower greenhouse gas impact than coal. Plus, it is the only alternative to coal that can meet the quantity demands over the next few decades. Californians drive 3 billion miles per year. Our society runs on fossil fuel.
Yes, Toyota introduced its hydrogen-powered automobile in the ACS booth as an example of sustainability. Toyota’s hydrogen car is scheduled for commercial introduction in the 2015 model year. However, have you seen a hydrogen fueling station in your neighborhood? I can see my city council reviewing the application for a filling station in Lafayette, CA. The opponents will show a picture of the demise of the Hindenburg and conflagration across the bay in San Bruno, CA. They might suggest relocating the station to the middle of San Francisco Bay or, better yet, Yucca Flats, NV.
Induced seismic activity
Dr. Adam Carpenter of the American Waterworks Association (Washington, DC) has worked on seismic issues for most of his career. Many have expressed concern that recycling of production water risks causing induced earthquakes. Carpenter advised that the actual risk is not predicable from present knowledge. He agreed that reinjection of wastewater at the Rocky Mountain Arsenal near Denver, CO, most probably induced an earthquake swarm. Plus, recently, another apparently induced swarm was co-located with PW recycling from wells in central Oklahoma.3 No other examples were cited. However, recycling PW has been every effective in Long Beach Harbor. Thus, Dr. Carpenter’s approach is to try reinjecting PW if it is probably advantageous, but monitor what happens seismically. Should problems arise, one might need a viable Plan B.
Methane
Methane’s global warming footprint was discussed in several lectures, most forcefully by Prof. Robert Howarth of Cornell University (Ithaca, NY). He described the global warming footprint of anthropogenic methane. Methane is a much more potent (25–75×, molecule to molecule) global warming contributor than CO2. Fossil fuel production and distribution is one methane source. Methane may be released as the well is drilled since the casing has not been cemented in place. Blowouts happen, such as BP’s infamous Deep Water Horizon disaster, but these are very rare.
After the well is completed, methane is flared or collected for use. Flaring is usually a temporary disposal technique that burns the gas to reduce the risk of explosion. Today, best practices require collecting the production gas by piping it to a collection and processing facility. From there, natural gas (greater than 90% methane) enters the commercial world as a fuel for furnaces, water heaters, and homes.
However, the American natural gas distribution system is leaky. Estimates vary, but Prof. Howarth chose to focus on an average leak rate of 5.8%. These leaks are an economic loss, and also an explosion hazard. Some gas delivery pipes in New York City are 130 years old. These iron pipes use butt-to-butt joints with gaskets and flanges that are bolted together. Pipes and bolts rust. Gas leaks are predictable over time (several decades or centuries).
For shock value, Prof. Howarth showed a map of Boston with bar graphs of methane emissions. Boston is not gas country, so these were all leaks. He then showed that one midsized city has replaced its pipes at a cost of about $2 billion. Methane leaks are nearly gone. Gas leaks are a recognized national problem. Even with the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, at the present rate, some cities will take a century to complete the job. By then, they will need to start over, since the useful life of piping is about a century, at the longest.
Prof. Howarth predicts that the methane leak rate would decrease to less than 3% to have a lower environmental footprint, equal to that of the same energy produced from coal. Looking longer term, he showed a slide of half a completed bridge—a bridge to nowhere. Others responded by pointing out that popular renewables all present unsolved challenges.
Other fracking solvents
Dr. Hari Viswanathan of the University of Southern California (Los Angeles) compared the properties of a purpose-designed fracking liquid with current water mixtures. Water’s only advantages are that it is not expensive and it is readily available. Water’s chemical and physical properties grouped at the bottom of the desirable properties list. The primary problem is that water and oil are at the extremes of polarity. Recall that likes dissolve likes.
Other alternative fracking liquids include CO2, propane, and diesel fuel. These would help oil and gas recovery by promoting solubility of the petroleum, plus probably have lower viscosity when in the producing formation. Deep wells often have a bottom hole temperature over 200 °C. Water does indeed become a less polar solvent above the critical temperature. However, normal deep well temperatures are well below the critical point of water, Tc = 374 °C.
Fracking’s impact on chemical laboratories, including staff
Managing public concern, adverse events, and good management of the producing field will require constant monitoring, from preinception to capping and abandonment. Think of the lab as being analogous to a clinical lab, where the patient is the well. Analytical results will provide diagnostic clues of remote events. With less than a decade of experience, best practices for fracking are just emerging.
For example, prior to spudding the well, surveys of groundwater and air quality will establish a baseline essential to estimate the impact of the well on these important matrices. One can expect imagined differences, which would be difficult to refute if no prior base case had been established. One example was reported in a lecture by Nima Jabbari (University of Southern California), who showed that it could take years for a point source failure to travel to the sampling site.
Dr. Art Fitchett of Thermo Fisher Scientific (Bannockburn, IL) described several applications of ion chromatography (IC) for assay of flowback and production water. The focus was on concentrated brine as found in the Marcellus Shale. IC can quickly separate many of the ions, but the sample is too concentrated and it overloads the column. One can dilute about 100× and shoot. This is manual. For higher throughput, Thermo Fisher Scientific also provides an automated dilutor. Gradient elution with columns packed with 4-μm-diam particles can cut run time in half, to under 30 min. Several application notes provide more detail.4
Standard methods
Dr. David Miller of the American Petroleum Institute (API) (Washington, DC) updated the audience on the programs offered by API in support of sustainable development of shale oil and gas. The API works with other associations such as ASTM to develop methods. ASTM has a comprehensive library of analytical methods relevant to oil and gas production. The Energy Institute in London also provides analytical methods to subscribers. Since HF technology has been used for decades for secondary oil recovery, some HF methods might be applicable to fracking technology.
Reference standards
During the panel discussion, an audience member asked how to obtain real samples and reference materials of flowback and production water. The answer was that personal contact was the best way to obtain aqueous samples. No one offered advice on reference standards. I anticipate further problems, i.e., instability of the samples since they are often aqueous suspensions of particles in brine may be an issue. Also, the composition of flowback water changes dramatically over the first few days after the fracturing. The flowback water varies from formation to formation. Production water from the Marcellus is not at all representative of PW from the Monterey.
Spills and accidents
Emergency response to inevitable accidents should be anticipated. Laboratory input should be expected during the planning stage, including drafting the environmental impact report, so that suitable instruments and staff are available should an incident occur. Portable analyzers such as handheld spectrometers and portable gas chromatographs and ion chromatographs may be on the list.
Analytical needs change with time
There are several stages to the life of the well. Each stage requires a monitoring protocol consistent with the risk, including severity and probability. In the initial stages the risk is transportation spills. In succeeding eons, the concern is that an abandoned, depleted well will cause future problems. Labs will need to provide assays in a variety of situations.
Summary
The first half-day of the program on hydraulic fracturing was organized by Dr. Thomas Barton, President of the American Chemical Society (Washington, DC). Ms. Donna Drogos, a Ph.D. candidate at the University of Wyoming (Laramie), organized the remaining two days. Both deserve special thanks for organizing the technical content and recruiting the speakers.
Despite the contentious discussions that hydraulic fracturing receives in the public press, the discussions at the ACS focused on the science. This allowed the audience to draw their own conclusions.
References
- Anon. The Outlook for Energy: A View to 2040; 2014, ExxonMobil Corp., Irving, TX; SP-134, pp. 52–55; http://cdn.exxonmobil.com/~/media/Reports/Outlook%20For%20Energy/2014/2014-Outlook-for-Energyprint-resolution.pdf
- http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_ id=201320140SB4
- Hand, E. Injection wells blamed in Oklahoma earthquakes. Science July 4, 2014, 345, 13.
- TN 138, TN139, and AN 1094, Thermo Fisher Scientific.
Robert L. Stevenson, Ph.D., is Editor, American Laboratory/Labcompare; e-mail: [email protected].