North America is undergoing a boom associated with the production of natural gas from dense shale rock formations. Natural gas is an efficient energy source and the cleanest-burning fossil fuel. The natural gas extracted from shale rock could become a significant global energy source.1
Although the energy industry has long known about huge gas resources trapped in shale rock formations, particularly in the United States, it is only over the last decade that energy companies have combined two established technologies - hydraulic fracturing and horizontal drilling - to unlock this resource.
This article will focus on the technique of hydraulic fracturing and in particular the common chemical additives used to support this technique. It is not a comprehensive review of all the chemicals and chemistries involved; readers interested in further information can refer to the footnotes.
There is currently a great deal of controversy associated with these chemical treatments. This article will provide some facts about the chemicals and chemistries used from a technical and environmental impact point of view.
Generally, the process of hydraulic fracturing involves pumping a viscous fluid, or pad, into a well faster than the fluid can escape into the formation. This causes the pressure to rise and the rock to break, creating artificial fractures or enlarging existing ones. A hydraulic fracture is a structure that is superimposed on the natural fracture leaving it undisturbed. As a result, the effective permeability of the reservoir remains unchanged; however, the wellbore radius is increased. This leads to increased productivity because of the larger surface area created between the well and the reservoir.
Hydraulic fracturing is a relatively new technique in terms of petroleum science, having been introduced just over 50 years ago.2 Classically, the fractures produced are approximately perpendicular to the axis of least stress, and for most deep reservoirs the minimal stresses are horizontal; hence, the fractures occur in the vertical plane.
The actual stresses can be calculated by balancing the vertical (geostatic) stresses with the horizontal stress. Taking into account a number of factors, the horizontal stress can be calculated from the corrected vertical stress. In some circumstances, in shallow reservoirs in particular, horizontal stresses can be created as well as vertical stresses.
The possible stress modes are shown in Table 1.
Table 1 Modes of Stress in Fractures
Knowledge of the stresses in a reservoir is essential to establish the pressure at which the initiation of a fracture can take place. The upper limit of this pressure usually can be calculated from the following formula:3
The pressure response during fracturing provides important information about the success of the operation. The efficiency of the fracturing fluid can be estimated from the closure time. The closure pressure is the pressure at which the width of the fracture becomes zero; this is normally the minimal horizontal stress.
All this information is important in the design and selection of the fracturing fluid and its components.
Hydraulic fracturing is becoming a common method of natural gas extraction in shale formations throughout the United States, including the following areas:
- The Marcellus shale, which extends from New York State through Pennsylvania and West Virginia and into parts of Ohio, Maryland, and Virginia
- The Haynesville-Bossier shale in Louisiana and Texas
- The Fayetteville shale in northern Arkansas and adjoining states
- The Barnett shale in Texas
- The Eagle Ford shale in southern Texas
- The Woodford shale in Oklahoma and Texas
Hydraulic fracturing also is being considered in Europe, where some field tests have been conducted.4
As was stated above, this has led to a certain amount of controversy over possible groundwater contamination, much of which is due to a lack of transparency regarding the associated chemicals used. This article will attempt to be as transparent as possible to allay if not dispel those fears, reasonable though they may be, by explaining which chemicals or chemical types are used and why they are used.
The use of fracturing fluids is critical in the stimulation of productivity by hydraulic fracturing. These fluids provide the means to produce the hydrostatic pressure required to create the hydraulic fracturing. In creating a hydraulic fracture, the pumped water has to be treated to increase its viscosity; this is done through the addition of viscosifiers or gelling agents.
After the formation has been fractured, a proppant, mainly sand, is added to the pumping fluid. This forms a slurry, which is used to prevent the newly formed fractures from closing when the pumping (hydrostatic) pressure is released. The transportability of this propping agent is dependent on which viscosifying agents have been added to the water or base fluid.5
The composition of the fracturing fluid therefore consists of a base fluid, usually water; a proppant, usually sand; a viscosifying agent; and some chemical additives. The total amount of chemical additives, including the viscosifying agent, used is less than 0.5% of the volume of fluid.6 These additives impart various properties that will be discussed later in this article.
The fracturing fluids are injected into the formation for the following critical reasons:
- To create a conductive patch from the wellbore to the formation
- To carry proppant into the fracture to create a conductive path for the fluids produced
The main fracturing fluid categories are
- Gelled fluids, including linear or cross-linked gels
- Foamed gels
- Plain water and potassium chloride (KCl) water
- Combination treatments (any combination of two or more of the fluids mentioned above)
The fluids used most commonly in shale gas formations are the gelled fluids, and this article will concentrate on their composition.
In general, the following chemical additives are added to the water and sand (or proppant) mixture. This is shown in Table 2, with the relative amounts used.
Table 2 Chemical Additives for Water and Sand
As can be seen, the overall amounts of chemical are relatively small, although the amounts of fluid are large.
The makeup of each fracturing fluid varies to meet the specific needs of each geological area; there is no one-size-fits-all formula for the volumes for each additive. In classifying fracturing fluids and their additives, it is important to realize that the service companies that provide these additives have developed a number of compounds with similar functional properties that are used for the same purpose in different well environments. The difference between additive formulations may be as small as a change in the concentration of a specific compound.
Although the hydraulic fracturing industry has a number of compounds that can be used in a hydraulic fracturing fluid, any single fracturing job would use only a few of the available additives. For example, Table 2 lists 12 commonly used types of additives, covering the range of possible functions that could be built into a fracturing fluid; anywhere from 3 to all 12 of these additives could be used in the composition of a specific fracturing fluid.
This article will now discuss each of these additives in regard to the chemistries deployed, their function, and their possible environmental fate.
More than half of all the fracturing treatments conducted to date have used fluids consisting of guar gums or guar derivatives such as hyropropylguar (HPG), hydroxypropylcellulose (HPC), carboxymethyl guar, and carboxymethyl hydropropyl guar.
Guar gum is a branched polysaccharide composed of the sugars mannose and galactose in the ratio 2:1 The backbone is a linear chain of β 1,4-linked mannose residues to which galactose residues are 1,6-linked at every second mannose, forming short side branches, as shown in this diagram:
Guar gum is more soluble than other similar gums and is a better stabilizer. It is not self-gelling, but cross-linking guar gum will cause it to gel in water. It is not affected by ionic strength or pH but will degrade at pH extremes at temperature (e.g., pH 3 at 50°C).7 It remains stable in solution over the pH range 5-7. Strong acids cause hydrolysis and loss of viscosity, and alkalis in strong concentration also tend to reduce viscosity. It is insoluble in most hydrocarbon solvents.
Guar gum has high low-shear viscosity but is strongly shear-thinning. It is very thixotropic above a 1% concentration, but below 0.3% the thixotropy is slight. It has a low-shear viscosity that is much greater than that of many other gums and generally greater than that of other hydrocolloids. It is economical because it has almost eight times the water-thickening potency of similar materials; therefore, only a very small quantity is needed to produce sufficient viscosity. The economics of using guar gum have shifted recently as a result of demand. The commodity price of guar has increased tenfold in recent months.8
The properties discussed above make guar gum ideal for use in fracturing fluid formulations as it acts as a viscosifier (when cross-linked), helping to gel the fluid, and/or as a stabilizer because it helps to prevent solid particles from settling.
Guar gum is a direct food additive that generally is recognized as safe by the U.S. Food and Drug Administration (FDA).9 It is highly biodegradable and is recognized as posing few environmental or toxicological problems.
Cross-linking, as was mentioned briefly above, is necessary and desirable to improve the gelling characteristics of guar gum or related products. It is desirable to have delayed cross-linking, and this can be achieved through the use of a number of systems, as will be explained below. Retarding the rate of reaction of the cross-linking allows the fluid to be pumped more easily.
These are the most common fracturing fluid cross-linkers and can be formed by boric acid, borax, an alkaline earth metal borate, or an alkali metal alkaline earth metal borate. It is essential that the borate source have around 30% boric acid. The boric acid forms a complex with the hydroxyl units of the guar gum polysaccharide, cross-linking the polymer units. This process lowers the pH (hence the need for pH control).10 These fluids provide excellent rheological, fluid loss control, and fracture conductivity properties in fluid temperatures up to 105°C.11
To allow use at higher temperatures, the use of magnesium oxide and magnesium fluoride has been developed. This effectively extends the range of these materials up to 150°C.12
Delay agents such as dialdehydes and polyols, for example, glycols and glycerol, have been used in the composition of fracturing fluids based on guar-type gums such as galctomannan. Again, this aids thermal stability.13
Organic titanium systems have been found to be useful cross-linkers14 but are used seldom if ever.
Various zirconium systems are used to ensure delayed cross-linking. These complexes are formed initially with low-molecular-weight compounds, which then are exchanged intramolecularly with the polysaccharides; this process causes the delayed cross-linking. The zirconium complexes that are used usually are initiated from compounds with diamine-based molecules such as hydroxyethyl-tris-(hydroxypropyl) ethylenediamine15 or from hydroxyl acids such as glycolic acid, lactic acid, and citric acid or polyhydroxy compounds such as arabitol, glycerol, and sorbitol. These materials then can form suitable gels with polysaccharides.
Clearly, the environmental fate and toxicology of the cross-linkers is more complex than that of food-grade polysaccharides. There is a lot of information available on boric acid. Boric acid naturally occurs in air, water (surface and ground water), soil, and plants, including food crops. It enters the environment through weathering of rocks, volatilization from seawater, and volcanic activity.16 Most boron compounds convert to boric acid in the environment, and the relatively high water solubility of boric acid results in the chemical reaching aquatic environments. Boric acid is therefore the boron compound of greatest environmental significance.17
It is assumed that boric acid is adsorbed to soil particles and aluminum and iron minerals and that this adsorption can be either reversible or irreversible, depending on soil characteristics. It is known that boric acid is mobile in soil.18
The EPA does not anticipate adverse effects on birds from the current use patterns of boric acid products.19
Surfactants generally are used in the formulation of fracturing fluids to aid and generate viscoelasticity. A range of surfactants have been used, including anionic, cationic, nonionic, and zwitterionic. These surfactants congregate into micelles, which interact to form a network that imparts viscous and elastic properties to the formulated fluid. One of the most commonly used surfactants is cetyl ammonium bromide, 20 a long-chain quaternary ammonium salt.
Amphoteric and zwitterionic surfactants are finding uses as viscoelastic agents in shale gas fracking because they have stability at temperatures up to 150°C.21
Surfactants are included in most aqueous fracturing fluids to improve compatibility with the hydrocarbon reservoir. It is important that the formation be water wet to achieve the maximum conductivity of hydrocarbon gas or fluids. A number of chemical types are used for this function. 22
The environmental fate of surfactants can be a complex issue,23 and some careful consideration will be required in choosing which surfactant to use.
Potassium chloride has been used as a clay stabilizer in hydraulic fracturing for many years. However, biodegradable alternatives are being examined because of concern about the environmental harm that may be caused by large additions of salts to the environment.24
The formation of scales-in particular calcium carbonate, calcium sulphate, and barium sulphate-can lead to permeability problems. For this reason, scale inhibitor is added to the fracturing fluid formulation so that it is placed in the newly made fractures.25 These chemicals tend to be one of two different types: either chelants such as ethylene diamine tetraacetic acid, citric acid, and gluconic acid or inhibitors such as phosphonates, polycarboxylates, and phosphate esters.
The environmental fate of the majority of these products is well known and has been studied widely,26 and the use of certain additives should be considered because of their potential environmental effects and a wide variety of biodegradable and nontoxic alternatives.
In the process of hydraulic fracturing, the properties of the reservoir formation may become disturbed. These properties must be restored after fracturing to achieve maximum well productivity. This can be achieved only when the solution viscosity and the molecular weight of the added gelling agent are reduced significantly; in other words, the fluid is degraded. There is a large amount of research and other findings on the kinetics of this degradation, particularly in the case of guar gums.27
The most common gel breakers are hypochlorite salts, which are familiar from their use in bleach and disinfectants. These are powerful oxidants that degrade the polymeric chains.28
The EPA generally recognizes these products as safe, in particular sodium hypochlorite.29
pH Adjusting Agents
These agents are usually necessary components of the fracturing fluid to adjust and maintain pH. They are either salts of a weak acid and a weak base such as carbonates and bicarbonates or weak acids such as formic acid and sulphamic acid.30
Many of the agents discussed here have been classified by the EPA as safe,31 such as formic acid. However, there are stated limits for operation, and those limits should be considered before any proposed application of fracturing fluid.
Iron Control Agent
The presence of iron can present a significant and complex problem in fracturing operations and can differ depending on the nature of the fracturing fluid. In acidic conditions, the fluid can dissolve iron from the equipment and flow lines and may dissolve additional iron as it reacts with the formation. This iron then can precipitate in the fracturing fluid if it does not contain a suitable control agent. The result is that this precipitate can be carried back on flowback to the wellbore, significantly affecting the permeability, and can have a detrimental effect on recovery of the fracturing fluid and on productivity.32
The products used in this case are the same as or similar to the chelating agents used in scale control, such as ethylenediaminetetraacetic acid and citric acid.
Corrosion inhibitors usually are added to the formulation of fracturing fluids in very small amounts to inhibit corrosion of equipment and well casings as fluids are placed into the formation and during flowback. The most common product in use for this application is N,N-dimethylformamide (DMF).
When DMF is released into water, it degrades there and does not move into other media. When the releases are into soil, most of the DMF remains in the soil, presumably in soil pore water, until it is degraded by biological and chemical reaction. Release to water or soil is expected to be followed by relatively rapid biodegradation (half-life of 18-36 hours). If DMF reaches groundwater, its anaerobic degradation will be slow.33
When the fracturing fluid is composed of guar gum or other natural polymers, it is advisable to include a small amount of biocide in the formulation to prevent any undesired degradation and changes in rheological properties. The biocides that are suitable for this function are all heterocyclic sulfur compounds such as 2-mercaptobenzimidazole.34
The environmental impact and toxic effects of 2-mercaptobezimidazole (2-MBT) are well documented.35 It has been found that this compound and similar compounds undergo only limited biodegradation and have aquatic toxicity.
The use of 15% hydrochloric acid or muriatic acid helps dissolve minerals and initiate fractures in the rock. It is assumed that in the operation of the fracturing fluid, all the acid is reacted. However, recognition that any acid still remaining may pose a problem to the environment is required.36
When released into the soil, this material is not expected to biodegrade and may leach into groundwater.
On occasion, a friction reducer is added to the formulation. However, guar is itself a friction reducer, and so it is not always necessary to add a further specialist polymer to achieve this effect. Indeed, the use of guar (not cross-linked) as a friction reducer is commonplace in fracturing.
It is the purpose of this article to give technical and environmental information in an overview as accurately and openly as possible. It is for the reader to judge what, if any, impacts from the use of chemicals are likely. Undoubtedly, some further environmental improvements are necessary, but in a balanced approach so is the need for reliable and sustainable cheap energy. This article has looked at the process of hydraulic fracturing and the main chemicals and chemical types used in supporting that process. The overall process of hydraulic fracturing and its environmental impact is a matter of current debate.37 This debate is likely to become even more topical, but in science and engineering circles the need for reasoned factual argument is paramount alongside openness and transparency.38
- 1 Kaskey, Jack. Cheap Shale Gas Means Record U.S. Chemical Industry Growth, Bloomberg.com, August 10, 2011, http://www.bloomberg.com/news/2011-08-10/cheap-shale-gas-means-record-u-s-chemical-industry-expansion.html ; and Shauk, Zain. Petrochemical Industry Takes Note of Shale Bounty, Fuelfix.com, March 29, 2012, http://fuelfix.com/blog/2012/03/29/petrochemical-industry-takes-note-of-shale-bounty .
- 2 Hubbert, M. K. and D. G. Willis, Mechanics of Hydraulic Fracturing, Trans. AIME, vol. 210, pp. 153-166, 1957.
- 3 Von Terzaghi, K. (1923). Die Berechnung der durchlässigkeit des tones aus dem verlauf der hydromechanischen spannungserscheinungen. Sitzungsbericht der Akademie der Wissenschaften (Wien) : Mathematisch-Naturwissenschaftlichen Klasse, 132, 125-138.
- 4 Wynn, Gerard. EU Safety-First View on Shale Gas Makes Sense, http://www.reuters.com/article/2012/03/27/energy-shale-idUSL6E8EN4W620120327
- 5 Lukocs, B., Mesher, S., Wilson, T.P.J., et al. Non-Volatile Phosphorus Hydrocarbon Gelling Agent. U. S. Patent 8,084,401, 2011
- 6 Chemicals Used in Hydraulic Fracturing. http://www.fracfocus.org/water-protection/drilling-usage .
- 7 Mathur, N. K. Industrial Galactomannan Polysaccharides Boca Raton, FL: Taylor and Francis, 2012.
- 8 Commodity Online. Guar seed, gum prices tumble on suspension of futures, http://www.commodityonline.com/news/guar-seed-gum-prices-tumble-on-suspension-of-futures-47028-3-47029.html . March 28, 2012.
- 9 Code of Federal Regulations, Food and Drugs, Title 21, Sec. 184.1339. http://www.accessdata.fda.gov/scripts/cdrh/cfdocs/cfcfr/CFRSearch.cfm?fr=184.1339&SearchTerm=guar%20gum .
- 10 Ainley, B. R., and McConnell, S. B. Delayed Borate Cross-Linked Fracturing Fluid. EP Patent 528461, 1993.
- 11 Brannon, H. D., and Ault, M. G., BJ Services. New, Delayed Borate-Crosslinked Fluid Provides Improved Fracture Conductivity in High-Temperature Applications. SPE 22838-MS, SPE Annual Technical Conference and Exhibition, Dallas, TX, October 6-9, 1991.
- 12 Nimerick, K.H., Crown, C.W., McConnell, S.B., Ainley, B. Method of Using Borate Crosslinked Fracturing Fluid Having Increased Temperature Range. U.S. Patent 5259455, 1993.
- 13 Ainley and McConnell, op cit.
- 14 Putzig, D. E., and Smeltz, K. C. Organic Titanium Compositions Useful as Cross-Linkers. EP Patent 195531, 1986.
- 15 Putzig, D. E. Zirconium Chelates and Their Use for Cross-Linking. EP Patent 278684, 1988.
- 16 World Health Organization. Boron, Environmental Health Criteria 204. Geneva, Switzerland, 1998.
- 17 Eisler, R. Boron Hazards to Fish, Wildlife, and Invertebrates: A Synoptic Review. U.S. Fish and Wildlife Serv. Biol. Rep., vol. 85, no. 1, pp. 1-32, 1990.
- 18 Reregistration Eligibility Decision Document: Boric Acid and Its Sodium Salts. EPA 738-R-93-017. U.S. Environmental Protection Agency, Office of Pesticide Programs, U.S. Government Printing Office: Washington, DC, September 1993.
- 19 Reregistration Eligibility Decision Document: Boric Acid and Its Sodium Salts, op cit.
- 20 Lukocs et al., op cit.
- 21 Allan, T. L., Amin, J., Olsen, A. K., and Pierce, R. G. Fracturing Fluid Containing Amphoteric Glycinate Surfactant. U.S. Patent 7399732, 2008.
- 22 Penny, G. S. Method of Increasing Hydrocarbon Production from Subterranean Formations. U.S. Patent 4702849, 1987.
- 23 McWilliams, P. and Payne, G. Bioaccumulation Potential of Surfactants: A Review. Chemistry in the Oil Industry VII, Royal Society of Chemistry, 2002, pp. 44-56.
- 24 Guidelines for Drinking-Water Quality, 2nd ed. Vol. 2: Health Criteria and Other Supporting Information. World Health Organization, Geneva, Switzerland, 1996.
- 25 Watkins, D. R., Clemens, J. J., Smith, J. C., Sharma, S. N., and Edwards, H. G. Use of Scale Inhibitors in Hydraulic Fracture Fluids to Prevent Scale Build-up. U.S. Patent 5224543, 1993.
- 26 Nowack, B. (2003) Environmental Chemistry of Phosphonates, Water Research, vol. 37, no 11, 2533-2546, 2003, http://s3.amazonaws.com/publicationslist.org/data/nowack/ref-38/Nowack%20WatRes%20review%20%282003%29.pdf
- 27 Craig, D., and Holditch, S. A. The Degradation of Hydroxypropyl Guar Fracturing Fluids by Enzyme, Oxidative and Catalyzed Oxidative Breakers. Proceedings of the Thirty-Ninth Annual Southwestern Petroleum Short Course, vol. 39, Lubbock, TX, April 22-23, 1992.
- 28Bielewicz, D., and Kraj, L. Laboratory Data on the Effectivity of Chemical Breakers in Mud and Filtercake (Untersuchungen zur Effektivität von Degradationsmitteln in Spülungen)., Erdöl, Erdgas, Kohle, vol. 114, no. 2, pp. 76-79, 1998.
- 29U.S. Environmental Protection Agency. United States Pesticides and Toxic Substances (7508W) 738-F-91-108, September 1991.
- 30 Nimerick, K. and Boney, C.L. Fracturing Fluid and Method. GB Patent 2291907, 1996.
- 31 Nowack, op cit.
- 32 Smolarchuk, P., and Dill, W. Iron Control in Fracturing and Acidizing. Proceedings of 37th Ann. Cim. Petrol Soc. Technical Mtg., Calgary, Canada, June 8-11, 1986.
- 33 Concise International Chemical Assessment Document 31: N,N-Dimethylformamide. World Health Organization, Geneva, Switzerland, 2001.
- 34 Kanda, S., Yanagita, M., and Sekimoto, Y. GB Patent 2172007, 1986.
- 35 H Hanssen, H. W., and Henderson, N. D. A Review of the Environmental Impact and Toxic Effects of 2-MBT. Environmental Protection Division, British Columbia, 1991.
- 36 Watkins et al., op cit.
- 37 Huffington Post. 'Promised Land': Matt Damon's Fracking Film To Highlight Controversial Drilling Process. http://www.huffingtonpost.com/2012/04/06/promised-land-matt-damon-fracking_n_1408501.html.
- 38 King, G. E. Hydraulic Fracturing 101: What Every Representative, Environmentalist, Regulator, Reporter, Investor, University Researcher, Neighbor and Engineer Should Know about Estimating Frac Risk and Improving Frac Performance in Unconventional Gas and Oil Wells. SPE 152596. SPE Hydraulic Fracturing Technology Conference, The Woodlands, TX, February 6-8, 2012.