Environmental Aspects of Hydraulic Fracturing: What Are the Facts

Chapter 1

Environmental Aspects of Hydraulic Fracturing: What Are the Facts? Downloaded by 138.219.53.221 on December 24, 2015 | http://pubs.acs.org Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch001

George E. King* and Danny Durham Apache Corporation, 2000 Post Oak Blvd., Suite 100, Houston, Texas 77056-4400, United States *E-mail: [email protected]

Hydraulic fracturing is an established oil and gas well stimulation technique that has been in play in various forms for over sixty years and is critical to today’s United States (U.S.) production of most oil and gas resources (Montgomery, C., Smith, M. Hydraulic Fracturing: History Of An Enduring Technology. SPE JPT 2010, 62, 12, 26-32). As with any industrial activity, there are risks, both immediate and latent that must be considered. Concerns have been raised recently of ground water contamination, air pollution and other problems that may occur either as routine production activities or as a result of fracturing. These issues are complicated since oil and gas, with a myriad of co-generated hydrocarbon molecules from alkanes to ring compounds of benzene, toluene and xylenes, are simultaneously produced by naturally occurring thermal and pressure driven maturation reaction of some forms of organic carbons laid down with the sediments. Sources of many of these hydrocarbons include the organicrich shales that were deposited throughout many geologic time periods and in most parts of the world (Toutelot, H. Black Shale – its Deposition and Diagenesis. Clays and Clay Minerals, 1979, 27, 5, 313-321). As oil and gas is produced, some moves out of the shales and may be trapped in rock containments called reservoirs, but when these reservoirs are filled or when they are absent, the hydrocarbons rise via buoyancy towards the surface forming weathered or bacterial altered deposits near surface, or co-occupying space with subterranean water reservoirs, both brine and fresh. © 2015 American Chemical Society In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Many concerns of potential pollution from hydraulic fracturing are actually concerns of materials transport, well construction, hydrocarbon production or distribution. This chapter will examine the direct impact of hydraulic fracturing as a primary target and the associated activities of hydrocarbon development as a secondary effort, using both historical performance and scientifically sound research methods.

Downloaded by 138.219.53.221 on December 24, 2015 | http://pubs.acs.org Publication Date (Web): December 15, 2015 | doi: 10.1021/bk-2015-1216.ch001

Hydraulic Fracturing: What Is It? Oil and gas well fracturing, in the most simple of terms, creates a crack or fracture through hydrocarbon bearing rock using pressure and an injected water, oil or gas-based fluid to oppose insitu stresses and rock strata tensile strength to create a fracture that may grow vertically and laterally outward from the well (1). After the fracture is initiated at the wellbore and widened by increasing injection rate, a proppant material, usually round sand or man-made ceramic, is carried into the fracture by the injected fluid, packing the fracture with sufficient proppant to maintain a stable flow path along the fracture after the hydraulic fracturing pressure is released. Selection of types and volumes of both fluid and proppant depend on the geologic characteristics of the rock and the requirements of fracture flow capacity to enable hydrocarbon fluids to flow from the formation toward the wellbore. Sub-surface elements of oil and gas well developments and hydraulic fracturing are relatively unique among engineering endeavors in that the final product; in this case the well and the hydraulically-formed fractures, cannot be visibly examined beyond the limited extent of the well’s interior piping, and therefore must be monitored remotely by various fit-for-purpose technologies. Added to complexity is the widely varying depositional geology of the earth where oil and gas is evolved and often trapped. Fracture shape varies with the specific conditions but is usually in the range of a few hundred feet along vertical and horizontal planes within the rock with lateral orientation dictated by stresses within the rocks. At depths greater than about a thousand feet, the weight of the overlying rock forms a large vertical stress, σv, which is usually greater that either the maximum horizontal stress, σhmax, or the minimum horizontal stress, σhmin; meaning fractures created in this stress environment will be vertical as the lower horizontal stresses are easier to push apart. Native stress fields within the rock, namely σhmax and σhmin, force the fracture to grow perpendicular to the minimum horizontal stress (the σhmin is easier to push back than the σhmax). Fractures leaving a vertical well will usually develop along the wellbore, growing upward until the limiting factors of leak-off, barriers and rock stresses stop the growth. Fractures leaving a horizontal well may travel along the wellbore or at an angle to the wellbore depending on the direction in which the horizontal well is drilled, Figure 1. The intersection of a transverse fracture with the horizontal wellbore may be a tortuosity restriction in conventional formations (non-shales), but is usually an acceptable flow intersection in unconventional completions. 2 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Figure 1. Orientation of wellbore to fracture direction. This is a critical element of wellbore orientation design. Factors such as natural fractures, bedding planes (sediment deposition streaks that accentuate or limit flow), and brittle or ductile rock all combine to shape the fracture. The intersection of the fracture with the wellbore is controllable only as much as the wellbore can be guided by directional drilling in the subsurface. In formations where fracturing is required, the wellbore acts as a “platform” from which to place fractures into the oil or gas filled rocks. The intersection of the fracture along the vertical well is the easiest to describe since the fracture follows the vertical wellbore until it limited by formation and application restraints. The natural containment barriers in reservoirs are extremely strong; proven by the fact that much of the low density oil, gas, and connate water remained trapped there even after millions of years of major earthquakes and other tectonic events. Fracture growth is limited by both natural and applied forces and factors. Changing depositional environments have shaped the rock strata for millennia, creating rock layers with different characteristics, many of which cannot easily be fractured. These fracture barriers and in situ stresses control the extent to which a fracture can develop, but are generally beyond the control of surface operations. The major fracturing design mechanism that is at least partly within the control of the fracturing applier is the type, volume, and injection rate of fracturing fluid. Targeted formations for the oil industry are those with sufficient open space between the rock grains (porosity) and possessing sufficient open passages between the pores to allow fluids to flow through the rock (permeability). As a fracture grows outward from the well, some of the injected fluid is continually lost to the permeable formation, reducing the pressure in the fracture and eventually stopping fracture growth as the total leak-off rate equals the injected rate. As fluid is lost from the volume in the fracture, the proppant is continuously concentrated and soon reaches the point where a screen-out (proppant “bridges-off”) occurs in the fracture and halts fracture fluid injection. Attempting to continue injecting beyond this leak-off dictated limit is futile, adding expense without possibility of economic benefit. The upper limit of pressure and fracture fluid injection rate is set by the size and strength of the pipe and the length of the wellbore to the 3 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


point of fracturing. Increasing friction pressure losses at higher flow rates place an upper limit on injection rate. Geology may be the biggest natural control of all and is always a major factor in the ability to generate oil, to produce large structures or “traps” that can produce conventional reservoirs and also controls the ability to reach the hydrocarbon deposits with the technology in place at the time. The only constant in the geology of the Earth is change, as attested to by millions of years of earthquakes, volcanic activity, mountain erosion, natural seeps of oil, gas and salt water, and a thousand other continuously changing processes, large and small. The need for hydraulic fracturing depends on the natural flow capacity or permeability of the formation. Economic flow from the earliest wells depended on the wellbore contacting formations with high natural flow capacity. As hydrocarbon reserves in these high permeability formations ran low, attention turned to technologies that could accelerate hydrocarbon flow from lower permeability formations. Fracturing was one of the main technologies that consistently improved flow. Marine shales that are the target of much of the oil and gas exploration today are the source for most non-bacterial deposits of oil and gas (2). Gas and oil-creating shales differ from sandstones by having extremely fine matrix particles, usually 5 to 20 microns in diameter and high total porosity that is poorly connected by restricted pore throats barely larger than an oil molecule. The permeability of these shale rocks are on the order of 10 to 1000 nanodarcies, although some shales have been naturally fractured by geological uplifts or other tectonic events and may have permeabilities through the natural fractures that are two or three folds higher than the permeability of the shale matrix. Total organic carbon (TOC) in prospective hydrocarbon-developing shales is usually 1% to 10% by volume, mixed within the rock-forming debris and deposited with the silt-sized particles and radiolaria (protozoa) skeletons. After burial with heat and pressure from the earth over geologic time, some of the organics may mature into a varied composition of hydrocarbons in a “thermogenic” action involving pressure and high temperature. Roughly 96% of seep gas and all of the seeping oil comes from thermogenic sources (3). As hydrocarbon reserves have declined, these low permeability shale formations, part of the vast shale belts of the world, have become the oil and gas reserves for the future. Hydraulic fracturing in these ultra-tight formations is a flow enabling technology and production would not be possible without it. Conventional formations (those which do not require fracturing to accelerate or enable flow of fluid in its pores) hold only a fraction of the total oil and gas generated in source rocks over millions of years. Hydrocarbons migrate out of the source rocks over geologic time and are carried upward by buoyancy with some oil and gas being trapped by the natural geologic traps that form the thousands of oil and gas fields around the world, with the remainder of escaping hydrocarbons traveling upward to the surface, often fully or partly oxidized to CO2 or being degraded by bacteria into a thicker hydrocarbon mass that is near-surface or seeps out at the surface. This upward hydrocarbon migration forms thousands of natural oil and gas seeps across the globe that over-lie depositional basins that are or have been active drilling and oil production areas. The oil and gas “springs” of New 4 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


York and western Pennsylvania (described in 1636 and mapped in 1748), the La Brea tar pits, the Coal Point seeps in the Santa Barbara Channel, Lake Guanoco in Venezuela, and the Pitch Lake in Trinidad, are western hemisphere examples of these historic oil seeps (4). The vast reserves of western Canadian Tar Sands are also examples of this hydrocarbon migration and near-surface degradation. As hydrocarbon migrates upward, the hydrocarbons that are not trapped in impermeable rock structures move further upward and are often trapped in rock layers which may also hold fresh or salt water. Documented cases of oil and gas sharing the same reservoirs are common. The history of oil and gas well development reaches back nearly 200 years in the U.S. to William Hart’s first shale gas well drilled near Fredonia New York in 1821, which stuck flowing gas at a depth of 28 feet. Edwin Drake’s purpose-drilled oil well, about sixty miles southwest near Titusville Pennsylvania, struck flowing oil at 69-1/2 feet. These two very early wells demonstrate that it should not be a surprise that oil and gas often cohabitate shallow fresh water aquifers in the areas of natural seeps (5). As the petroleum industry was developed in areas like Pennsylvania and the Santa Barbara channel, a notable decrease in emissions from some seeps has been documented. Wells drilled into the seep-powering source rocks of the coal point seep have reduced initial emissions over 50% (6). There is a level of risk of pollution in every human or natural endeavor. Pollution by oil and gas from seeps is a natural occurring act demonstrated by the volume of gas and oil that flows from tens of thousands of natural seeps, both onshore and offshore. Estimates of world-wide methane emissions from natural seeps range from about 45 terragrams (Tg) or about 6.4 billion cubic feet (bcf) per day (2, 7). Since the 1800’s, the oil and gas industry has gone from a frantic and frequently unruly place to a highly scientific, engineered, and technical world. It is useful to look back a few years and see the advancements in the oilfield and how technology development has changed the energy industry, even in the last few years. Pollution from wells and the associated processing and distribution systems has been demonstrated to be preventable if the companies and governments that are involved in production will operate in a responsible manner. The fracturing process, using fresh or salt water, chemicals and proppant, has been used over a million times with very few problems (1). Potential for pollution by fracturing exists but has been rated as a low risk by numerous studies, particularly if safer chemicals are used and the wells are designed to operate successfully during and after the fracturing treatment (8). Most problems in actual field studies have been identified as transport (major) and well construction (minor) (8–10). Although it would be easy to identify the risks only from hydraulic fracturing, the fracturing technique would not be applied without the other well development components, e.g., drilling, well construction, materials transport activities, produced water handling and production. The number of activities involved in drilling a well and the time and money spent on each varies widely. Figure 2 estimates most of these activities for US onshore, with estimates of time and money involved in each. Time and cost in other areas of the world will vary widely depending on but not limited to location, 5 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


government requirements, skill availability, available data on the geology and local infrastructure. Fluid flow through rocks must be through the pores and/or open natural fractures. Permeability is generally proportional to the square of the size of open passages through the rock although an exact linkage between pore dimensions and permeability is only possible in rocks with relatively consistent pore size and pore connections (pore throats) with single phase fluids with no wetting. Calculating or assuming a single permeability for a formation using the Darcy equation (an empirical equation developed in the 1850’s) is problematic since formation matrix permeability, particularly in shales, may vary by two or more orders of magnitude and the extremely high capillary blocking pressure in nanometer to micro meter-sized pores and fractures may make Darcy law unusable for precise prediction. Additionally, significant flow through ultra-low permeability shales is thought to travel in the natural fractures where width of the fracture is highly variable or through macro pores which make up only a small percent of the total effectively-connected porosity (11). Middle Eastern and Gulf of Mexico deep water oil and gas reservoirs are among some of the highest permeability hydrocarbon reservoirs while gas and oil shales are very low permeability, often with permeability ranges of five nanodarcies to over a thousand nanodarcies (1 microdarcy). Shale reservoirs, whether they contain gas or liquids are in a similar range of permeabilities; however, gas, which has a much lower viscosity than oil, can be more easily targeted by fracturing stimulation in low permeability formations than can the higher viscosity oil. A minimum permeability of formations that can be economically stimulated depends on average effective permeability, produced fluid viscosity and economics of the development. A generalized comparison of the typical permeability ranges of different rocks is illustrated in Figure 3. Each formation has a range of permeability and the deposition environment and post depositional modification is often the major control. Fracturing is used in the lowest permeability reservoirs, such as shale, to enable flow, while a different fracturing job design is sometimes used in higher permeability formations to accelerate flow. The job type and the design depend on type of fluid being produced and specific rock characteristics. Some shales have permeabilities that are so low that the velocity of liquid flow through their pores cannot be directly measured by flow in laboratory tests. In these cases, although the total amount of hydrocarbon in place may be exceptionally large, the ability to recover the potential resource is restricted by time. The lower the formation permeability, the more fracture-to-formation contact area is needed to provide access to the micro-cracks and small natural fractures that offer higher flow capacity than the matrix. Creating extremely large contact areas requires large volumes of fracture fluids. Fractures are usually very narrow and may close completely if sufficient proppant is not placed to offset the closure pressure of the rock. Examples of fractures in rock at a depth of about 4500 feet are shown in Figure 4. These fractures, filmed with a downhole television camera in a well with an open-hole pay zone have a characteristic width of about 1/8th to ¼ of an inch (3 to 6 mm) 6 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


and their flow capacity is several orders of magnitude higher than flow through the matrix of the rock.

Figure 2. Activities and estimates of time and cost for an onshore U.S. multiple well development.

Figure 3. Permeability range comparison of rocks on a log scale. The low end of the permeability scale is matrix permeability while the upper end of permeability is through closed or open natural fractures. 7 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Figure 4. Downhole camera pictures of fractures in vertical wells at depths of about 4500 ft (~1400 m) (12). These pictures are still shots of video recordings in open hole wells in west Texas in 1970’s. Top Left – Fractures interrupted by a thin shale layer. Top Right – Fracture propped open by a rock fragment. Bottom Left – fracture at a pressure of simple fresh water hydrostatic. Bottom Right – same fracture as on left, except opened wider by injection pressure. Most oil and gas zones that are targets for fracturing are three thousand to over ten thousand feet deep and most fresh water sands are less than 300 to 1000 feet deep so separation is usually adequate. Separation between top of fracture and the fresh water table is often ½ to over one mile, thus potential for a fracture to even be close to a fresh water sand is very remote in most cases. Where fresh water and oil or gas zones are close together in very shallow or mixed deposits, extra care with well construction is necessary and fracturing is not commonly used. Fracturing effectively increases the size of the area that can be economically drained, thus fewer wells are required to produce the oil and gas from a field. In a moderate permeability reservoir a fractured vertical well can produce oil or gas from an area that may take 3 to 5 or more unfractured wells depending on formation permeability. Reducing footprint area drives conservation of land surface area and reduces waste. Fracturing can accelerate production from low to moderate permeability reservoirs and enable gas and oil production from those reservoirs with permeability so low they will not flow on their own. To optimize production from the lowest producible formations, which include the various gas and hydrocarbon liquid producing shales, two established technologies – fracturing and deviated wells were joined, starting in the early 1970s – with spectacular results (13). Using horizontal wells with lengths of one to two miles (1.6 to 3.2 km), and creating fractures about every 30 to 75 feet (9 to 23 m), reduced well count 8 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


again. A multi-fractured horizontal well in a very low permeability reservoir (0.0001 millidarcy [md]) may replace ten to twenty fractured vertical wells. This reduction in total well count is highly significant since the only documented subsurface leak paths from wells are small amounts of seepage along the vertical section of the wellbore (14). Reducing the well count by an order of magnitude and placing a long unperforated, cemented vertical well section, often behind an additional steel casing and cement barrier, sharply reduces methane or oil leak risk, regardless of the well design or location. Horizontal wells, which can have a horizontal displacement or “reach” of several miles, also enable wells to be located on remote pads or drilling plots away from urban or sensitive areas. One example of this from the Horn River area of British Colombia is shown in Figure 5 (15). This six acre pad, with twelve wells, each with 12 to 18 fracture stages of 1 to 4 clusters per stage, effectively and economically produces gas (at a depth of eight thousand feet) from beneath six thousand acres of forest. This type of development achieved a 93% reduction in surface area footprint over the surface area that would have been required to develop the same reservoir area requiring over ten times more fractured vertical wells.

Figure 5. An Apache Corporation six-acre pad with twelve horizontal, multi-fractured wells that access 6,000 gross acres of shale gas reservoir. Photo courtesy of Brad Affleck (16).

One of the most frequently voiced concerns about hydraulic fracturing is that fracturing would contaminate groundwater with methane gas or oil. Potential to fracture into water sands from deep hydrocarbon zones is exceptionally low as shown by microseismic monitoring data that established the distance between the “top” of fractures and the bottom of the deepest water zones in thousands of fracture treatments in the Barnett Shale, Table 1 (17). This microseismic database contains nearly four thousand hydraulic fracture treatments with clearances from the tops of fractures to the base of the deepest fresh water in each fracture treatment in four major shale fields. 9 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Shale

Number of Fracs with Microseismic Data

Primary Pay Zone Depth

Fresh Water Depth [Typical] (Deepest)

Typical Distance between top of Fracture and Deepest Water

Closest Approach of Top of Fracture in Shallowest Pay to Deepest Fresh Water

Barnett (TX)

3000+

4700′ to 8000′

[500′] (1200′)

4800′

2800′

Eagle Ford (TX)

300+

8000′ to 13,000′

[200′] (400′)

7000′

6000′

Marcellus (PA)

300+

5000′ to 8500′

[600′] (1000′)

3800′

3800′

Woodford (OK)

200+

4400′ to 10,000′

[200′] (600′)

7500′

4000′

10


Table 1. Fracture Height-Growth Limits in Four Major U.S. Shale Plays

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Smaller data sets for Eagle Ford, Woodford, and Marcellus show the same type of response. Fractures are typically very limited in vertical height development (17).


Drilling and Well Construction Although the action of fracturing rock is rarely a threat to groundwater supplies, well construction has been demonstrated to be a potential pollution problem in some studies. The most significant potential leak pathway for methane is either through the completion barriers (casing and cement pairs) from inside to outside or along the vertical cement isolation sheath that forms the final seal after casing has been run. Well construction, indicated by several studies to be a minor but persistent leak potential, requires a closer look for pollution potential. The Norsok D-010 report on well integrity in drilling and well operations defines the minimum performance-oriented requirements and guidelines for well design, planning and execution of safe well operations and defines well integrity as “Application of technical, operational and organizational solutions to reduce risk of uncontrolled release of formation fluids throughout the life cycle of a well” (18). Documented research projects covering well failure and leak information on several hundred thousand wells worldwide with leak type, rate and frequency indicate that although some wells do have small seepage leaks, the fraction leaking are a small subset of the total and a very small number of the leaking wells are by far the worst offenders (9, 10, 14, 19). The objectives of well construction include the following: •

• •

Isolation of any produced fluids within the well from the formations and fluids above the pay zone. This protects groundwater and the producible mineral resource from contamination. Protection of the casing exterior from chemical attack and load impingement. Setting of multiple nested barriers and designing a well for containment in the event of an inner barrier failure (9). Cement and steel are the main cornerstones of establishing effective isolation over the life of the well. Steel alloy pipe has evolved over the past century and offers strength and corrosion resistance that was unavailable fifty years ago. The weak point in casing and tubing design is usually the threaded connection. Connection selection and connection make-up procedures may be problem causes in some operations; however, highly effective connections and proven make-up procedures are available.

As the well is drilled, the drilling is interrupted at intervals dictated by formation pressure, fluid type and rock strength characteristics, and steel pipe is run to the bottom of the drilled interval and then cemented in place. Cement slurry (powdered cement, mixed with water – no sand or gravel) is pumped down the casing and up the annulus between the casing and the drilled hole. Once set, cement has similar compressive and tensile strengths to the rocks through which 11 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


the hole has been drilled (in the range of five thousand to over ten thousand psi unconfined rock compressive strengths). The cementing step is actually a series of actions including clearing the hole of cuttings and highly gelled drilling fluids, then cleaning the pipe and casing walls to remove filter cake and other coatings before circulating cement into place. Figure 6 conveys the actions in a simple step-wise schematic of a generic cement job.

Figure 6. A sequence of basic operations involved in well completions starting with the cementing activities involved in surface casing installation to isolate and protect fresh water. Effectively cementing the annulus between the outer casing body and the drilled hole requires pipe be sufficiently centralized and proper cementing procedures be followed. Amount of cement required for a good seal varies with conditions but even zones of five thousand psi or more can be isolated with as little as 50 feet of properly blended and placed cement (20). Typical cementing zone lengths range from two hundred feet (60 m) to over a thousand feet in a single cementing stage. Full columns of cement (total depth to surface) can rarely be run in a single stage without reverting to light weight cement or two-stage jobs because of formation fracturing potential with the dense (16 pounds per gallon cement. The majority of wells do not pollute, but some obviously have done so (21, 22). Well construction improvement leading to better isolation is a major goal within the industry. Hydrocarbon producing wells are a nested collection of pipe, cement, seals, and valves that form multiple barriers between produced well fluids and the outside environment. The concept of well design is if the inside barrier fails (e.g., a leak in tubing allows sustained pressure in the annulus), the next barrier will prevent 12 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

leakage outside of the well – essentially a barriers-within-barriers. Modern well design favors more barriers at the surface and across protected water zones and fewer barriers toward the bottom of the well where the perforations and fractures are placed to encourage flow into the well.


Cementing and Isolation Testing Monitoring and evaluating cement quality, bonding, strength and durability is a science itself with over a thousand publically-available, presented and published technical articles and studies. Although cementing science is well known, getting an effective cement job in the field often requires a large amount of attention to detail. An experienced engineer or foreman can often forecast the quality of a cement isolation step from the cement job’s pump chart recording of density, pump rate, pressure and returns. This type of evaluation is immediately available, requires no added equipment or cost and is superior to most cement monitoring methods of tools on the market, Figure 7.

Figure 7. Upper: Cement pump charts of measurements at each step are one of the best quality checks available on cement. Flow return records can be added check displacement volume. Timing of cement arrival or markers in the returning fluids is an effective indicator of cement fill and mud displacement. Lower: Description of each of the numbered events in the graph. 13 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Testing and/or regular monitoring is required by all states and often mandated for specific areas when detrimental conditions exist. The only proof of isolation continues to be a pressure test, commonly required for all surface strings where fresh water or the surface must be protected. Cement is not always easy to place. A full static column of regular cement, with a density of about 16 lb. per gallon exerts a static force at the bottom of the hole equal to a pressure of 0.83 psi per foot of the true vertical depth (TVD) of the cement column. The amount of pressure generated by the fluid density in a long vertical column of cement may fracture most formations – damaging the rock and compromising well integrity. Lower density cements may still be too heavy to accomplish a full cement column without going to a multi-stage cement job. The required activity of circulating the viscous cement also increases flowing friction backpressure and thus increases its equivalent circulating density – adding another 1 to 2 lb. per gallon density increase that raises the dynamic density of the cement column to as much as 0.94 psi/ft while the liquid cement is circulating. A multi-stage cement job is required to place a full cement column in most wells. The ports in a multi-stage cement placement tool compromise the integrity of the casing and may lead formation of leak paths. Effective cement life is a function of the conditions in the well over its lifetime including the surrounding formation fluids and stresses. Cement can be strong as or stronger than the rock that has provided a seal on gas, oil, and saltwater for millennia. There are records of cemented wells still effectively isolated after one hundred years. Older records for wells are simply not available since the first use of cement in an oil, gas or water well was in 1903 and was not required by newly developed regulatory agencies until about 1915 to 1935. Correct selection and use of additives prevents cement shrinkage, sulfate induced cement deterioration, acid gas reactions, and other detrimental effects.

Wellheads, Christmas Trees, and Flow Equipment After the deepest casing is set and cemented, the blowout preventer used during drilling is replaced by a set of valves that can be used for surface control and routing of pressure and produced fluids. The wellhead, Figure 8, is an intricate control center that uses multiple valves and multiple seal barriers to enable maximum control of fluids flowing from the formation. Two to three barriers are used at most points. Annular access valves may sometimes be below ground level in an accessible cemented cellar. Wellheads and their control systems may be simple on low pressure wells or very complex on high pressure wells, Figure 9. Leaks of oil at surface are rare but gas leaks may be more difficult to detect without regular inspection. The failure rate of properly maintained wellheads is low and is commonly limited to seals that isolate the top of tubulars, seals between the hangers, and valves. Failures in surface barrier systems can be inspected and repaired easily and quickly, usually without exorbitant cost or risk. Failure databases on topside (surface) equipment and some subsurface equipment (e.g. subsurface safety valves) are available through joint industry projects (23). 14 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Figure 8. Wellhead and tree assembly with cut-away of basic casing and tubing string configuration. The design allows maximum flexibility for flow control, monitoring, and quick repair if necessary.

Figure 9. Wellhead on a low pressure gas well (left); a wellhead on a deep, high pressure gas well (right). The layout is similar, but the high pressure wellhead uses twin flow paths to reduce gas velocity and potential erosion as well as giving options for control needed on a high pressure well (12). 15 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


The technology in practice at the time of well construction is a reflection of how well operators and regulators are doing their jobs in applying and checking for use of the best technologies. Early drilling methods such as cable tools allowed blowouts and old-time “gushers”, a once-routine practice that is now happily extinct. Wells completed before about 1903 had a quite peculiar problem – none of them used cement for isolation. Gas simply flowed up the outside of the uncemented steel casing and into the atmosphere. Cementing was introduced in 1903 and was a standard (required) practice by 1920. Rotary drilling, blow out preventers and wellhead designs were in wide use by the 1930’s (4, 9). Effective regulation lagged drilling for years. Oil and gas well drilling in western states was slower to develop while the attention was on the early Pennsylvania oil boom in the 1860 through the 1890’s. The western states benefited from the delay since, by the time the western states oil boom started, cement isolation practices were spreading across the country. California established Plug and Abandonment (P&A) rules in 1915 and Texas in 1919. Few other states with growing oil and gas activities enacted or enforced effective construction and plugging rules. Of the thousands of wells drilled during the first 20 to 30 years in the northeast US, many were not plugged in any way until and unless abandonment regulations orchestrated a systematic approach. In Texas, for example, over 15,000 “orphaned” wells were identified and have been plugged in the past 25 years by the state-run program funded by operator permitting fees (24, 25). Although these plugging programs arrived late in relation to the earliest booms, the application of modern isolation techniques has been a large factor in reduction of pollution potential. There is no doubt that the plugging programs have been improved over the years, but one beneficial outcome is that many, if not most of these old orphaned wells were shallow dry holes or depleted at abandonment and lacked the pressure to flow to surface. Fortunately, most of the wells in North America have been drilled since World War II, and about a third of the wells drilled up to the early 1890’s were dry holes that were plugged immediately after drilling (26). The first unified approach to resource conservation and effective rules to enforce it came in 1935 with the establishment of the Interstate Oil and Gas Compact Commission (IOGCC), the oldest and largest interstate compact in the US that now represents governors of 30 member and eight associated states. The objective of the group is to conserve resources, but also protect the public. Their survey work on idle and orphaned wells has been the driver for most of the well construction and abandonment rules that states have adapted to fit the needs of local geology (26). Well type may be one of the largest factors in well-to-well variances in well failures and risk. Wells that operate at the extremes of temperature, pressure, corrosion tolerance, high erosion potential or are in areas of tectonic induced movement or active subsidence will usually have shorter well life or more integrity problems than wells in less extreme or lower stress environments. Wells must be designed to handle the specific environment, both inside and outside the well, but a better well design includes flexibility to handle operations as field conditions change. 16 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Pressure declines in a well as oil and gas is produced - this usually reduces pollution risk. Three things are required for pollution to occur: there must be a leak path large enough for the contaminating fluid to flow from the source to the target; there must be an undesirable fluid present in sufficient quantity to create contamination; and there must either be sufficient pressure differential toward the target to move the contaminating fluid or a density difference that can move the contaminating fluid. If any of these three elements are removed then contamination from that source will not occur. If a leak path in the casing develops and the hydrostatic gradient of liquid outside the casing (above the producing zone) is higher than the pressure inside, liquid leaks will be into the casing, not out of the casing. Gas wells are not affected in quite the same manner. Although decreased pressure in the gas well diminishes the driving pressure, gas can migrate upward, preserving more of its pressure than a static column of liquid thus the lack of liquid hydrostatic back pressure allows more gas-produced pressure near the surface than would be possible in a well of 100% liquids. Culture of maintenance is a trademark of a good operating company that equates to proper preventative maintenance on the well, such as corrosion inhibitor application, scale inhibition, bacteria control in injected fluids, as well as routine checks and testing. The worst leak rates have been seen on wells with poor maintenance (9).

Well Integrity and Leak Potential Failure frequencies are estimated for wells in several specific sets of environmental conditions (location, geologic strata, produced fluid composition, soils, etc.) (9). Leaks from wells, especially small leaks measured in gallons per day, are difficult to detect. Estimate accuracy depends on a sufficient database of wells with documented failures, divided into: 1) barrier failures in a multiple barrier system that did not create pollution; 2) well integrity failures that created a leak path, whether or not pollution was created; 3) actual events of pollution. Estimated failure frequency comparisons are only valid for a specific set of wells operating under the same conditions with similar design and construction quality. Well age and construction era are important variables. There is absolutely no universal number for well failure frequency. Data from studies of over 650,000 wells worldwide have been examined to give a clearer picture of the leak potential for wells and the difference between a single barrier failure that is contained by the next barrier without leaking and an isolation failure that results from failure of multiple barriers) (9). Older era vertical well leak rates are about 0.02% for this class of wells. The newer class of horizontal multiple fractured wells have a leak rate less than about 0.004% (4 detected liquid leaks in a hundred thousand wells) – this figure continues to be reduced through improvements in design and cementing. Well leakage appears to be influenced by six major factors: geographical location; technology in practice at the time of well construction; efficiency of regulation level and enforcement; well type; pressure; and culture of maintenance (9). 17 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Geographic location may seem an odd factor, but natural seeps are indicative of oil and gas field locations. Large seeps share a common area occurrence with gas or oil fields. Woods Hole Institute explains offshore seep action: “As much as one half of the oil that enters the coastal environment comes from natural seeps of oil and natural gas (27).” Seeps are often found in places where oil and gas extraction activities are also located. As a result, many surface slicks and tar balls caused by seeps are often attributed to releases from oil and gas production activities. Seeps are generally very old and flow at a very low rate, often in an episodic manner. The material that flows out is very often toxic in an undiluted state, but some unique species of organisms are able to use the hydrocarbons and other chemicals released at seeps as a source of metabolic energy. By the time hydrocarbons reach atmospheric conditions, the materials often have become biodegraded by microbial action (27). In areas with high organic content from peat bogs, tundra and areas of heavy plant growth and decaying leaves, the soil will emit much larger amounts of methane than areas like deserts with low amounts of organic carbon.

Studies of Well Failures According a review of state-investigated well pollution incidences in Ohio (185 cases in ~65,000 wells) and Texas (211 cases in ~250,000 wells), the majority of pollution incidents were from drilling, completion, production, waste disposal and wells that were no longer operated but had not been maintained or properly plugged and abandoned (these wells are defined as orphaned wells) (19). The production well problems were dominated by leaks from pipelines and tanks. These data include a significant amount of legacy data before the Texas regulations on pits, cementing and barrier design were changed in 1969. Many of the Drilling and Completion (D&C) incidents were cement isolation problems, some before the cementing regulations were changed in 1969. Fiftyseven of the 75 waste related incidents in Texas during the study period were legacy issues with disposal pits that were outlawed in 1969. Texas has an industry tax funded program that has reduced the number of orphaned wells from 18,000 in 2002 to less than 8000 in 2009, and currently is plugging and abandoning roughly 1000 to 1400 wells per year of the remaining orphaned wells (19).

Barrier and Well Failure Frequency from Case Histories and Databases Using extensive documented literature from several technical societies, Table 2 captures ranges of barrier failures without apparent leaks and well integrity failure (all barriers in a sequence fail) where fluids (oil, gas) may move from inside the well to the outside (contamination/pollution) or from outside to inside the well (intrusion of salt water). Reported leak rates without specific leak path determinations were assumed under worst-case scenario to be leaks rather than barrier failures. 18 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Area / Number of Wells

Number of Construction Failures

Barrier Fail Freq. Range (Containment)

Well Integrity Failure Range (Containment Lost)

Leaks to Groundwater by Sampling

Ohio / 64,830

74 fail initial cement test. 39 failed in production (19).

1983-2007 0.035% in 34,000 wells 0.1% in older wells – worst case.

0.06% for all wells

Detail not available

TX 253,090

10 fail initial cement test. 56 failed in production (19, 28).

~0.02% all wells.

0.02% for older era wells 0.004% for newer wells

0.005% to 0.01% for producers 0.03% to 0.07% for injectors

TX 16,000 horiz-MF

No reported failures (19).

No failure reported

No failure data or pollution reports

No well pollution

MN / 671

Salt creep crush casing (29).

5.5%

Unknown

None reported

Alberta / 316,000

Total vent flow data (30).

No separation data available

4.6% taken as worst case.

No data – mostly gas escape

19


Table 2. Distribution of Barrier and Integrity Failures — Improvement by Era (Land Wells) (19, 28–30)

In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Risk No human or natural endeavors are risk free. The definition of risk includes the recognition that, although there is a degree of risk in every action, the frequency of occurrence and the impact of a detrimental outcome create a risk or threat level that we can understand and accept or reject based on what we believe, hopefully from assessment of facts. For example, actuarial tables of life insurance on pilots and on-board airline staff (showing no elevated life risk from flying in scheduled airlines) and the public’s acceptance of the airlines as a safe way to travel are an educated acceptance of risk. Failure frequency, impact assessment and risk rankings are needed to learn what problems are most important and require rapid attention. Identifying problems without ranking them for frequency and impact is somewhat similar to comparing a large asteroid collision with a tripping hazard created by a wrinkle in the carpet. Both are hazards, but one is catastrophic with a miniscule chance of occurring and few ways to avoid it, and the other is a minor issue, frequently encountered and easily corrected. Impact and frequency are used in every risk-based industry as the basis for preparation, plans, and changes to designs. Effectively improving a process or a design requires identification of the risk producing elements and an assessment of the impact and the probability of an undesirable outcome. For this reason, the actual expression of risk must be made based on a quantitative risk assessment (QRA) and may be compared to other industries where significant risk is an issue (31, 32). The concept of ALARP (As Low As Reasonably Practicable) is widely accepted in risk-based industries and by the public, although many have not heard the term, Figure 10. The ALARP term comes from the United Kingdom and North Sea safety practices and law in the area of safety-critical systems. The basic principle is that the residual risk shall be as low as reasonably practicable, but all endeavors accept a risk threshold that can be described as a judgment of the balance of risk, economic return and social benefit. Within that definition; however, the implied responsibility is that future risk must always be further diminished by applying learnings and developments from study of operations and failures; hence the learning loop in Figure 10. From the study of forces of ruin (wear, corrosion, erosion, decomposition, weather, cyclic loads, etc.) that degrade all things natural and man-made; engineers describe behaviors that will destruct, and design counter-actions that will preserve or extend. An engineered structure, perhaps “perfect” at the time of construction, remains perfect only for a period of time. We “risk” our lives on, but still trust skyscrapers, ships, airplanes, cars, and bridges to perform safely over an expected lifetime. They are designed to have an acceptable, although non-zero, risk levels, as they age or when weather or load conditions change. Lessons of success and failure must enter into both design and maintenance to reduce risk. In engineering design, multiple fail-safe principles and redundant systems are included that both warn of a potential problem and prevent an immediate one. For the oil and gas industry, redundant barriers in well design perform this purpose with great reliability. 20 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Figure 10. ALARP – As Low As Reasonably Practicable diagram showing levels of risk acceptance as zero risk is approached. The learnings loop designation implies that lessons from failures will be incorporated into future designs.

Why Well Integrity Failures Produce Few Pollution Incidents As opposed to loss of control during drilling in high pressure reservoirs, such as the Macondo well, loss of control from completed and producing onshore wells occurs very infrequently for several reasons: •

Many drilling failures are the result of unexpected high pressure or other drilling-related factors where the pressure barriers are mostly dynamic (mud weight and blow out preventer [BOP] or BOP control) and before installation of the full range of permanent barriers in a completed well. The expected frequency of surface releases in production wells (completed wells) is between 10% to 1% of the number expected in drilling (33, 34). Workovers during the life of the producing wells do 21 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

•

raise the risk of a release, although the frequency is still about one-tenth of that during drilling activities (30). Completed wells are constructed of tested multiple barriers - monitored where applicable. Good construction practices followed by good maintenance reduces risk (9).


As previously stated, pressure inside a producing oil well drops constantly during primary production. As pressure declines, the potential for liquids inside the well to flow to the outside of the well is sharply reduced while the outside fluid gradients above the producing zone maintain pressure, and an inward potential for leaks if a leak path is present.

Age versus Construction Era or Vintage From early failures to “old age” wear, time is portrayed to be the enemy of any engineered structure, regardless of the technical discipline. Although aging is a significant issue, it must be remembered that failures of the past are what our knowledge of today is built upon and, as learnings progress, the failure rates of a later time should be lower than the era before it – this is true in medicine as well as industry activity. Everything we know about success is based on mistakes we have made, but only if we learn from them. A key issue with operators is how they capture and incorporate learnings into the next design. For any risk rating, time is a consideration that cannot be ignored. In well construction, time has at least four major influences: 1.

2.

3.

Time impacts the knowledge available at the time of well construction. This in turn must reflect the knowledge that went into forming the design of the well, the materials available at the time for the construction, and the knowledge-based regulations that governed construction at that time. Failure rates measured in a specific time period are artifacts of that period; they should not be reflective of wells designed and completed later. In oil and gas well construction, the last 15 years have arguably brought more advances (new pipe alloys, better pipe joints, improved coatings, new cements, and subsurface diagnostics by seismic and logging delivering better understanding of earth forces) than the previous fifteen decades of oil and gas operations. Early time failures on new wells reflect both the quality of well construction and general early component failure (similar to items on a new car that must be repaired in the first few weeks of operation). Time reflects the potential for natural degradation of materials and changing earth stresses, both natural and man-made. Structures age; that is inescapable. The impact of aging; however; is highly geographically-variable and controllable to a degree with maintenance. Structures in dry climates and soils often age slowly, while structures in wet areas, salt spray zones, acid soils and tectonically active areas can be degraded and even destroyed in a few years. The oldest producing wells, 22 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


4.

for example, are more than a century old and many have not leaked, while high pressure and high temperature wells (HPHT), thermal-cycled, and corrosive environment wells may have a well life of a decade or less before permanent plugging and isolation is required. Time has also recorded changes in energy source availability from the easily obtainable conventional reservoir petroleum resources to dependence on and development of resources that are much more difficult to access. This, in turn has created technology-driven approaches that have been difficult for some, both inside and outside the industry, to learn and accept.

From the first U.S. gas wells that used wooden pipe (circa 1820s) to a few years after the beginning of the 20th century, zonal isolation of early wells was haphazard at best (9). The first true long-term isolation attempts applying Portland cement in 1903 marked the start of the cemented pipe era (26). The effective two plug cementing system moved cement into a proven isolation technique. Along the way, advances in every well construction technology improved zonal isolation reliability. Major eras of operation and the notable improvements are shown on a timeline in Figure 11.

Figure 11. A timeline of pollution potential by era. Advances in technology, regulation, corporate responsibility, and social pressure have created a lower pollution potential era. Technology advances have driven improvements in wells, often without a clear intent to accomplish that specific goal. For example, rotary drilling made drilling faster but also enabled development of surface pressure control systems that eliminated most blowouts, hydraulic fracturing vastly improved production, but also drove better cementing practices and pipe designs, and horizontal wells reduced the total well count in many areas, thereby sharply lowering any risk of surface and subsurface pollution. While what we know about the past may be accurate (and might not be), any projections we make of the future are estimates, preferably but not always based on our assessment of technology improvement or deterioration of current market trends. After all, how long have we been “running out of oil?” The best forwardlooking estimates must take into account how well the lessons of failures have been 23 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


incorporated into improving the next generation of well designs or development plans. Any development (lakes, tunnels, mines, wells, foundations, etc.) through subsurface strata must consider that every vertical and lateral inch or centimeter of a depositional formation is different from the bit above, the bit below and the bits on each side. The challenge to well design is the need to design for the unknown and the worst load. Well design is a complex geomechanical, fit-forpurpose engineering effort and definitely not a “one-size-fits-all” approach. Wells are designed and built as pressure vessels using exact data on as many variables of the formation and producing conditions as we know and considering how they will change as underground forces are altered by producing or injecting fluids into rocks with fluid filled porosity that have reached equilibrium. This is the challenge that the oil and gas industry has faced for over 150 years.

Hydraulic Fracturing Risks A fracturing study presented in 2012 concluded that risk from fracturing was extremely low, risk from well construction was slightly higher and the real concern was actually transportation and storage of materials (8). Perceived and actual outcomes in Table 3 were researched for frequency and plotted against average impacts in Figure 12.

Figure 12. Risk reduction achieved in hydraulic fracturing by application of developing technology.8 Blue lines are tracks of risk reduction driven by use of safer chemicals, safer methods of transport, and learnings integration back into job designs. Reproduced with permission from reference (8). Copyright 8 George King. 24 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Table 3. Fracturing Risk Events – Event Numbers and Descriptions for Figure 12 1 – spill transport of fresh or low salt water

12 – frac opens mud channel, well < 2000 ft. deep.

2- spill 15 gal biocide

13 – frac opens mud channel, well > 2000 ft. deep.

3 – spill 50 lb. dry non-toxic additives

14 – frac intersects another well in same pay zone.

4 – spill 150 gal diesel from truck wreck

15 – frac intersects properly abandoned wellbore.

5 – spill 2500 gal from refueler wreck

16 – frac intersects improperly abandoned wellbore.

6 – spill frac tank of water, no additives

17 – frac to groundwater through rock, well > 2000 ft. deep.

7 – spill water w/ food grade polymer

18 – frac produces earthquake that can be felt at surface.

8 – spill of 10 gal. diesel during refueling

19 – frac intersects a natural seep.

9 – spill 100 bbls of produced water

20 – frac produces emissions in excess of limits.

10 – frac ruptures surface casing

21 – normal frac operations no problems

11 – cooling pulls tubing string out of packer.

Chemicals Used in Fracturing The identity of chemicals incorporated in fracturing fluids were probably the first thing sensationalized about fracturing. The movie “Gasland” created quite a stir with the statement that a “cocktail” of several hundred toxic chemicals were possibly used in fracturing. The grain of truth was that there are many chemicals in additives sold for incorporation in fracturing; however; the fact is that most fracs use only five to an average of 14 major chemicals and about half of fracturing jobs are “slick water” fracturing fluid that uses from two to five chemicals. Often the chemicals referred to in public objections appeared to included trace amounts of chemicals at the edge of detection and most well below the EPA’s strictest limits. The outcome of the fracturing and well construction studies indicate that transport of chemicals is one of the higher risk areas for well operations. To contrast this risk, a comparison to the larger industrial use of chemicals shows the 4 to 6 billion pounds per year of chemicals transported in peak activity years for hydraulic fracturing amounts to only ~ 0.03 % of all petrochemicals moved by truck and rail in the U.S. in a year. The fraction of fuel used in fracturing is an even small fractional percent of the near 10 trillion gallons of total gasoline and diesel fuels moved on roads and railways. Table 4 shows examples of the most common chemicals used in fracturing, the volumes used and what the alternate uses include. Chemicals such as diesel, 25 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

benzene and proven carcinogens, mutagens and endocrine disruptors are not used in modern safe fracturing fluids.


Table 4. Examples of Most Common Fracture Additives on Location for a Slickwater or Hybrid Slickwater and Gel Fracturing Job Common Fracturing Additive

Purpose

Type

Avg. Amount Used In A 500,000 Gallon Fracture Stage

Alternate Use

Friction Reducer

Reduce Friction And Pressure During Pumping

High Molecular Weight Polyacrylate Copolymer

100 To 250 Gallons

Absorbent In Diapers, Flocculent For Drinking Water

Biocide

Reduce Corrosion After The Frac

Glutaraldehyde, Quaternary Amines

50 To 100 Gallons

Medical Disinfectants

Scale Inhibitor

Reduce Scaling And Ensure Flow Assurance After The Frac

Phosphonates, Polymers

10 To 50 Gallons

Detergents

Surfactant

Reduce Surface Tension To Improve Oil Production

Alcohol Ethoxylates, Sulfonates

250 Gallons

Detergents

Guar Gum

Increase Viscosity To Carry Proppant

Bio Polymer Made From Guar

300 Gallons

Food Additive

The energy industry is devoting substantial resources to chemistry and focusing on creating new, greener chemical combinations. The chemical producers and companies supplying drilling and hydraulic fracturing services are conducting much of this activity, and energy producers will play an important role in reducing both the volume and the toxicity of the chemicals they use. Smarter chemical use can boost production, cut costs, and reduce environmental impacts. Historically, operators relied on oil field service companies to provide the best technology in compliance, costs, and performance. More recently, many major suppliers have developed ranking systems for rating 26 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

chemical toxicity and are mothballing older products while developing more environmentally sustainable products. Some operators have taken a different tack and created staff positions with chemical industry experience that are responsible for reducing the volume and toxicity of chemicals. Having that chemical industry experience enables operators to use and develop best technology for sustainable cost performance while auditing systems used by service companies. Often, a simple product review can improve sustainability and cost performance and reduce chemical use rates.


Cutting Chemical Toxicity and Volume The greatest progress in reducing chemical toxicity is occurring with friction reducers, scale inhibitors and surfactants. Biocides and acid corrosion inhibitors have proven more difficult, but new approaches are on the horizon. A few noteworthy developments in reducing chemical volumes and toxicity arise from new technologies for friction reducers and scale inhibitors. Operators are experimenting with replacing liquid friction reducers and scale inhibitors with powdered materials. These powdered materials can reduce the required friction reducers and scale inhibitors volume and reduce carrier solvents and additional chemicals. Powdered materials also will reduce emissions of volatile organic compounds caused by friction reducer and scale inhibitor use. Plus, the lower volume of chemicals will result in fewer trucks on the road, meaning fewer traffic accidents and less carbon emissions. Operators and service companies are developing new technology to reduce the amount of carrier solvents in biocides and surfactants by concentrating the products. As seen with dry friction reducers, this also will reduce chemical volumes, volatile organic compounds and truck emissions and they are using greener carrier solvents. Within hydraulic fracturing, these initiatives have resulted in reducing chemical volume and in using less toxic types of friction reducers, scale inhibitors, biocides, and surfactants. Operator’s progress toward more environmentally friendly hydraulic fracturing is annually reviewed in a report Disclosing the Facts, published by environmental stakeholders from As You Sow, Boston Common Asset Management, Green Century Capital Management, and the Investor Environmental Health Network (35). This report issues a yearly scorecard that ranks companies on disclosure of chemical use, water and waste management, air emissions, community impacts, and management accountability. To further the use of greener chemistry in oil and gas operations many operators and service companies promote industry collaborations. Many have taken leadership roles in a Society of Petroleum Engineers working group on safer chemicals and are active in one of the American Chemical Society’s (ACS) Green Chemistry Institute forums on greener chemicals in hydraulic fracturing. Work in these forums should lead to further reductions in chemical toxicity in the lower volume use areas.These operator and service company groups promote advances 27 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


in chemistry, technical processes, and sustainable chemical with competitive cost performance and their goal is to reduce and eliminate toxic chemical use. The ACS Green Chemistry Institute Hydraulic Fracturing Roundtable has formed as a result. The roundtable is a consortium of operators and service companies that will pool and attract resources to develop more effective and sustainable chemistry for common hydraulic fracturing needs. The ACS Green Chemistry Institute chairs roundtables in four chemistry related industries with high sustainability profiles in terms of products and volumes. Operators are improving on being as transparent as possible in disclosing carbon, water, and chemical data. Many operators disclose greenhouse gas emissions and water usage to the Carbon Disclosure Project (CDP), an online international disclosure collaboration (36). Operators also make a significant effort to post comprehensive chemical disclosures for all hydraulically fractured wells from our U.S. operations on the FracFocus website, which is operated by a federally charted Interstate Oil and Gas Compact Commission and the Groundwater Protection Council (37). In Canada, they post similar material on the FracFocus.ca website, which is maintained by Canadian authorities for wells in British Columbia and Alberta (38). In July 2013, FracFocus.org was technically upgraded to allow operators to post water volumes by source type, so for postings since July 2013 the company is detailing the amount of water that comes from freshwater resources, brackish groundwater or recycled produced water on a well-by-well basis. On the FracFocus.org site, disclosures are keyed to geographical coordinate systems and instantly appear on Google maps. Authorities and reporting agencies have the capability of gathering and analyzing information on any data set. Any user can easily determine what has happened in a specific well or area of concern. Operators may also work with service companies and chemical vendors on a continuous basis to minimize use of chemicals overall and to select hydraulic fracturing fluid additives that minimize environmental or health concerns. Full disclosure of chemical additive compositions may be disclosed in many cases but the exact formulation (proportions of chemicals) is often not available to operators. Operators attempt to disclose 100 percent of all deliberately added chemical additive components whenever possible. Some vendors and chemical suppliers maintain legal rights granted by state or federal authorities to protect intellectual property and refuse to fully detail additive compositions; however, operators must maintain active management oversight of all operations and can specify toxic or dangerous chemicals such as benzene, toluene, ethyl benzene, and xylene (BTEX), endocrine disruptors, mutagens, carcinogens, etc. that they will not allow to be used in their wells. Each specific area has internally reviewed operational procedures since geological variability of areas that will require different additive formulations. The use of more toxic chemicals is decreasing and acceptable substitutes and making solid headway in replacing the older chemicals but care is still required. Operators also work with major service companies to pioneer the use of large-scale natural gas fueled engines in our well-site operations that mitigate air emissions. 28 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Reduction Strategies Operators and service companies work to lower chemical volumes, reduce chemical toxicity and improve environmental fate, which is the destiny of a chemical after its release to the environment. Reduction strategies include: • • •


• •

reducing overall chemical volume; reducing volatile organic compound emissions; reducing chemical component toxicity, including the elimination of high risk chemicals (e.g., diesel, BTEX, endocrine disruptors, and carcinogens); cutting back on total chemical volumes and lowering the chemical volumes hauled by trucks; and improving usage strategies, including using chemical components that are less bio-accumulative and more biodegradable.

Generally, chemicals used in hydraulic fracturing fall into five categories. • •

• •

• •

Biocides: Disinfectants that kill down-hole bacteria that can corrode pipes. Friction reducers: Chemical compounds that "slick the water" to minimize friction and pressure. These compounds allow the fluid to carry more sand into the fractures, making them wider and more permeable to produce more oil and gas. Gel systems: Different than friction reducers, these chemical compounds increase viscosity of water to allow it to carry more sand into the fractures. Scale inhibitors: These compounds keep mineral scales such as calcium carbonate and calcium sulfate from forming in pipes, which can slow oil and gas flow. Surfactants: Detergents that help wash out contaminants down hole so the well can yield more oil and gas. Acid additives: Additives used during the acid job used in each stage.

These and other chemicals are used in minute amounts as additives during hydraulic fracturing. Water and sand make up 98 to 99.5 percent of a slickwater hydraulic fracturing fluid, with the exact formulation varying from well to well.

Review of Additive Use and Progress Made on Additive Toxicity Reduction Slickwater, gel fracturing fluids and hybrid mixtures of the two are the most common fracturing fluids. Fracturing fluids must create a fracture in the rock and then must carry a proppant like sand into the fracture to preserve the flow path that the fracture creates. Efforts to produce “greener” fracturing fluids have led to many advances on fracturing chemicals for lower toxicity. 29 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

Friction Reducers (FR) Green Progression - (FR) Slickwater Frac Fluid


•

Emulsion Polymers – high molecular polyacrylates with slightly anionic character materials are the currently used compounds but dry powdered materials with no oil phase and no surfactants that have one-third the volume, volatile organic compounds (VOC) and risk are being developed with a lower cost. These are also U.S. Environmental Protection Agency - Design for Environment (EPA-DFE)-listed and drinking water approved (39).

Gellants – Guar/Hydroxyl Ethyl Cellulose/Crosslinkers/Gel Breakers – Gel Frac Fluid •

Crosslinkers, which were metal ions have given way to greener borate materials. Gel breakers, typically persulfates, peroxides, etc. have acute toxicity but short lived with rapid spending and non-toxic by-products. Reducing gellants reduces the need for breakers. Guars, either natural or modified are inherently green with good biodegradation properties.

•

•

Biocides Biocides are used in slickwater applications to prevent bacteria growth and must be safe, cost effective, be compatibility with other additives.

Biocides Green Progression • •

•

•

Early products - THPS, DBNPA, bromine based biocide , TTPC, halogenated oxidizers – now considered inferior for oilfield use. Current - Glutaraldehyde or glutaraldehyde and quaternary amine mixture – North Sea Gold Band rated with great cost performance, friction reducer compatibility. In some cases, ultraviolet light is used as a bacterial control and other mechanical methods are under trial. On the horizon - Nitrogen reducing, sulfate oxidation (NRSOB) Bio exclusion technology - Borderline commercial and successfully trialed in Marcellus Shale and Permian in the Wolfcamp Future - Phage Bio Control – Experimental in Oilfield - Studies underway for Health, Food Safety, Veterinary, Agriculture, Aquaculture, Fermentation industries

Scale Inhibitors Calcium sulfate, calcium carbonate and barium sulfate can cause scale flow assurance problems in the well. As the well is fractured, water dissolves minerals 30 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

in the formation, and scale can form if the conditions are right. Most available scale inhibitors are phosponates and polymers which are anionic.

Scale Inhibitors Green Progression (SI) • •


•

Past and still in use - Phosphonates – DETA / Amine – N/P containing formulated in methanol More current - Polymers – low molecular weight polymers – lower toxicity although still formulated methanol or ethylene glycol. Now available - Dry Polymers - 1/8th the volume, 1/3rd the VOC, 1/3rd the logistics risk and lower cost. Also EPA-DFE listed

Surfactants The major use of surfactants in hydraulic fracturing are listed below: • • • • • •

Assist in FR inversion via surface tension reduction. Sacrificial water wetting of sand vs. friction reducer adsorption. Non-emulsifying properties for fluids entering perforations (perfs) at high shear rates Lower surface tension to aid in fluid traveling through sand pack Reduction of relative perm damage due to ingression of frac fluids into pore spaces Dispersion of natural wax , asphaltenes, maltenes, etc.)

Surfactants Green Progression • • •

•

Past materials - BTEX Solvent based Older approach - Cationics – oxyalkylated amines / quats in water based + methanol – poor compatibility with FR Current - Non ionics – oxyalkylated alcohols in water based + methanol; anionics – sulfonates in water based + methanol; Non ionics / Sulfonates in water base + isopropyl alcohol (IPA)/ propylene glycol - no oil phase, less VOC, lower RM cost - EPA-DFE listed components Frac jobs typically start with a small acid job to dissolve near well bore formation and excess cement to ensure that the perfs are clear for the frac stage. The additives for this acid job include corrosion inhibitors and surfactants. The surfactants are similar to the surfactants used in the frac fluid itself.

Acid Corrosion Inhibitor Green Progression •

Past products - Acetylenic organics – propargyl alcohol + Alkly pyridine quats 31 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

• •

Fatty amines / Fatty amine quats Greener acid corrosion inhibitors have been developed and are in use in the US.


Groundwater and Methane Migration Groundwater, brine zones and produced water from oil and gas operations in a specific area do not have a constant composition (40–42). Variability in any groundwater is well documented (40, 41). Causes of natural variation in mineral and methane content in ground water and brine zone include: seasonal variance, barometric pressure changes, changes produced by runoff, water recharge routes into the reservoir, recharge sources, recharge rates, depth of water withdrawal and rate of groundwater withdrawal. According to groundwater experts, overdrawing or over-drafting a groundwater reservoir (withdrawing water faster than it can be recharged) can produce notable changes in the reservoir water composition including pulling contaminants in from above and salt from below. This variability makes single point comparisons of water quality practically worthless. Many fresh groundwater aquifers are laterally or vertically connected to more saline water sources. Salinity, within a single unit, often varies with depth. Sudden changes in pressure within a groundwater reservoir will also change the amount of free methane gas by causing gas to move from solution into free gas phase (44). The only way to assess changes in a groundwater source is to establish a trend range and include seasonal variations, withdrawal rate and other variables. Investigations of stray natural gas incidents in Pennsylvania reveal that incidents of stray gas migration were not caused by hydraulic fracturing of the Marcellus shale (45, 46). The possibility of some gas migration events being related to drilling cannot be dismissed, since air drilling, when practiced, may be a cause for temporary upsets in shallow well water color and odor, although the worst of these migrations appear to be in areas with known history of shallow gas flows that predate drilling (47). Methane is the most common gas in groundwater. Shallow methane may be from sources both thermogenic (maturation of depositional organics in the reservoir) and biogenic (biological breakdown of organic materials carried into the reservoir). Depending on the area of the country and the specifics of the aquifer, groundwater, fresh or saline, may dissolve and carry methane gas in concentrations of 0 to 28 mg/l. Free (non-dissolved) methane gas exists in many aquifers under the caprock or in rock layers and methane gas is frequently desorbed from organic formations such as coal or shale as the pressure is reduced by producing the water from these formations. As water flows out of a rock formation and into a wellbore, pressure is lowered, creating opportunity for some dissolved methane gas to move out of the water and become a free gas phase (similar to the CO2 escaping as a fresh bottle of carbonated soda is opened). Higher draw-downs will enable more gas to come out of solution (similar to rapidly pouring any carbonated beverage). Any free gas will rapidly rise in the water well and can accumulate into the highest part of the well piping system, and, if not vented by proper water well construction, will follow the moving 32 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


water when the water tap is opened in the house. This is the cause of burnable gas seen in 200 year old historical reports on igniting water wells and in more recent dramatic TV and movie shots of burnable gas quantities in faucets and garden hoses. If the well is constructed correctly, a vent cap allows the methane to escape from the well and prevents most gas accumulation. The frequency of gas appearance in groundwater is linked to a number of factors, most of which can be more geographically or geologically influenced than impacted by oil or gas well presence. Figure 13 shows a number of these factors as positive or negative influences. Perhaps surprisingly, many of the influences are natural in origin. Wells, particularly those drilled with air, can play a significant local role in gas migration disturbances (46) either by air charging shallow water sands or by displacing shallow pockets of methane into the low pressure areas caused by groundwater withdrawal. The number of water supply wells drilled in the U.S. is near 15 million, not counting those that have been dug, driven, or drilled and then abandoned without being reported (48). There are very few mandatory water well standards enforced in the U.S. and improperly constructed, poorly maintained, and improperly abandoned water wells can be a primary pathway for aquifer contamination by a variety of materials, both from surface and subsurface inflow, regardless of the source of the gas.

Figure 13. Factors involved in gas migration may include natural sources as well as both water well construction and gas well construction or abandonment.

Methane Emissions In the past decade methane has been reported by some forward projecting models to be a more serious Greenhouse gas than originally thought with leak potential along section of the vertical part of the casing and through the annulus. Routine methane venting has been stopped on flowbacks and equipment is 33 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

being designed for more effective controls of methane released from pneumatic control devices, compressors, and other operations that currently vent even small amounts of methane. Green completions, although not yet specifically designed, are evolving towards zero gas emissions.


Major Sources of Pollution – Where Do Oil and Gas Wells Rank? Groundwater pollution continues to be a major issue in the U.S.; but what are the primary causes and pathways? The indisputable major sources of U.S. groundwater contamination over the past few decades are: 1) leaks from underground storage tanks (gasoline, diesel, and chemicals) at filling stations and industrial sites with buried tanks, 2) improper residential septic systems, 3) agriculture waste and runoff of pesticides and fertilizers, and 4) poorly constructed landfills (Figure 14) (49).

Figure 14. EPA data collected in 1999 from states, tribes, and territories on reported incidents of groundwater pollution. Reproduced from EPA 2000 National Water Quality Inventory. Reproduced with permission from reference (49). Copyright 2000 U.S. EPA.

Case History – Texas Aquifers, Oil and Gas Wells, and Pollution To update the potential of groundwater contamination in a high density oil and gas well environment, data from Texas Commission on Environmental Quality (TCEQ) and Texas Groundwater Protection Council (TGPC) pollution 34 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


reports were reviewed for specific references to reported oil, gas, and injection well relevance (28, 50). The state of Texas, where half of the U.S. fracturing and nearly half of the U.S. drilling rigs operate, was used as an example, specifically to examine reports of pollution in high density oil and gas well areas on a county-by-county basis. The major aquifers of Texas, overlaid with hundreds of thousands of oil and gas wells drilled through those aquifers are mapped in Figure 15 (51). Studies of pollution reports from counties show a higher correlation of oil and saltwater pollution in surface facilities (plants, compressor stations, and tank storage), but few direct downhole results linked to producing wells (28). Roughly 80% of groundwater withdrawals in Texas are used for agriculture and municipal water supply. Aquifers of varying water quality and quantity underlay between 80 to 90% of Texas lands. Reports of water quality from properly built water supply wells affecting public health or crops are rare.

Figure 15. Overlay of oil and gas wells over areas of Texas major aquifers. Adapted with permission from reference (51). Copyright 2011 Texas Water Development Board. Pollution report records for Texas were examined for major causes of pollution and for possible links to oil and gas wells. The reported pollutant frequency information (volumes of pollutant released were not available) from the 35 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Texas Railroad Commission (TRC) and the TCEQ, Figure 16, shows decreasing pollution report frequency from 2000 through 2011 (last available data). The biggest pollution report was from underground gasoline and diesel storage tanks at filling stations, and variable exposure to manufacturing chemicals, solvents, waste oils, and very small incidents of spills involving road transport of oil (28).

Figure 16. Reported Incidents of Groundwater Pollution in Texas from TCEQ records. The top twenty reports on pollution were predominantly caused by leaking fuel tanks from filling stations, improper disposal of dry cleaning solvents (chlorinated materials), various metals (possibly from metal plating/treating operations) and agriculture sources. The percentage of pollution reports that TCEQ and TGPC identified as under TRC authority varied between less than 1% to a maximum of about 10% of the total new pollution reports each year (28). Further analysis of these reports showed a breakdown of cases where surface facilities (tanks, separators, gas plants, compressors, and gathering lines), and pipelines were responsible for about 90% of the fraction of pollution incidents where TRC had jurisdiction. The remaining reports of pollution, roughly less than 1% of the total reported each year, concerned the 200,000 to 250,000 wells that are producing, injecting or shut-in in Texas during the respective time period. All leaks were ascribed to wells whether they had been investigated or not – a worst-case approach. No leaks from abandoned wells were listed, although these may have been addressed 36 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.

under the Texas Orphan well program which ranks and then plugs and abandons over 1400 wells per year.


Naturally Occurring Radioactive Materials (NORM) Many areas of the country are listed as higher than average radioactivity, with solar and natural background being the most prevalent natural radiation sources and radon gas being the most serious health risk. Medical radiation sources (gastrointestinal series, diagnostic x-rays and mammograms) are significantly higher than common well or industry sources, and produced fluids from most wells was significantly below that of cosmic radiation. The level of NORMs found in produced water from oil or gas wells varies considerably across the country but all is reportedly lower than EPA acceptable levels unless the materials are concentrated (filtering, evaporating, scaling, precipitating or in sludges). Some older oilfield produced water handling facilities will occasionally produce deposits of NORM materials although the volumes and activity is usually low.

Water Use About 99% of the all the fluid volume used for fracturing is water but water used in fracturing is rarely over 1 to 2% of the total water used in states where fracturing is practiced. Nation-wide, fracturing may use about 100 billion gallons of water in a year (combined fresh and salt water). Although a seemingly large volume, the water usage for fracturing pales by comparison to yearly volumes used in thermo-electric power generation, irrigation and domestic fresh water usage, Figure 17. Power generation, which uses significant amounts of surface water as well as groundwater, is a single-pass through use of water with most returning water released to surface flowing water, regardless of whether the initial source was surface or groundwater. Compare this to the estimated 2.08 billion gallons of water used per day for golf course irrigation in the U.S. (51) In comparison, just the leakage from America’s residential and industrial fresh water supply lines is estimated at almost 6 billion gallons per day and 2.1 trillion gallons per year (52). Fracturing supply water sources are surface water, fresh water wells, salt water from oil field produced water and other concentrated brines. The high salt content waters now widely used in fracturing are unusable for agriculture and have too much salt reject to make reverse osmosis units economical. The amount of recycling of produced and salt waters and the use of high total dissolved solids (TDS) brines varies with the cost of and availability of fresh water and the cost and availability of disposal or treating of produced water. The volume of fresh water used for fracturing in Texas, where half of the hydraulic fracturing jobs in the U.S. are pumped, is about 1 percent of the total water usage for the state as a whole, but may range higher than 10% of the available water supply in a localized area. Although this volume may appear low for the state, dry areas may not be able to sustain this usage volume. This has been a driver for produced water recycling in Texas. 37 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Figure 17. Total freshwater use in the U.S. from USGS estimates for 2010. Reproduced with permissions from reference (54). Copyright 2014 United States Geological Survey. Water usage for production of primary fuels is shown in Table 5 (54).

Table 5. Gallons of Water Used by an Energy Source to Produce 1 Million BTUs of Energy Primary Energy Resource

Range of gallons of water used per million BTU generated

Data Source

Natural Gas (based on all water needs for gas from shales including fracturing)

1 to 3 (conventional gas uses less than shale gas development)

USDOE 2006, P59.

Coal (no slurry transport) (with slurry transport)

2 to 8 13 to 32

USDOE 2006, p53-55.

Nuclear (processed uranium ready to use in plant)

8 to 14

USDOE 2006, p 56.

Conventional Oil

8 to 20

USDOE, p 57-59.

Synfuel Coal Gas

11 to 26

USDOE, p 60.

Oil (liquid) from shale

22 to 56

USDOE, p 57-59.

Oil from Tar Sands

27 to 68

USDOE, p 57-59.

Ethanol (irrigated corn)

2510 to 29,100

USDOE, p 61.

Biodiesel (irrigated soy)

14,000 to 75000

USDOE, p 62.

The low volume of water required to produce natural gas using fracturing technology makes it one of the most water–efficient primary fuels.

38 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


Induced Seismicity - Earthquakes No earthquake under your house is ever “small”, but thousands of tremors occur each year around the world, so what is the seismic risk from natural or manmade activities and what can minimize the occurrence and impact? Creating a large seismic event requires a certain set of geologic and stress conditions and the depth (also called hypo-center or “focus”) is most often along deep tectonic plate margins that are subject to “stick and slide” behavior. Large quakes are also possible in areas away from the major tectonic boundaries along fault lines, such as the New Madrid Fault of the central U.S. Induced seismicity, that fraction of seismicity resulting in part from man’s activities, is a reaction to loads and forces resulting from creation of surface impoundments of water (creating lakes), removing or piling up hundreds of millions of tons of rocks and soil (strip mining) and injection of fluids into some subsurface rocks that are highly stressed and capable of movement (produced water disposal). Not every activity will create tremors; the conditions to create a shift in the rock strata must be ready and waiting for the extra push to create fault movement. Highly damaging earthquakes, those of Magnitude 7 or higher have occurred in a few, very specific places in the U.S., usually along tectonic plates or major faults (56). According to the USGS: “The magnitude of an earthquake is related to the length of the fault on which it occurs -- the longer the fault, the larger the earthquake. The San Andreas Fault is only 800 miles long. To generate an earthquake of 10.5 magnitude would require the rupture of a fault that is many times the length of the San Andreas Fault. No fault long enough to generate a magnitude 10.5 earthquake is known to exist. The largest earthquake ever recorded was a magnitude 9.5 on May 22, 1960 in Chile on a fault that is almost 1,000 miles long”. Large magnitude earthquakes usually rip open hundreds of miles of faults, often creating ground shifts and “ground waves”. The short duration of hydraulic fracturing simply does not have the capacity to create this level of energy. However; very large-volume water injection has been identified as a culprit in a few hundredths of one percent of the US’s 150,000 UIC-II (oil & gas injection and produced water disposal wells). Fracturing, particularly near the larger faults within a pay zones have produced felt quakes with magnitudes of 1.0 to 3.0 and higher. Certain regions such as central Oklahoma have seen much higher earthquake activity related to very large volume disposal from produced water. Determining the strength (magnitude), the surface location (epicenter) and depth (hypocenter or focus) are becoming better with time because of the increase of monitoring stations from the few hundred stations worldwide in the 1930’s to the tens of thousands of monitoring stations today. Closer station positioning results in sensing and locating more of the small quakes that were previously undetected. The earthquake risk maps for the US have shown small changes in some areas, Figure 18 (57, 58). Increased numbers of monitoring stations and use of portable monitoring stations has helped redefine most areas of risk. Note that risk has increased in a 39 In Hydraulic Fracturing: Environmental Issues; Drogos, Donna L.; ACS Symposium Series; American Chemical Society: Washington, DC, 2015.


few areas such as central Oklahoma where induced seismic from injection wells is suspected and fault mapping has identified higher risks.

Figure 18. USGS Earthquake Risk maps of 2008 and 2014. Maps showing peak ground acceleration for 2% probability of exceedance in 50 years and Vs30 site condition of 760 m/sec. Reproduced with permission from reference (57). Copyright 2014 USGS Earthquake Hazards Program.

Recycling Produced Water A better approach to water disposal, with multiple benefits, is to consider recycling the produced water into fracture base fluid. Recycling produced waters relieves pressure on fresh water supplies and can sharply reduce the volume of water that is sent to disposal wells. A workable approach was advanced by Apache Corporation in several southwest US areas (20, 59). Hydraulic fracturing stimulation in one area of concentrated well development utilized a mixture of recycled produced water and a feed stream of high salinity groundwater that was not suitable for agriculture use. In 2013, sixty-two new horizontal completions in the area used a total of 12.8 million barrels (bbls) of water for operations that was approximately 75 percent brackish and 25 percent recycled produced water (55). In the first three months, there were 18 new horizontal completions, using a total of 5.0 million barrels of water (49 percent brackish, 51 percent recycled). Each hydraulic fracture requires approximately 200,000 to 300,000 bbls of water per well (8.4 to 12.6 million gallons). The total volume of water produced from the field is approximately 32,000 bpd (barrels per day), varying from 100 to 2,500 bpd per well. Eighty percent to 100 percent of the water used for the hydraulic fracture is produced over the life of each well. In this area, the recycled and brine combined waters satisfied 100% of the 12 million barrel (537 million gallon) fracturing water demand without using any fresh water.

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Environmental Aspects of Hydraulic Fracturing: What Are the Facts

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