In This Issue
Summer Issue of The Bridge on Shale Gas: Promises and Challenges
June 15, 2014 Volume 44 Issue 2

Well Integrity Challenges and Risk Mitigation Measures

Tuesday, June 24, 2014

Author: Stefan Bachu and Randy L. Valencia

Hydraulic fracturing is not a new technology—it has been practiced in vertical wells by the oil and gas industry since the late 1940s–early 1950s. But multistage hydraulic fracturing in horizontal wells, which may be a few miles in length, opened new possibilities for producing oil and gas from tight reservoirs and methane-rich shales. The subsequent recent surge in horizontal drilling and hydraulic fracturing has sharpened concerns about risks of fracture propagation, contamination of other resources, including groundwater, by frac fluid and/or methane, and interwellbore communication between the injection well and an offset well, resulting in either production of frac fluids or loss of integrity of the offset well, as summarized in Table 1.

Table 1

Because of public concern about the impacts of horizontal drilling and hydraulic fracturing on possible groundwater contamination, we show that vertical propagation of fractures from the producing formations is rarely a source of such contamination; instead, surface activities are the major source of groundwater contamination (Kell 2011; King and King 2013; Krupnick et al. 2013). For example, handling and storage of injection and produced water were documented as the predominant source of groundwater contamination in a study of more than 317,000 wells in Texas and Ohio (Kell 2011).

Our focus in this article is on the risks associated with subsurface operations, particularly wells, involved in fracturing low-permeability shales to release natural gas. We draw on recent analyses of well design and construction, gas leakage, and associated geological factors in the United States and Canada, collected by regulatory agencies, academics, and operators (Kell 2011; King and King 2013).1

We begin with a review of challenges and questions that have emerged with the expansion of hydraulic fracturing. We then provide, as background, an overview of the construction and components of a horizontal well. The following sections address the challenges and questions raised below, and we conclude with suggestions of measures to mitigate potential hazards associated with hydraulic fracturing and horizontal wells.

New Challenges and Questions

The unprecedented development of shale gas resources poses significant questions for the public, regulators, and the industry:

  1. What new risks to the integrity of existing wells are inherent in the advanced technologies of horizontal drilling and hydraulic fracturing, and how are those distinct from conventional oil and gas development?
  2. What are the potential risks to well integrity (Kell 2011; King and King 2013; Krupnick et al. 2013) that may threaten groundwater supplies and how serious and likely are those risks? Although any contamination of groundwater occasioned by drilling and fracturing techniques and operations may be serious, how do the risks of contamination from horizontal drilling and hydraulic fracturing compare to other threats to groundwater?
  3. What geological conditions or perturbations might impinge on well development and on gas migration to groundwater, and how might they be addressed?
  4. Are there new mitigation measures that need to be adopted in engineering practices and regulatory standards and oversight?

Overview of Well Design and Construction

Before reviewing the specifics of well design and construction, we explain the concept of well integrity. Well integrity encompasses the technical, operational, and organizational solutions necessary to reduce the risk of uncontrolled release of gas and hydrocarbon fluids throughout the life cycle of a well.

Protective Well Design

Wells are typically designed from the inside out and constructed from the outside in. Structural elements termed well barriers are essential in both the design and construction of wells. These barriers function as containment envelopes to prevent unintentional fluid flow between the geological unit from which the well produces and other geological formations, reservoirs, shallow groundwater used for drinking water, and/or the atmosphere. The barriers have built-in redundancies to reduce the risks that gases or liquids can escape from a well anywhere along its length, enter a well from untargeted zones, or migrate from one geological zone to another.

On its way to the target zone (e.g., a gas-bearing shale), a well traverses other geological layers, impermeable as well as more permeable, such as sandstone, coal, and carbonates containing various hydrocarbons and brines. If fluid escapes containment, it follows a leakage pathway to reach an adjacent permeable formation or the environment (Watson and Bachu 2008).

To maintain well integrity and prevent impacts from such leaks, zonal isolation is among the key functions of well barrier design. Introduction of improvements in well tubing and pipes, cementing design and practices, couplings, pressure controls, and plugging design and practices are among many examples of technologies undertaken, in part, to sustain the integrity of a well during its active life and after abandonment.

Construction

Wells must be of the right size and materials to withstand their environment. An exposed and corrodible iron pipe inserted into a borehole will not do.

Typically, the interior or production casings of a well consist of steel pipes or tubes designed to withstand the pressure, temperature, and chemical environment of both the produced fluids that come into the well and the fluids (usually brines but also gas) on the outside of the well in case the borehole is not fully cemented or the cementing job is deficient.

Once the interior casing design of a well is determined, the exterior casing size, strength, and cements can be designed around it. A series of concentric casings is fitted into a wellbore and cemented sequentially as they are set in place when a well is drilled, finally looking much like an extended telescope. Cements are poured between each layer of casing and between the casing and the borehole to stabilize the well structure and to provide an impermeable barrier between geological zones. The well design is thus a series of nested barrier elements that provide structural strength, barriers to fluid flow, and pressure containment.

The number of casings and cement barriers differs according to the depth in the well. Shallow portions of the well (500–1,500 ft) can have up to 4 or more barrier elements depending on regional geology and regulatory requirements to protect groundwater. Intermediate depths of the well may have up to 2 barrier elements, and deep sections commonly have 1 or 2 barrier elements.

Cement, Couplings, and Other Safeguards

Cement is an important contributor to well integrity. It is used not only to sheath well casings but also to plug zones to prepare a well for abandonment.

Cement must meet four criteria to serve as an effective barrier: (1) there must be a sufficient amount for the task; (2) it must have the proper quality and properties after setting; (3) it must be free of voids, fractures, and/or channels; and (4) there must be a robust bond with the pipe and with the rock formations on the outside.

The quality of the cement is more important than the volume used. Attention to the cement composition is essential because some additives, such as bentonite or gypsum, deteriorate in the presence of CO2 or under acidic conditions, potentially opening leakage pathways (Watson and Bachu 2008, 2009).

Cement bonding logs are used to assess isolation and pressure containment, but have frequently been found to be inaccurate. Isolation of zones can be measured effectively only with pressure tests (King 2012).

Additional well components enhance integrity and serve as barriers. For instance, improvements in threaded couplings and in coupling preparation have greatly reduced leaks from joints. Valve configurations (called “Christmas trees” because of their shape) at the top of a wellhead control well pressures and flow rates in a variety of well conditions.

Annular flows of gas at the surface, often signaled by rising pressures, can indicate barrier problems anywhere in the well. In old wells, visible gas migration may be manifested as bubbles rising in puddles surrounding the well (Bachu and Watson 2006). Gas migration and surface casing vent flow leakage are illustrated in Figure 1, a schematic of typical vertical well construction. Gas accumulating inside the casing leads to pressure buildup, also known as sustained casing pressure. In Canada, venting of the accumulated gas is allowed in order to avoid pressure buildup that may damage the well; depending on the rate of the vent flow and severity of the leak, the operator may be required to repair the well immediately or the repair may be delayed until well abandonment.

Figure 1

When wells are closed or abandoned, additional safeguards are required to avoid leakage from or migration into a well. Cement plugs or other mechanical barriers in various configurations placed above a zone impede fluid flow through a well, but these too are subject to degradation or failure, especially in older and abandoned wells.

In addition to these physical measures, a host of technologies and procedures now enable not only periodic monitoring but also real-time identification of issues before they jeopardize well integrity. Among these technologies are gas and pressure monitors, gas chromatography, and acoustic, sonic, temperature, and electronic sensors. Many of these have been implemented in response to state and provincial regulations.

Risks to Well Integrity

There are many reasons why barriers fail and well integrity is threatened. Pipes and casings can corrode, cement can chemically or mechanically degrade, valves can fail or leak, and well maintenance may be faulty. The probability of failure is strongly related to the type and age of a well.

Old and New Wells

Table 2 shows the qualitative evolution of well construction since 1830 (King and King 2013), and Table 3 gives data on recorded well failure rates (Kell 2011). Notably, hydraulically fractured wells, especially those of recent vintage, are the least likely to develop problems, because of improved construction and barrier standards and more stringent regulatory requirements. Wells built in other periods, however, are vulnerable, especially as they age.

Table 2 

Table 3
 

According to a recent study of nearly 65,000 wells in Ohio (Kell 2011), 31,000 drilled before 1983 had a barrier failure frequency (with no leak to the environment) of 0.1 percent, whereas the failure frequency for those drilled between 1983 and 2007 was 0.035 percent. During the 25-year study, 0.06 percent of the entire study population of 64,830 wells had a leak to the environment (well integrity failure). The same study of 253,000 wells in Texas showed a similar decrease in well integrity failures between newer wells (~0.004 percent) and older wells (~0.02 percent).

The greater propensity of older wells to leak or fail has consequences for new drilling, whether conventional or horizontal, in older fields. Detailed discussions of well failures are in King (2012) and King and King (2013).

Horizontal Wells and Hydraulic Fracturing

Some well integrity issues are specific to horizontal wells. When the wellbore and casing are turned laterally and proceed horizontally through shale rock, they are subject to gravity along the full lateral length of the pipe. This may make it difficult to keep the pipe properly centered to effectively cement it in place. It will then tend to sag in the unset cement, occasionally leading to a defective cement job and compromising the integrity of the well, particularly during high-pressure fracturing. Repeated pressure changes along the horizontal length of pipe induce stress in the casing and cement and may cause the cement to debond from its casing and crack.

Of greater potential consequence are the possibilities that hydraulic fracturing along a horizontal well will affect nearby offset wells through fractures propagated through the shale. Prediction of fracture length is still a challenge. It is possible for induced hydraulic fractures to contact adjacent wellbores and thereby create a pathway for fracturing fluid and/or gas migration. This may be particularly problematic with historic abandoned wells that lack barrier protections. Similarly, the drilling of offset wells, whether conventional or horizontal, can affect the integrity of horizontal wells when a communicating fracture zone is intersected.

In a study of 5,349 horizontal wells drilled in Alberta and British Columbia from 2009 to 2012, there were 39 reported instances of interwell communication (it is worth noting that fracturing fluid, not methane gas, travelled through the fracture to the offset well and came up the well) (Kim 2012). Because fracture propagation is substantially confined to the shale formation in which it is induced, 95 percent of interwell communication occurred between horizontal wells drilled into shared formations. The distance between the communicating wells averaged about 1,300 feet, but varied from ~90 to ~7,000 feet.

However, the number of horizontal wells completed with multistage fracturing is comparatively very small and the number of conventional wells very large (a ratio of 0.03 percent in North America), so there are no data on how induced fractures may affect broader arrays of nearby conventional offset wells as the frequency of horizontal drilling increases. This uncertainty is compounded when the types and locations of historic offset wells are unknown or their ownership is distributed among different parties.

The Role of Geological Conditions

What happens to the gases and other hydrocarbons released from fractured rocks and to the fracturing fluids injected in them? Can vertical fractures find their way to the surface and serve as pathways for gas to contaminate groundwater?

Horizontal drilling is conducted 4,000 to 13,000 feet below the Earth’s surface, below the maximum depth of underground sources of drinking water or protected groundwater (the depths of such sources vary regionally from hundreds to thousands of feet below the surface). Although there are a number of other ways in which methane from below the surface can reach and contaminate groundwater, recent studies of deep horizontal well fracturing indicate that it is nearly impossible for induced fractures to travel through several thousand feet of rock (Fisher and Warpinski 2012; King 2012). Fluids injected into shale plays may dissipate quickly into the rock (sometimes “thieved” by more permeable overlying strata), the extent of flow may be limited by diminishing hydraulic forces, and migration may be localized to the well site except in the possible presence of nearby offset wells (Fisher and Warpinski 2012; King 2012). Meta-analyses of thousands of actual measurements and hundreds of studies on wells drilled in various shale gas basins, combined with more simplistic models of fracture propagation in specific locales, demonstrate that vertical fractures encounter a number of barriers in the complexity and mechanics of layered sedimentary structures.

Shale plays vary both from basin to basin and within a basin in a number of parameters, including the maximum height of induced vertical fractures. The great majority of land-based vertical fractures generally propagate several hundred feet, although a few—in the Barnett and Marcellus shales, for example—have vertical extensions of 1,000–1,500 feet and in some cases even more.

Different geomechanical properties can be encountered in offshore drilling. Studies off the coasts of Mauritania, Namibia, and Norway demonstrate that natural faults and possible stimulated fractures may reach up to 3,000 feet vertically, although the probability of either stimulated or natural fractures exceeding 1,000 feet both on land and under the seabed combined is estimated to be less than 1 percent (e.g., Davies et al. 2012).

Variations underscore the need to adapt drilling and hydraulic fracturing to local conditions and to maintain sufficient depths (2,000–3,000 feet) below groundwater levels to eliminate the possibility of direct contamination from the fracturing process.

Conclusions and Authors’ Recommendations

Horizontal drilling and multistage hydraulic fracturing pose limited risks for groundwater contamination in and of themselves (Kell 2011; King and King 2013). Surface activities present greater hazards either from gas leakage into the atmosphere or groundwater contamination associated with fracturing fluids and/or produced fluid handling at the surface.

The potential for any significant long-term hazards of interwell communication between horizontal wells and abandoned or closed older wells can be addressed through adequate regulation. Horizontal multistage fracturing should be conducted (1) at safe depths—2,000–4,000 feet below the base of groundwater protection and based on local geological conditions; (2) at safe distances from offset wells, whether shale gas or vertical wells drilled for other purposes; and (3) at safe distances from abandoned offset wells. In addition, (4) fractures should be designed and controlled to remain within the shale gas–producing formation and not propagate vertically into adjacent formations, reservoirs, or deep saline aquifers.

References

Bachu S, Watson TL. 2006. Possible indicators for potential CO2 leakage along wells. In: Proceedings of the 8th International Conference on Greenhouse Gas Control Technologies. Gale J, Rokke N, Zweigel P, Svenson H, eds. Oxford: Elsevier.

Davies RJ, Mathias SA, Moss J, Hustoft S, Newport L. 2012. Hydraulic fractures: How far can they go? Marine and Petroleum Geology 37:1–6.

Fisher K, Warpinski N. 2012. Hydraulic-fracture height growth: Real data. SPE 145949 Production and Operations 27:8–19. Presentation at the SPE Annual Technical Conference and Exhibition, Denver, October 30–November 2, 2011.

Kell S. 2011. State oil and gas agency groundwater investigations and their role in advancing regulatory reforms. A two state review: Ohio and Texas. Presentation to Ground Water Protection Council, Oklahoma City, August.

Kim T. 2012. Overview of interwellbore communication incidents: An ERCB perspective. Paper presented at the SPE Canadian Unconventional Resource Conference, October 30–November 1, Calgary.

King GE. 2012. Hydraulic fracturing 101: What every representative, environmentalist, regulator, reporter, investor, university researcher, neighbor, and engineer should know about estimating frac risk and improving frac performance in unconventional gas and oil wells. SPE 152596.

King GE, King DE. 2013. Environmental risk arising from well construction failure: Difference between barrier and well failure, and estimates of failure frequency across common well types, locations and well age. SPE 166142 Production and Operations 28:323–324.

Krupnick A, Gordon H, Olmstead S. 2013. Pathways to Dialogue: What the Experts Say about the Risks of Shale Gas Development. Washington: Resources for the Future.

Silva JM, Gettings RM, Kostedt WL, Watkins VH. 2014. Produced water from hydrofracturing: Challenges and opportunities for reuse and recovery. The Bridge 44(2):34–40.

Watson TL, Bachu S. 2008. Identification of wells with high CO2-leakage potential in mature oil fields developed for CO2-enhanced oil recovery. SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma. SPE 112924.

Watson TL, Bachu S. 2009. Evaluation for gas and CO2 leakage along wellbores. SPE 106817. Drilling & Completion 24:115–126.

 FOOTNOTES

 1 The types and comprehensiveness of data available on well characteristics, performance, and failures are uneven but became increasingly detailed in the latter part of the 20th century.

 

 

About the Author:Stefan Bachu is a distinguished scientist, CO2 Storage, Alberta Innovates–Technology Futures in Edmonton, Canada. Randy L. Valencia is a production engineering advisor, Apache Corporation, Houston.