Considerations for development of Marcellus Shale gas (Jul-2009)
Operators are working to optimize fracture patterns for improved production and to ensure containment and efficient use of frac fluids.
Operators are working to optimize fracture patterns for improved production and to ensure containment and efficient use of frac fluids.
J. Daniel Arthur, Brian Bohm and Mark Layne, ALL Consulting
Shale gas resources extend across the continental United States, offering estimated potential of 500 to 1,000 Tcf with consistent increases as wells are brought online and additional information is gathered.1 One key shale gas play identified as having promise for future development is the Devonian-aged Marcellus Shale of the Appalachians, with potential for 50 Tcf or more of technically recoverable gas.2 While still in the early stages of development, this basin has the potential to be one of the largest gas plays in the US. Development of the Marcellus play has been made possible by recent advances in two key technologies—horizontal drilling and hydraulic fracturing.3
Fracturing fluids require the use of multiple additives that serve different functions specific to the well undergoing the stimulation. Unique challenges such as scale buildup and bacteria require specific additives to prevent degradation of well performance. Well characteristics, formation properties and fracturing fluid compositions are a few of the criteria used to select the most appropriate additives for the stimulations.
Table 1 provides a summary of common fracture fluid additives, their main components, and the usual uses in the field and elsewhere for those compounds. The table illustrates that while there are a variety of different additives used in fracturing fluids, these additives are also contained in common products that people encounter in their daily lives. Service companies are also working to develop even more environmentally friendly fluids, such as using hydrochloric acid formulations that more easily break down into simple salts.9
WATER AVAILABILITY, FLUID HANDLING AND DISPOSAL
Drilling and fracturing a typical horizontal shale gas well is estimated to require 3–4 million gal (71,000–95,000 bbl) of water.10 While this volume is not trivial, it is a small percentage (less than 0.1% to 0.8%) of the total water consumed by industry in any particular shale gas development region.11
As public concern over water usage increases in communities in shale gas basins, Marcellus operators are assessing possible supplies for water, including surface water, private water sources, municipal water, water supplies from groundwater and re-used produced water. A study conducted by the Appalachian Shale Water Conservation Management Committee in 2008 identified surface water withdrawals as the primary source (60–70%) of the total water demand for drilling and completion activity in the Marcellus Shale Basin.12 The Susquehanna River Basin Commission (SRBC) has noted an increase in applications for water withdrawals, mostly due to the oil and gas activity in the Marcellus Shale, and as such has triggered an administrative Approval by Rule regulation adopted in 2006 for projects using water “obtained solely from public water supply systems.”13 The agency’s executive director also issued a Notice of Determination that all gas development in the Marcellus or Utica Shale Formation that involved the withdrawal or consumptive use of water was subject to review and approval through the SRBC regardless of regulatory thresholds.13 However, water usage for drilling and completion in the Marcellus Shale (projected at 8.4 million gal per day) is dwarfed by area power generation demand of 150 million gpd.12
Additionally, the Pennsylvania Department of Environmental Protection, in an effort to ensure that environmental anti-degradation practices are used to protect surface waters, is requiring operators to submit a Water Management Plan with drilling permit applications identifying water sources to be used, with safe yield calculations for surface water withdrawals for each well.12 Operators are likely to deal with a variety of water regulatory agencies as oil and gas development increases in the Marcellus Shale.
Other public concerns revolve around the chemical properties of fracturing fluids or additives and their effects on public health, since recent reports have circulated identifying some of the agents used in hydraulic fracturing.14 Since then, increasing public inquiry on the possibility of migration of fracturing fluids into underground drinking water aquifers is generating regulatory scrutiny and study of the issue.15
Water and fluid handling. Shale is a natural barrier to the vertical migration of fluids and is documented as confining layers to vertical migration of oil and gas. There are multiple shale zones present between the Marcellus Shale and shallow groundwater zones in much of the anticipated development area, which provides protection of groundwater resources from the hydraulic fracture treatments used to develop the Marcellus. In some parts of the Marcellus production area, there is as much as 7,000 ft of sedimentary rock strata, including thousands of vertical feet of shale, between the Marcellus and the shallow groundwater system.
The casing and cement programs required by oil and gas agencies are designed to ensure that drilling and construction of a gas well protects potential sources of drinking water. Analysis of the protection provided by casings and cements was presented in a series of reports and papers prepared for the American Petroleum Institute in the 1980s.16,17 These investigations evaluated the level of corrosion that occurred in Class II injection wells, which are used for routine injection of water associated with oil and gas production. The research resulted in the development of a method of calculating the risk that fluids injected into Class II injection wells could result in a discharge of fluids that could reach an Underground Source of Drinking Water (USDW). The Appalachian Basin was ranked as having a minor potential for corrosion because only a few instances of casing corrosion had been reported by oil and gas agencies.
The analysis was then limited to those basins in which there was a possibility of casing corrosion.17 For those basins, it can be correlated that—in a modern horizontal well completion in which 100% of the USDWs are protected by properly installed surface casings (and for geologic basins with a reasonable likelihood of corrosion)—the probability that fluids injected at depth could reach a USDW would be between 0.00002 per well-year (one well in 200,000) and 0.00000002 per well-year (one well in 200 million) if these wells were operated as injection wells. This analysis does not account for the fact that hydraulic fracturing of shale gas wells typically is done over a couple of days to one week. The Appalachian Basin was not identified as having a reasonable likelihood of corrosion, so the risk probability is likely lower than that presented above.
The API study also included an analysis of wells that had been in operation for numerous years, accounting for what are likely many variations in applied technologies and regulations. It is expected that the probability of groundwater being impacted by the pumping of fluids during hydraulic fracture treatments of newly installed wells with a high level of monitoring would be even less than 0.00000002.
The potential for hydraulic fracturing and Marcellus Shale development activities to impact surface water has been reduced by operator and service company practices over recent years, including the transition toward use of water-based slickwater fracturing fluids, which have fewer additives than cross-linked gel. Additionally, service companies performing hydraulic fracturing are designing systems to contain fracturing fluids within closed loops that would keep all additives, fracturing fluids, mixing equipment and flowback water within a storage tank, service truck or flowline.18
Disposal. After a hydraulic fracture treatment, when the pumping pressure has been relieved from the well, the water-based fracturing fluid begins to flow back through the well casing to the wellhead. This produced water consists of spent fracturing fluids and, in some cases, dissolved constituents from the formation; the dissolved constituents vary from one shale play to the next or even by area within a shale play. Produced water from shale gas can vary from fresh (less than 5,000 ppm total dissolved solids) to varying degrees of salinity (5,000–100,000 ppm TDS).10
The disposal of flowback and produced water is an evolving process in the Appalachians. The volumes of water that are being produced as flowback water are likely to require a number of options for disposal that may include municipal or industrial water treatment facilities (primarily in Pennsylvania), Class II injection wells, and on-site recycling for use in subsequent fracturing jobs.
In most shale gas plays, underground injection has historically been preferred. In the Marcellus play, this option is expected to be limited, as there are few areas where suitable injection zones are available. If such is not locally available, it may be possible to transport the produced water to a more distant injection site. Injection disposal wells are permitted under the federal Safe Drinking Water Act Underground Injection Control (UIC) program for the states of New York and Pennsylvania; in the case of state primacy, such as Ohio and West Virginia, the program is administered under equivalent applicable state programs. UIC programs are a stringently permitted and monitored process with many environmental safeguards in place.
Produced water treatment may be feasible through either self-contained systems at wellsites or fields, municipal waste water treatment plants or commercial treatment facilities. With an estimated apex of 8.4 million gpd required for oil and gas development in the future, and assuming less than 50% of that amount will require disposal as flowback or produced water from wells, about 95,000 barrels of water per day could require treatment before discharge to surface waters.12 The availability of municipal or commercial treatment plants may be limited to larger urban areas where treatment facilities with sufficient available capacity already exist; as in underground injection, transportation to treatment facilities may or may not be practical.5 As of this writing there are plans to construct commercial wastewater treatment facilities specifically for gas shale-associated produced water in some US locations.19 However, as injection well disposal options appear increasingly limited in the Marcellus, operators and regulatory agencies are evaluating what treatment requirements would be necessary to return flowback or produced water to reuse by operators or to allow for discharge to surface waters by National Pollutant Discharge Elimination System permit. Those requirements center primarily on reducing TDS and concentrations of contaminants such as benzene, oil and grease, and suspended solids.12
A number of treatment processes are being evaluated and studied for effectiveness in other shale gas plays. In the Barnett Shale, the Texas Railroad Commission approved and Fountain Quail Water Management tested a water distillation process that allows reuse of 80% of the produced water in that region. As of April 2008, 5.7 million barrels of flowback water (and produced water) have been processed to recover 4.5 million barrels of water for reuse in operations.20 Additional studies are proceeding to determine the minimum water quality necessary for successful hydraulic fracturing operations; recycling produced water could alleviate issues associated with water withdrawals from regional sources and disposal concerns in communities.11
Hydraulic fracturing and horizontal well completions appear to be effective for development of Marcellus Shale gas, although there have only been a few wells drilled to date. Advances are being made in the design of fracturing programs to develop more efficient ways to create additional flowpaths to the wellbores, and these advances are targeting extensive design and analysis of fracture treatments including simulators, microseismic fracture mapping and tilt measurements.2 Production economics directly hinge on improving gas production by optimizing fracture development and ensuring that fracture propagation is limited to the target formation and does not extend into surrounding wet formations.
The potential for impacts to surface water and groundwater quality from Marcellus Shale development is expected to be minimal because of the regulatory requirements from state oil and gas agencies involved and the practices operators are implementing to ensure that fluids are contained. In addition, the thick sequence of Devonian-aged shales overlying the Marcellus acts as a series of confining layers to prevent the vertical migration of fracturing fluids toward groundwater systems.
1 Halliburton Energy Services, “U.S. shale gas: An unconventional resource: Unconventional challenges,” white paper, 2008.
- EOR/IOR technology: Advanced shale oil EOR methods for the DJ basin (May 2023)
- The last barrel (April 2023)
- What's new in production (April 2023)
- Regional Report- Gulf of Mexico (April 2023)
- ShaleTech- Permian shales: Production hits new high amidst talk of looming plateau (April 2023)
- ShaleTech: Marcellus-Utica Shales (February 2023)