Article pubs.acs.org/est
Potential Restrictions for CO2 Sequestration Sites Due to Shale and Tight Gas Production T. R. Elliot and M. A. Celia* Civil and Environmental Engineering, Princeton University, 50 Olden Street, Princeton, New Jersey 08544, United States ABSTRACT: Carbon capture and geological sequestration is the only available technology that both allows continued use of fossil fuels in the power sector and reduces significantly the associated CO2 emissions. Geological sequestration requires a deep permeable geological formation into which captured CO2 can be injected, and an overlying impermeable formation, called a caprock, that keeps the buoyant CO2 within the injection formation. Shale formations typically have very low permeability and are considered to be good caprock formations. Production of natural gas from shale and other tight formations involves fracturing the shale with the explicit objective to greatly increase the permeability of the shale. As such, shale gas production is in direct conflict with the use of shale formations as a caprock barrier to CO2 migration. We have examined the locations in the United States where deep saline aquifers, suitable for CO2 sequestration, exist, as well as the locations of gas production from shale and other tight formations. While estimated sequestration capacity for CO2 sequestration in deep saline aquifers is large, up to 80% of that capacity has areal overlap with potential shale-gas production regions and, therefore, could be adversely affected by shale and tight gas production. Analysis of stationary sources of CO2 shows a similar effect: about two-thirds of the total emissions from these sources are located within 20 miles of a deep saline aquifer, but shale and tight gas production could affect up to 85% of these sources. These analyses indicate that colocation of deep saline aquifers with shale and tight gas production could significantly affect the sequestration capacity for CCS operations. This suggests that a more comprehensive management strategy for subsurface resource utilization should be developed.
■
INTRODUCTION Carbon capture and geological sequestration (CCGS) is a promising technology to reduce carbon dioxide emissions to the atmosphere.1 In CCGS, CO2 from large industrial emitters is captured from the flue gas, converted to a supercritical fluid, and injected into deep geological formations. If CO2 is injected into a formation below about 800 m depth, the temperature and pressure in the formation are high enough to keep the CO2 in a supercritical state. Therefore, a “deep” geologic formation is defined as being deeper than about 800 m from land surface. The most ubiquitous formations for CO2 sequestration are deep saline aquifers, which are deep rock formations where pore space is filled with brine. For a sequestration operation to be successful, the formation into which the CO2 is injected needs to have sufficient permeability to accept the incoming supercritical fluid and displace some of the resident brine. The formation also needs to be overlain by a sufficiently impermeable formation to keep the less-dense CO2 from moving upward and out of the injection formation by buoyancy. Such conditions, with deep permeable formations overlain by impermeable (“caprock”) formations, can be found in many locations in North America due to the depositional history of the continental interior.2 The overall storage capacity for CO2 in deep saline aquifers in the United States has been estimated to be between a minimum ∼1700 giga-tonnes of CO2 (1 giga-tonne = 1 Gt = 1015 grams) and a maximum ∼20 000 Gt CO2.2 For comparison, emissions of © 2012 American Chemical Society
CO2 in the United States due to fossil fuel combustion (both stationary and mobile sources) and cement calcining are about 5.7 Gt CO2/yr.3 Shale is a fine-particle rock with very low permeability, and as such shale formations are usually viewed as very good caprock formations. Therefore, deep shale formations are valuable to CCGS operations, because a permeable formation below a shale formation can be viewed as a good prospect for a CCGS operation. Of course, an ideal caprock shale formation would be a structurally intact and continuous space, so that it forms an effective barrier to fluid flows over the requisite large areas associated with an injection operation. In concert with increasing awareness of CO2 emissions from carbon-rich fossil sources such as coal, the production of shale and tight gas has grown rapidly in recent years. This recent growth is due to widespread application of hydraulic fracturing technologies, wherein otherwise competent low-permeability formations are purposely fractured so that flow channels can be created, thereby enhancing production of natural gas. The fracturing operations are designed to enhance permeability over as large a distance as possible. While good for gas production, Received: Revised: Accepted: Published: 4223
November 9, 2011 February 6, 2012 February 20, 2012 February 21, 2012 dx.doi.org/10.1021/es2040015 | Environ. Sci. Technol. 2012, 46, 4223−4227
Environmental Science & Technology
Article
Figure 1. (A) Continental shale and tight gas basins, overlain with active production shale or tight gas plays as identified by EIA. (B) Potential saline basins for CO2 storage as identified by NATCARB. (C) Superposition of basins from parts A and B with overlap areas identified. The gas and CO2 storage basins have more than 60% overlap in areal extent, which corresponds to roughly 80% of the potential CO2 storage volume.
loss of potential CCGS sites due to shale-gas hydraulic fracturing of otherwise competent caprock formations. Both of these spatial analyses give a first-cut estimate of the possible impact that shale gas production can have on future CCGS operations. Because we only consider areal overlap, and do not consider the actual geological structure in the vertical direction, we consider this initial estimate to be an upper bound on the impacts.
such fracturing operations are clearly in direct contradiction with a CCGS operation that relies on a continuous, competent shale formation to serve as a barrier to flow. In this short note, we gather existing data on location and size of deep saline aquifers in the United States, and compare those locations to the areas of current and potential future shale and tight gas production. This areal analysis provides a first measure of resource competition, with shale being the resource and CCGS and gas production being the competitors. As a second consideration, we identify all large stationary sources of CO2 emissions and analyze which of those would be affected by
■
DATA SOURCES AND METHODS We used the recent update of the National Carbon Sequestration Database and Geographic Information System (NATCARB)4,2 4224
dx.doi.org/10.1021/es2040015 | Environ. Sci. Technol. 2012, 46, 4223−4227
Environmental Science & Technology
Article
Table 1. Quantification of Storage Volume and CO2 Emissions Potentially Affected by Unconventional Natural Gas Production
to identify deep saline formations that are considered suitable for CO2 sequestration. We also used the U.S. Energy Information Association (EIA) database of tight and shale gas formations5,6 to identify areas where gas extraction is ongoing or likely to occur in the future. Both of these data sets were imported into ArcGIS ArcMAP 10 software from Esri; ArcGIS and ArcMAP are the intellectual property of Esri and are used herein under license. As a third data source, we used the reported CO2 emissions from power plants and other industrial sources, as provided by Carr et al. (2007)2 and accessed through NATCARB.4 The reporting of emissions by NATCARB follows protocols outlined in Appendix A: Stationary Source Emission Estimations Methodologies Summaries of NETL (2011).4 We analyzed these data sources to identify (1) geographic regions where shale fracturing associated with natural gas extraction will influence CO2 sequestration and (2) source and volume of CO2 emissions that may have to be diverted due to compromised caprock formations. The overlap between shale gas production and potential CO2 sequestration sites was determined by direct comparison of the NATCARB deep saline aquifer locations and the EIA tight and shale gas maps. We currently do not have sufficient data on vertical structure within the identified areas to perform a full three-dimensional analysis, so our results should be seen strictly as a first-cut areal analysis to identify the fraction of potential CO2 sequestration locations that could be impacted by hydraulic fracturing. When comparing locations and identifying affected areas due to overlap of activities, we considered a simple estimate of pressure build-up associated with a typical CO2 injection, on the basis of the analytical solutions of Nordbotten and Celia (2006).7 On the basis of “typical” results, we implemented a 20 km radius from an injection well as an approximate distance over which elevated fluid pressure could lead to vertical flows across a fractured shale formation [see also Birkholzer et al. (2011)8]. This was included in our definitions of impacted and overlapping areas. To examine the number of stationary sources that could be impacted by compromised sequestration sites, we assumed that a large (>1 Mt CO2/yr emissions) source located over an identified saline aquifer (from the NATCARB data) would be impacted if local shale operations required CO2 from that source to be transported more than 20 miles to reach a suitable sequestration site. This is based on a cost estimate, using 1.2 million U.S. dollars per mile for a 12-in. pipeline, and information that indicated 20 miles as the approximate maximum distance current CO2 EOR operators are willing to pay for a branch pipeline (Denbury, per communication). Small (
