In situ measurement of effective wellbore permeability

There are millions of old oil and gas wells in North America. Because these wells represent potential leakage pathways for injected CO2 as well as displaced brines, it is important to characterize the properties of these wells. Both bp (through collaboration with Walter Crow) and Schlumberger (through collaboration with Princeton alumnus Andrew Duguid) have used a technique called a Vertical Interference Test (VIT) to determine, in situ, the effective permeability of materials (mostly cements) outside of well casings. These tests provide permeability estimates over distances of a few meters along the well. Michael Celia and colleagues have analyzed these test results to infer the effective permeability of the materials outside of casing.

These tests are not easy to perform, and to date nine tests have been performed in six different wells. The Celia Group has analyzed each of these data sets, and from this analysis approximated the well permeability. Of the permeability values from tests that yielded usable numbers (6 of the 9 tests), 3 have been approved for publication ( Table 3). They range from about 1 milliDarcy (mD) to about 50 Darcy (D). To put this into perspective, permeability of a good reservoir rock is typically about 100 mD; the Utsira formation, which is the injection formation for the Sleipner operation, has permeability of about 1 D, while the In Salah reservoir has permeability of about 10 mD. Cement cured at room conditions usually has a permeability of about 0.01 microDarcy. These initial numbers indicate that effective permeabilities outside of casing, over distances of a few meters along the well, are higher than expected and are roughly in the range of reservoir permeabilities. These numbers can form the basis of more realistic simulations to estimate leakage along old wells.


Shale gas interference with CCS

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 of greatly increasing 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.

The Celia Group has 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 (Figure 5). While estimated sequestration capacity for CO2 sequestration in deep saline aquifers is large, up to 80% of that capacity 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 emissions from these sources are 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.

Figure 5. A) EIA identified tight and shale gas basins, which could be use for unconventional gas production; B) saline basins identified by NATCARB as ideal storage formations; and C) overlap of (A) and (B). The gas basins overlap over 60% of the targeted saline formations within the contiguous continental United States.