40 CFR §146.8(b)(3) allows the use of a special mechanical integrity test (MIT) for existing Class II enhanced recovery injection wells (this MIT is sometimes referred to as the injection pressure injection rate or IPIR MIT), as follows:CONCLUSION
"(3) Records of monitoring showing the absence of significant changes in the relationship between injection pressure and injection flow rate for the following Class II enhanced recovery wells:
(i) Existing wells completed without a packer provided that a pressure test has been performed and the data is available and provided further that one pressure test shall be performed at a time when the well is shut down and if the running of such a test will not cause further loss of significant amounts of oil or gas; or
(ii) Existing wells constructed without a long string casing, but with surface casing which terminates at the base of fresh water provided that local geological and hydrological features allow such construction and provided further that the annular space shall be visually inspected. For these wells, the Director shall prescribe a monitoring program which will verify the absence of significant fluid movement from the injection zone into an USDW."
This provision has not been widely applied to Class IIR wells; in fact, it has never been allowed in Kentucky by EPA Region IV, not even for a single well. To further complicate matters, Region IV has recently declared that the relief appearing at 40 CFR §146.8(b)(3) is restricted to only injection wells without tubing and packer, despite compelling evidence that said provision was intended to apply to all existing Class IIR enhanced recovery wells, even those completed without tubing and packer. It has been suggested that a poor understanding of the importance and usefulness of flow monitoring has colored EPA's current attitude about 40 CFR §146.8(b)(3); see Water Meter Mistakes and Manifold Monitoring and Water Meter Trivia.
Historically the use of injection pressure / flow rate data to demonstrate well integrity crept into the underground injection control (UIC) regulations as a result of the 1981 multi-industry litigation challenging EPA's 1980 final UIC regulations. API, MOGA, ARCO, Shell, Texaco, Pennzoil, Tenneco, Mobile, and the State of Texas joined with the iron and steel and mining industries in said lawsuit. Industry presented 93 issues for discussion in the settlement negotiations; the oil and gas industry raised about 15 of the 93 issues, with Issue Paper 70 covering matters discussed herein. On October 1, 1981, EPA proposed the language that now appears in 40 CFR §146.8(b)(3) pursuant to the settlement of the above mentioned litigation. The actual regulatory revisions were promulgated on February 3, 1982. The applicable preamble (46 Fed. Reg. 48247, October 1, 1981) states as follows:
"These proposed changes only apply to enhanced recovery wells since EPA believes that shutting down these wells in order to run a pressure test could have a substantial impact on oil and gas production. Further for these wells a strong economic incentive exists for the operator to insure that the wells function properly, i.e., that there are no significant leaks from the well. There are no changes proposed for salt water disposal wells since shutting these wells down for a few days every five years in EPA's view would only have minimal impact on oil and gas production."
It would seem clear from the foregoing preamble language that relief was being granted for existing Class IIR enhanced recovery injection wells from the time burden of running pressure MITs. Obviously, the "Existing wells completed without a packer..." would have ordinarily required a packer at some point in time in order to undergo the required initial pressure test, so this relief could not be intended for only those wells with a mechanical or operational problem precluding the use of tubing and packer. The mention of salt water disposal wells in the preamble is important since no salt water disposal well, existing or otherwise, would be allowed to operate without tubing and packer, yet the preamble language distinguishes between said categories of injection wells. Region IV's position would urge the removal of the tubing and packer in existing Class IIR wells, thus unnecessarily reducing the layers of protection by one, in cases where an operator wants to avoid the burden of pressure MI retests. While many operators may do this very thing for economic reasons, it is foolish to force such an outcome as a result of a misguided interpretation of the regulations.
Given the history of the MIT relief contemplated at 40 CFR §146.8(b)(3), the only reasonable conclusion is that said relief applies to all existing Class IIR wells. Region IV's interpretation leads to the bizarre outcome that an operator can escape the burden of a conventional pressure MIT by actually making the subject injection well less safe, an outcome surely not intended by the original industry litigation, and an outcome contrary to good public policy.
After this page was prepared, the following draft letter was found in our archives:
March 22, 1999
(Addressee Deleted for Privacy Reasons)
Re: 40 CFR §146.8(b)(3)(i) MI Retests
Dear (Deleted for Privacy Reasons):
This letter is my attempt to explain my take on the 40 CFR §146.8(b)(3)(i) issue.
In narrowly reading said section, Region IV would limit the relief granted to only casing injectors (wells completed without a packer). Given the history of this matter and the applicable preamble language, I believe their position is wrong-minded.
First, the present language at 40 CFR §146.8(b)(3) was included to settle the multi-industry litigation, and specifically addresses Issue Paper 70. Industry hoped to escape future pressure testing for Class II wells. It is important to understand that "real" oil states like Texas have required an initial SAPT prior to commencement of injection for many years; hence there was no resistance to the EPA requirement "...that one pressure test be performed…" (40 CFR §146.8(b)(3)(i)). It is significant that EPA narrowed the relief to only Class IIR wells, and not all Class II wells. Since virtually all Class IIR wells in the "real" oil states were already equipped with tubing and packer, offering relief to only the tiny number of casing injectors amounts to virtually no relief at all. The industry got what it asked for with the exception of a limiting of the relief to Class IIR wells from all Class II wells. Region IV improperly attempts to limit the relief granted to the industry even further.
Second, the explicit language of the October 1, 1981 preamble mentions "...discussions with the litigants…" and enumerates two reasons for agency reconsideration. [Unrelated sentence omitted.] Notwithstanding the two reasons, the preamble goes on to discuss how the proposed changes apply to enhanced recovery wells "...since EPA believes that shutting down these wells in order to run a pressure test could have a substantial impact on oil and gas production." That language would be meaningless if the relief was meant to apply to a couple of percent of Class IIR wells! Even wells already equipped with tubing and packer require a considerable expenditure of time, and usually must be removed from injection service for at least a day or two (often longer).
Third, Region IV's position is absurd on its face. If they are correct, then any operator can escape ever doing subsequent Class IIR SAPTs by withdrawing the tubing and packer from all injection wells after an initial SAPT. The insane outcome of this flawed interpretation is that by removing a "layer of protection", an operator can escape a regulatory burden. Stated otherwise, Region IV would argue to exempt only the least safe wells from subsequent SAPTs!
The industry sued EPA seeking relief, and they got it. The only reasonable reading of 40 CFR §146.8(b)(3) is that the relief contemplated is available to all Class IIR wells, even those awful wells without tubing and packer.| Home | Tech & Tips | UIC MIT Menu |
Syd H. Levine