Section 1724.10.2 - Mechanical Integrity Testing Part Two - Fluid Migration Behind Casing, Tubing, or Packer(a) In addition to testing under Section 1724.10.1, operators shall periodically test injection wells to demonstrate that there is no fluid migration behind the casing, tubing, or packer. This testing may be accomplished by any of the methods set forth in subdivisions (d) through (f), or other method approved by the Division (including modifications of the methods below when approved by the Division in writing). Operators shall obtain written approval from the Division regarding the testing method prior to performing the tests.(b) Testing under this section is required within three months after injection has commenced for the first time after a well is approved or reapproved by the Division for injection. Commencing April 1, 2019, subsequent testing under this section is required at least once every two years, with the following exceptions:(1) Disposal injection wells shall be tested at least once a year;(2) Low-use cyclic steam injection wells are required to be tested at least once every five years;(3) If a well that previously met the definition of a low-use cyclic steam injection well has not been tested in over one year, then testing is required within one year of the time that the well stopped being a low-use cyclic steam injection well.(4) Steamflood injection wells equipped with tubing and packer are required to be tested at least once every five years;(5) Testing is required following an unplanned variance in injection pressure of more than 25 percent within a 48-hour period, unless the operator demonstrates to the Division that the variance was the result of an issue that does not relate to well integrity; and(6) Testing is required when requested by the Division, including as may be specified in the Project Approval Letter.(c) On a project or well-specific basis, the Division may approve different testing frequencies from those specified in subdivision (b), and may approve alternative methods for demonstrating an absence of fluid migration behind the casing, tubing, or packer. Any approved variance shall be documented in writing and be based on specific factors identified in the writing, including but not limited to well construction, age of the well, demonstrated quality of cement encasing the well, quality of groundwater in the area, and operational considerations.(d) Radioactive Tracer Survey. In addition to all other applicable federal, state, and local requirements, a radioactive tracer survey performed to satisfy the requirements of this section shall adhere to the following: (1) Testing shall be conducted while injecting, and the operator shall ensure that adequate fluid can be supplied for the test. The injection rate shall be governed by the ability of the operator to track the radioactive tracer as it moves downward, but the injection rate should be stable and as close to the normal operating injection rate as practical.(2) If the injection well is equipped with a packer and there is no injection occurring through the casing-tubing annulus, the casing-tubing annulus valve shall be open during testing and there shall be no fluid flow, unless the well is a gas disposal well. If fluid flow is indicated, the test shall be discontinued and the casing-tubing annulus shall be evaluated.(3) Gamma ray detector sensitivity shall be set in consideration of lithologic and other effects.(4) Before conducting the test, a dynamic temperature survey shall be run from at least 200 feet above the packer to the total depth, and a static temperature survey shall be run for the entire length of the well. A casing collar locator shall be run from 200 feet above the packer to the total depth. If the well is not equipped with tubing and packer, then the casing collar locator shall be from 200 feet above the top perforation to the total depth.(5) A background gamma ray log over the interval to be tested shall be recorded before any radioactive material is introduced into the well.(6) Radioactive tracer tubing rate checks shall be run within 200 feet of the top and 200 feet from the bottom of the tubing.(7) The release of a slug of radioactive material shall be above the interval to be tested.(8) The slug of radioactive material shall be followed with the logging tool or the tool shall make repeated passes upward through the slug as it moves down the well. Alternatively, with Division approval, the amount for the slug to go from surface to the tool may be measured. All logging shall be done at a single logging speed which is appropriate for the injection rate to allow quantitative measurements of deflections to be evaluated.(9) If repeated passes are used, the logs resulting from the slug-tracking exercise should overlap so that the return of radioactivity to the level which existed before the slug's passing is demonstrated for the entire length of the section of the well being tested. The logs of all passes shall be presented as a composite log on a common depth track. If means to differentiate the log traces are available, then no other presentation is required. If the traces cannot be differentiated on the composite log, then they shall also be presented individually.(10) After any ejection of radioactive tracer into the wellbore, the slug of radioactive tracer material shall be followed until it has moved below the interval being tested. Any portion of the slug of radioactive tracer material that divides shall be accounted for.(11) After completion of the log passes, a final log should be made through the entire tested interval to check for residual radioactivity which might be associated with exit of radioactive tracer material from the wellbore.(12) If a well other than a steam injection well is injecting at a rate consistent with that described in subdivision (d)(1), radioactively treated beads shall be introduced into the well and evaluated according to subdivision (d)(7) through (d)(10).(13) Steam injection wells shall be tested using an inert gas tracer.(e) Temperature Survey. A temperature survey performed to satisfy the requirements of this section shall adhere to the following: (1) The well shall be taken off injection at least 24 hours but not more than 48 hours prior to performing the temperature survey, unless an alternate duration has been approved by the Division.(2) The temperature logging tool shall be calibrated to the manufacturer's recommendations or as otherwise requested by the Division.(3) The well shall be logged from the surface downward, lowering the tool at a rate of no more than 30 feet per minute or a faster rate approved in advance by the Division based upon the operator's demonstration that the faster rate will yield data of at least equivalent quality.(4) If the well has not been taken off injection for at least 24 hours before the log is run, comparison with either a second log run six hours after the time the log of record is started or a log from another well at the same site showing no anomalies shall be available to demonstrate normal patterns of temperature change.(5) The log data shall be provided to the Division digitally in LAS, ASCII, or other format that is acceptable to the Division.(f) Noise Log. For a noise log performed to satisfy the requirements of this section, logging shall include a repeat section of no less than 200 feet, preferably across intervals where anomalies are present.(g) The operator shall take immediate action to investigate any anomalies encountered during testing required under this section. If there is any reason to suspect fluid migration, the operator shall take immediate action to prevent damage to public health, safety, and the environment, and shall notify the Division immediately.Cal. Code Regs. Tit. 14, § 1724.10.2
1. New section filed 2-6-2019; operative 4-1-2019 (Register 2019, No. 6). Note: Authority cited: Sections 3013 and 3106, Public Resources Code. Reference: Section 3106, Public Resources Code.
1. New section filed 2-6-2019; operative 4/1/2019 (Register 2019, No. 6).