Current through Register 2024 Notice Reg. No. 38, September 20, 2024
(a) Casing Pressure Test at the Maximum Allowable Surface Pressure. Prior to commencing injection operations for the first time after a well is approved or reapproved by the Division for injection, each injection well shall pass a pressure test of the casing to determine the absence of leaks. Thereafter, the casing of each well shall be tested at least once every five years, prior to recommencing injection operations following the repositioning or replacement of downhole equipment, or whenever requested by the Division. If an injection well is a gas disposal well, then the casing of the well shall be tested at least once every year. If a required pressure test is not successfully completed, then the operator shall immediately notify the Division and the well shall not be used for injection without subsequent written approval from the Division.
(b) Pressure testing under this section shall conform to the following:
(1) If injection in the well is through tubing and packer, then the pressure test shall be of the casing-tubing annulus of the well.
(2) Pressure testing shall be conducted with a liquid unless the Division approves pressure testing with gas.
(3) If pressure testing will be conducted with a liquid that contains additive other than brine, corrosion inhibitors, or biocides, then the operator shall consult with the Division regarding the contents of the liquid prior to commencing testing.
(4) The wellbore shall be filled with a stable column of fluid that is free of excess gases.
(5) Pressure tests shall be recorded and a calibrated gauge shall be used that can record a pressure with an accuracy within one percent of the testing pressure. Pressure shall be recorded at least once per minute during testing. If an analog gauge is used, then the test pressure shall be within the mid-range scale of the gauge. The pressure test results shall be submitted to the Division in a digital tabular format within 60 days of the date the test is conducted. The charts or digital recording of the pressures during testing shall be provided to the Division upon request.
(6) The operator may select the initial test pressure of the pressure test, provided that the pressure test is conducted at an initial test pressure of at least 200 psi above surface pressure, and the maximum allowable surface injection pressure for the injection well, as determined under Section 1724.10.3, shall not exceed the initial test pressure used during the most recent successful pressure test.
(7) Pressure tests shall test the casing of the well from the surface to a depth that is within 100 feet measured depth above the uppermost perforation, immediately above the casing shoe of the deepest cemented casing, or immediately above the top of the landed liner, whichever is highest. If the top of the landed liner is 100 feet or more above the cemented casing shoe, then the pressure test shall be to a depth specified by the Division on a case-by-case basis.
(8) A pressure test is successful if the pressure gauge does not show more than a three percent change from the initial test pressure over a continuous 30-minute period, except that if the well is a cyclic steam injection well, then an increase in pressure of as much as 10 percent is a successful test.
(9) The Division may modify the testing parameters on a case-by-case basis if, in the Division's judgment, the modification is necessary to ensure an effective test of the integrity of the casing.
(c) Alternative Pressure Monitoring. Subject to the Division's approval, for injection wells equipped with tubing and packer, operators may propose a pressure testing and annular pressure monitoring program, consistent with this subdivision, as a substitute for the pressure test described in subdivision (a). If an injection well is covered by an approved pressure testing and annular pressure monitoring program, then the maximum allowable surface pressure for the well is the calculated pressure value under Section 1724.10.3(a)(1).
(1) An operator's proposals for alternative annular pressure monitoring shall include the following information:
(A) All relevant information about the injection wells proposed to be monitored, including identifying information, size of the tubing and packer and setting depth, and date of the last tubing and packer reset;
(B) All relevant information about the proposed pressure monitoring system, including monitoring instrumentation specifications, computer data acquisition and storage system specifications, method and frequency of calibrating and otherwise confirming the working order of the monitoring system, data retention, and reporting protocols with a clear identification of reportable statistical deviations;
(C) Schedule of injection project implementation, including the known and anticipated addition or removal of wells from the project; and
(D) Technical justifications and reasons for requesting the alternative proposal.
(2) Alternative pressure testing and annular pressure monitoring programs are subject to the Division's approval, and the requirements and limitations stated in subdivisions (A) through (F), below.
(A) The well shall be pressure tested in accordance with all of the requirements in subdivision (a), except that pressure tests shall be conducted at an initial pressure of at least 500 psi, and subdivision (a)(6) shall not apply.
(B) In order to demonstrate ongoing mechanical integrity, the alternative annular pressure monitoring program shall adhere to the following conditions:
(i) The casing-tubing annulus shall have a minimum of 100 psi pressure at all times, preferably with a nitrogen gas blanket at the surface to stabilize potentially large variations in pressure due to thermal expansion of incompressible fluid;
(ii) There shall be an observable pressure differential (+/- 10 percent of the tubing pressure or at least +/- 50 psi) between the annular pressure and the tubing pressure; and
(iii) There shall be no anomalous variances in the annular pressure. If there are significant pressure variations from the historic daily pressure readings, these shall be satisfactorily explained and documented as part of the operator's record of mechanical integrity.
(C) The Division may consider proposals to modify the conditions of subdivision (c)(2)(B) on a case-by-case basis if the Division determines that the proposal will represent a stronger demonstration of ongoing mechanical integrity. Such proposals may include, but are not limited to, fail-safe systems, such as automatic casing pressure relief systems, and other back-up safety, shutdown, and pressure relief systems.
(D) The casing-tubing annular pressure shall be measured and recorded at least as frequently as every five minutes with a pressure gauge having an appropriate range. The record of such documentation shall be made available to the Division upon request, including in digital form within one business day of a request from the Division. A Division-approved, operating supervisory control and data acquisition (SCADA) system, with automatic computer alarm notification, may be used to satisfy this requirement and is a preferred methodology.
(E) The operator shall take immediate action to investigate any anomalous pressure incidents, as compared to historic daily readings. If there is any reason to suspect a leak, the operator shall take immediate action to prevent damage to public health, safety, and the environment. The operator shall provide immediate notice to the Division of any anomalous pressure incidents and the steps taken in response.
(F) At any time, the Division may request a full casing pressure test as described in subdivision (a).
(d) Alternate Testing Methods. An alternate mechanical integrity testing method may be used to satisfy the requirement under this section to pressure test the casing of an injection well if the alternate testing method has been approved by the Division on a case-by-case basis as being at least as effective as pressure testing to demonstrate the integrity of the well at the calculated pressure value under Section 1724.10.3(a)(1). Examples of alternate testing methods that would be considered on a case-by-case basis are a casing wall thickness inspection to estimate internal and external corrosion, employing such methods as magnetic flux or ultrasonic technologies; or a combination of an ultrasonic imaging tool and a cement evaluation log. If the most recent successful test of an injection well under this section was by testing approved under this subdivision, then the maximum allowable surface pressure for the well is the calculated pressure value under Section 1724.10.3(a)(1).
(e) For injection wells that as of April 1, 2019, were approved for injection but were not previously subject to periodic casing pressure testing requirements, testing under this section is not required to be completed until April 1, 2024, unless the injection well is a gas disposal well, in which case testing shall be completed by April 1, 2020. For all other injection wells, if testing consistent with the requirements of this section has not been done on the well in the past five years, or in the past year if it is a gas disposal well, then the well shall not be used for injection without subsequent written approval from the Division.
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.
