Current through Register 2024 Notice Reg. No. 38, September 20, 2024
(a) Injection pressure at surface shall not exceed the maximum allowable surface injection pressure for an injection well, as approved by the Division under this section and documented in the supporting project data under Section 1724.7(a)(4). Except as provided under subdivision (b), the maximum allowable surface injection pressure for an injection well shall be the lower of following two values:
(1) A calculated pressure value equal to the true vertical depth of the shallowest portion of the well open to the injection zone multiplied by the difference between the injection gradient and the injection fluid gradient (MASIP = (IG - IFG) * TVD). The injection gradient used for this calculation shall be the product of the fracture gradient as determined under subdivision (b) or (c), multiplied by 0.95, or other multiplier subject to Division approval on a well-specific basis that more appropriately accounts for factors such as a conservative allowance for friction loss. If the Division allows friction loss to be factored into the calculation, then the friction factor shall be calculated based on the new coated tubing of the largest diameter that will be used for injection. If a single well is injecting through dual injection strings, then the friction factor of the two strings shall be calculated separately.
(2) The initial test pressure used during the most recent successful pressure test of the injection well under Section 1724.10.1(b). If the pressure testing requirement for the injection well was satisfied under Section 1724.10.1(c) or (d), then the maximum allowable surface injection pressure shall be the calculated pressure value as determined under subdivision (a)(1).
(b) The Division may approve a maximum allowable surface injection pressure higher than what would be allowed under subdivision (a) based on a demonstration by the operator of all of the following:
(1) The higher maximum allowable surface injection pressure is needed for effective resource production;
(2) Injected fluid will remain confined to the approved injection zone;
(3) The higher pressure will not initiate fractures outside the approved injection zone or propagate existing fractures outside the approved injection zone; and
(4) The higher pressure will not otherwise threaten life, health, property, or natural resources.
(c) Subject to the Division's approval, an estimated baseline fracture gradient may be used for determining the maximum allowable surface injection pressure for all injection wells within a given area. An estimated baseline fracture gradient shall be supported by representative step-rate tests, or other testing or geologic data, demonstrating to the Division's satisfaction that the estimated baseline fracture gradient is lower than the actual fracture gradient that would be encountered anywhere in the injection zone where the estimated baseline fracture gradient will be used.
(d) If an injection well is not within the area of an approved estimated baseline fracture gradient, or if the operator seeks to establish a well-specific fracture gradient above the estimated baseline fracture gradient, then the fracture gradient shall be determined by performing a step-rate test on the injection well or by another method approved by the Division to effectively determine the fracture gradient.
(e) Step-rate tests conducted to satisfy the requirements of this section shall meet the following requirements:
(1) Before commencing the test, the well shall be shut in until the bottom-hole pressures approximate shut-in formation pressures. If the shut-in well flows to the surface, then the static surface pressure shall be read and recorded.
(2) The operator may determine the appropriate length of time to conduct each step of the step-rate test, provided that each of the steps is conducted for the same amount of time and a stabilized pressure value is obtained within each step. If steps are conducted for differing lengths of time, if a step does not yield a stabilized pressure value, or if formation breakover is not clearly demonstrated, then the Division may deem the step-rate test inconclusive. Suggested step durations are 30 minutes if the formation has a permeability of more than 10 millidarcies, and sixty minutes if the formation has a permeability of ten millidarcies or less.
(3) The first three steps of the step-rate test shall be below the fracture gradient. Suggested step pressures are 5, 10, 20, 40, 60, 80, and then 100 percent of the proposed injection rate, or until formation breakdown.
(4) Real-time downhole and surface pressure recording using digital pressure gauges shall be employed, unless an alternative has been approved by the Division.
(5) Bottom-hole pressure shall be recorded at a zero injection rate for at least one full time step before the first step of the step-rate test and for one full time step after the last step of the step-rate test.
(6) Step-rate test data reported under Section 1724.7(a)(4) shall include the injection rate, bottom-hole pressure, surface pressure, pump rate, volume, and time recorded continuously at a rate of at least one pressure recording per second during the step-rate test. The step-rate test data submitted to the Division shall be unaltered and submitted in a digital format.
(7) Operators shall provide the appropriate Division district office with at least 24 hours of advance notice, or other period of advance notice acceptable to the district office, prior to conducting a step-rate test for purposes of this section.
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.
