By Kylie Wright
Water Management
Without water management, producers cannot successfully complete new oil and gas wells in the Permian Basin. The production-water equation has two parts: providing water to the wellhead for drilling and taking produced and flowback water away from the wellhead. Millions of barrels of water are needed to complete a well on the front end of this equation, but billions of barrels of water are produced on the back end, most of which is disposed. As the industry strives toward better water stewardship goals like recycling and beneficial reuse, impacts to disposal options in the meantime can hamstring energy production.
To get a better idea of potential disposal impacts, we need to understand the current disposal capacity in the Permian. Texas’ permit methods allow us to more readily assess the disposal well capacity, so this thought experiment and discussion is limited to TX disposal wells. This topic is complex, with several intertwining considerations which we’ll do our best to address in the following sections.
What is Disposal Capacity?
Capacity encompasses both the volume and pressure of a well, and we use it here to represent the ability of a well to digest a certain volume of fluid (and gas) at a certain pressure. Disposal well capacity can be defined by many potential numbers: permitted, utilized, or operational. State agencies set permitted, or authorized, capacity by specifying barrel per day or pressure limits on disposal well permits. Utilized capacity is the percentage of permitted capacity actually being used by the well operator (for our purposes, a six-month median value). Operational capacity is more complex; we’ve included methodology at the bottom of this article [1].
Operational capacity is based on an estimate of daily injection pressure per barrel and the authorized maximum injection pressure. This captures the reality of pressure limitations on disposal wells and provides a more accurate idea of the volume a well can handle. It’s valuable to understand because operational capacity allows us to estimate a well’s ability to reach it’s permitted volume and pressure based on its past performance. For example, suppose a well is permitted for 30,000 bpd but has been injecting 10,000 bpd at its maximum authorized pressure. In that case, its operational capacity is likely 10,000 bpd not the permitted 30,000 bpd.
The cumulative permitted disposal capacity for the thousands of actively injecting wells in the TX Permian is estimated to be just over 51 million bpd. However, the operational capacity is only around 31 million bpd, a massive 40% less than permitted capacity. Operational capacity is also about 40% less than permitted capacity in both the Midland and Delaware Basins. This paints a picture of a Permian Basin less able to dispose of its water.
Impacts of Capacity Reductions
Seismic Activity Constraining Capacity: sEISMIC rESPONSE aREAS
In September and October 2021, the Railroad Commission of Texas (RRC) announced the Gardendale and NCR Seismic Response Areas (SRAs). The New Mexico Oil Conservation Division also released guidelines for an SRA in New Mexico along the southern state line on November 23, 2021. The Midland Basin Gardendale SRA (and Stanton SIR) in TX requests a reduction of maximum daily injection to 10,000 barrels per day (bpd) for 76 SWDs, monthly reporting of daily injection volume and pressure, historical daily injection volume and pressure reporting since November 2019, prevents permitted but unused SWDs from beginning operations. Operators were requested to indicate compliance within 30 days and implement volumetric and reporting changes within 90 days. All requested changes remain in effect until further notice. No new well permits will be approved in the Gardendale SRA.
The NCR SRA is more complex. The RRC has requested that operators of 89 wells within the NCR SRA develop an Operator Lead Response Plan (OLRP). The OLRP is expected to address the RRC goal of reducing earthquake activity in the NCR SRA. The RRC measure of success is specified as “no more M 3.5 or greater earthquakes after 18 months from implementation” within the NCR SRA. Operators have 90 days to develop, evaluate, and implement the OLRP or the RRC will instead implement its own Seismic Response Action Plan (SRAP). The SRAP for the NCR SRA includes injection curtailments based on the injection interval depth and proximity of wells to the seismic hotspots in the center of the SRA. The RRC has stated that it will continue to review SWD permit applications within the NCR SRA until an OLRP or SRAP is implemented, and if an SRAP is required no new permits will be approved in the NCR SRA for an unknown period.
Both SRAs seek to address the potential connection between produced water disposal and induced seismicity in the Permian Basin. The goal is to eliminate significant magnitude seismicity within a year or two by curtailing the amount of water going downhole and decreasing the depth of SWD disposal intervals. The long-term efficacy of this strategy is unclear given the industry and scientific communities’ evolving understanding of Permian-induced seismicity causes. Though these measures will undoubtedly impact the disposal capacity of certain wells, the specific volumetric impacts of these SRAs are currently unclear, as the operator response is still evolving. The estimated reduction of permitted capacity in the Gardendale SRA is about 900,000 bpd. The reduction in the NCR SRA is close to 2 million bpd.
dEVELOPING Our Understanding
As we discussed in the preceding sections, these reductions in disposal capacity could have severe implications on disposal availability. Volume reductions like these assume that the permitted volumes being reduced were available in the first place, which we know could be far from accurate. Additionally, if the RRC or SWD operators decide that more significant volume reductions are needed to thoroughly address seismicity, capacity constraints will be more severe and water management costs in these areas will rise. In either scenario, if disposal availability decreases or new disposal permitting is limited, the industry should expect water management costs to increase, especially in core Midland Basin and New Mexico acreage. Disposal capacity in the Permian is difficult to confidently assess whether from the perspective of existing operational capacity or even through the lens of total potential disposal capacity. We must continue to develop our understanding of disposal capacity in the Permian and what limiting disposal could do to the ability of the oil and gas industry to produce energy. This understanding will be a key part in infrastructure development strategies, regional capital deployment decisions, and water management plans for E&P companies.
[1] There are over four thousand active disposal wells across the TX Permian; for each of these wells we used a six-month median value for daily injection rate (bpd), injection pressure (psi), and injection pressure per barrel (psi/bbl). Operational capacity was estimated by dividing maximum authorized injection pressure (psi) and by daily pressure per barrel. If daily injection pressure was zero and injection rate was zero, then the operational capacity is the permitted capacity. If daily injection pressure was zero and injection rate was positive, then the operational capacity is the permitted capacity. If daily injection pressure was positive and injection rate was zero then the operational capacity for that well is null. This calculation for operational capacity is based on reported injection pressure which may have limited accuracy based on the quality of reporting or the type of pressure monitoring. Operational capacity is variable and can change over time.
