CAPP response to AER request to assess the significance of fluid disposal challenges

Photo: CAPP logo.

This post was extracted from a letter sent by CAPP to AER, earlier today.

The Canadian Association of Petroleum Producers (CAPP) would like to thank the Alberta Energy Regulator (AER) for the opportunity to provide feedback regarding the significance of challenges associated with fluid disposal in Alberta. In response to the AER’s request (dated Nov. 13, 2018) for CAPP to undertake an assessment regarding these challenges, we have surveyed our members and offer the following comments for consideration.

Background
Access to disposal wells and facilities is essential for both unconventional and in situ oil sands developments. Generally, operators will preferentially develop first-party disposal operations for produced water. These operations significantly reduce operational costs, increase field operations efficiency and reduce trucking needs (particularly when tied in to producer water infrastructure). For in situ oil sands development, disposal is included as a part of initial environmental impact assessments. Following project approval, operators apply for site-specific disposal operations – this disposal capacity is integral to in situ project viability.

A timely, predictable and efficient regulatory process for the evaluation, authorization and operation of disposal wells in Alberta is of significant concern for industry. To date, a number of CAPP members have been directly impacted by fluid disposal issues, particularly in the Montney, Duvernay and Deep Basin plays, and in some in situ oil sands areas. Challenges with the current system are causing the following issues:

• Significant stranded capital due to first-party disposal assets awaiting regulatory approval and/or addressing Crown consent/mineral tenure issues;
• Increased costs associated with finding third-party disposal alternatives (due to lack of disposal capacity, Crown consent/mineral tenure issues or protracted regulatory reviews), particularly in unconventional plays where:
  
  • Disposal volumes are being trucked much farther distances to facilities with available capacity (sometimes more than eight hours one-way)
  • Wait times at facilities with capacity is often a large cost component of these operations
    o Emissions footprint is larger as a result of the increased trucking
• Uncertainty associated with the ability to continue disposal operations in cases where tenure associated with disposal zones becomes leased post-approval.

Issues and recommendations
In light of these impacts, CAPP believes that there is the potential for significant additional cost and project certainty/investment decision impacts for operators if these issues are not addressed. Disposal is currently regulated by Directive 051 (D051), Directive 065 (D065), and the Mines and Minerals Act (MMA). The need for change can be highlighted in the following three broad areas:

Crown consent and mineral tenure issues
Mineral rights continuations and reversions are designed to maximize the benefit to Albertans while providing a competitive environment for operators to access those minerals. At present there is a misalignment between Crown consent commonly provided to operators to conduct disposal operations (as pore space in Alberta is owned by the Crown), and the sale of petroleum and natural gas rights (P&NG) and/or metallic and industrial mineral (MIM) permits.

The AER does not specify a requirement to hold mineral rights for a disposal zone (as, by virtue of being suitable for disposal, the lands cannot/do not contain resources). However, currently third parties can apply for P&NG rights for disposal horizons despite the lack of recoverable resources-in-place. In doing so, third-party rights holders gain the ability to object to a proposed or existing offset disposal operation, even if they themselves do not have an operating or proposed disposal operation. These objections often cite that the disposal operation may impact the mineral rights and/or ability of the third party to economically dispose. As well, even if the disposal operator does purchase P&NG rights in advance of conducting disposal operations, having no hydrocarbon potential, these rights will revert to the Crown if production is not realized and may be reposted at a later date.

This misalignment has resulted in the widespread acquisition of numerous sections of subsurface rights and significant uncertainty for operators with existing or proposed disposal operations. This lack of certainty appears particularly acute in areas with a high volume of unconventional development, including the Duvernay and the Montney, as well as in the in situ oil sands regions. CAPP members have noted that these concerns extend beyond fluid disposal operations and also have the potential to impact acid gas disposal operations.

The cost of this issue to individual operators is potentially significant. In some cases third-parties have elevated bids for P&NG rights beyond what would be typical for similar lands. As well, the costs associated with the uncertainty created by this misalignment are significant. The trucking or infrastructure installation required for disposal in suboptimal locations due to “rights blocking” can create knock-on effects that may make prospective operations uneconomic and/or result in deferral or cancellation of projects for which disposal capacity is required. Likewise, the ability for a potential future interest holder to cause existing approvals to be withdrawn creates significant uncertainty and risk on investment decisions. In the case of acid gas disposal operations, in cases where a gas plant relies on acid gas disposal wells, if these wells become unavailable, operators may need to flare sour gas or (in extreme cases) shut in production associated with that facility.

These issues are particularly concerning given the large inventory of existing disposal wells in Alberta (as at November, 2018):

• 3,662 disposal wells (3,529 water disposal, 70 waste disposal, 63 acid gas disposal)
  • Of these disposal wells (includes water, waste and acid gas disposal), approximately 2,527 are on Crown land
  • 1,079 (43%) wells are on undisposed Crown land
  • 1,448 (57%) are on disposed Crown land

Note that disposal wells on disposed Crown land may still pose the same risks as wells on undisposed Crown land because the mineral rights may be owned by a party other than the disposal well operator and/or the rights may expire, revert to the Crown and be reposted over time.

Recommendation 1: In the short term, Alberta Energy should immediately halt the posting and sale of P&NG and MIM rights associated with zones for which there is an active (or proposed) disposal scheme. In the medium term, Alberta Energy, the AER and industry should jointly review and enhance existing practices regarding P&NG rights and pore space to help align procedures for posting and acquisition of undisposed Crown minerals and P&NG rights with approvals that are either granted:

• Under the jurisdiction of the AER for schemes as per D065, or
• As undisposed Crown consents by Alberta Energy.

Other solutions CAPP members have suggested to resolve this issue may include the following (note that these recommendations are draft at present and would require broader industry engagement before any such changes are considered to avoid unintended consequences):

• Broadening of the definition of development to include disposal (and injection) activities for the purposes of continuation of P&NG rights;
• Aligning the tenure process for disposal operations:
  • allowing direct purchase of mineral rights associated with disposal;
  • allowing leasing of lands only with the inclusion of a caveat identifying any established disposal scheme and allowing continuation of those activities; or
  • aligning with approaches used for other subsurface rights (e.g., water).
• In particular for oil sands operators where an environmental impact assessment has been performed to receive an EPEA approval it is recommended that a:
  • consultative notation be granted for all laterally congruent mineral lands for oil sands projects; and
  • priority for disposal rights be granted for operators with applied for/approved EPEA project areas;
• Increasing clarity regarding the technical details required to demonstrate lack of erosion of storage capacity and/or pressure influence on existing disposal wells.

Timelines for disposal authorizations
Currently, operators must complete requirements under both D065 and D051 prior to operating disposal wells. While the AER offers pre-authorization review of D065 components, the D051 review is still required. Depending on classification, this authorization may take between 60 and 130 working days, according to AER standards. AER reviews are generally focused on feasibility, risk to offsets, containment and fluid compatibility. The material reviewed is centered on geologic/plume mapping, stakeholder and offset consultation, and logs (geological and wellbore) showing zone characteristics and wellbore integrity.

Operators and third-parties often drill new wells specifically for the purposes of disposal (versus the historical practice of converting older wellbores to disposal wells). In industry’s view, this should significantly reduce the risk of the review as wellbore integrity issues related to corroded and/or damaged casing are lessened with new wells. As well, data collected on new wells (e.g., logs) provide a much clearer understanding of current wellbore conditions.

Due to the aforementioned regulatory authorization period and because logs are collected post-drilling, there is a period of time during which a potentially functional disposal well is non-operational. During this time, operators may seek third-party disposal alternatives. These options can cost upwards of $40-60+/m³ (versus $2-10/m³ for first-party disposal) and can result in a cumulative costs of $5 million to $10 million per disposal well over the period of regulatory review due to the differential between third-party and first-party disposal costs. Alternatively, where third-party disposal is not a viable option due to costs, volumes or technical constraints, production can be impacted or projects can be delayed.

While initiatives such as the AER’s Bulletin 2018-22 and its new application processing time targets of 60 days or more being reduced by 50% (by April 2019) are positive steps to address some of these issues, industry believes that continued improvement of application timelines can help to further address these challenges.

Recommendation 2: For the AER to reduce the review period for disposal applications in accordance with the risk profile of built-for-purpose disposal wells and thereby reduce potential cost, project delays and production impacts incurred while awaiting regulatory authorization.

Disposal fluid classifications
Currently, fluids for disposal are characterized based on requirements in D051 (March 1994). Fluid classifications are designed to prevent risks to disposal wellbores associated with corrosion and that could lead to wellbore integrity issues. With the advent of multi-stage hydraulic fracturing and the prevalence of slickwater completions, fracturing fluid flowback is still classified as Class Ib (i.e., “spent stimulation fluids”), despite the fact that from a composition perspective it is equivalent to Class II (produced brine water). Operation of Class Ib disposal wells also requires detailed applications/approvals under AER Directive 058 (D058).

Accordingly, industry recommends that fracture flowback water be considered Class II (congruent with its level of risk and wider compatibility with disposal horizons), provided it stays within a prescribed range of chemical properties defined based on risk. A draft D051 was developed in 2012 (in part) to address this issue, but D051 has not been updated since the consultation draft was released. Some industry operators have also developed internal guidance documents to help differentiate between slickwater fracturing fluid flowback and other “spent stimulation fluids.”

Recommendation 3: For the AER to update classification definitions under D051 to align with the risk profile of modern produced fluids to clarify requirements to avoid unnecessary D058 waste applications for disposal wells that are required to have a Class Ib designation, and allow for increased use of the inventory of Class II wells for the purposes of disposal.

Next steps
As noted above, CAPP has identified that the current fluid disposal challenges pose significant potential competitiveness risk to the oil and natural gas industry in Alberta. While initiatives such as the AER’s Bulletin 2018-22 and the new application processing time targets are positive steps to address some of these issues, a more holistic view that includes Alberta Energy and considers the tenure-related elements is required. Opportunities to modernize the current disposal requirements and application timelines will also help to alleviate and address the present fluid disposal concerns.

Sincerely,
Richard Wong, P. Eng.
Manager, Operations