🛢️ G Arnold 1 SWD

Firebird Services, LLC · Divide County, ND · File #42396 · Generated 2026-02-13 12:33

API: 3302301699
Target Formation: Inyan Kara (Dakota Group)
Permit Explained: Yes

📋 Permit Cycle Assessment

The well file contains explicit, contemporaneous regulatory and technical documentation that explains and conditions the permit approval anchored to 13 October 2025 (Industrial Commission Order No. 34944). The primary permit justification is the UIC Class 2D authorization order, which conditions approval on compliance with all NDAC Chapter 43-02-05 provisions and a referenced Oil and Gas Division injection permit (UICSWD1250). The injection permit specifies maximum surface pressure of 1,315 psi, maximum rate of 30,000 BPD, and required MIT pressure of 1,000 psi. These operational limits are directly justified by a Well Fracture Analysis dated 1 October 2025, which employs EPA-compliant formation fracture pressure calculations (1,346.12 psi) based on measured fluid specific gravity (1.21) from a certified laboratory analysis (Pace Analytical, 8 August 2025, sample from offset Moe Trust well). Non-routine permit stipulations (shutdown devices, tank level sensors, perimeter berm, immediate spud notification) are documented in the APD Stipulations section and represent UIC-specific risk mitigation measures. Geotechnical support for surface containment adequacy (Braun Intertec, 4 August 2025) is also present. All signals directly condition the permit approval; none are pre-permit background material lacking regulatory linkage. The permit cycle is fully documented from authorization through operational constraint specification.

🔍 Permit Cycle Signals (5)

UIC Class 2D permit authorization issued via Order No. 34944, Case No. 32167, conditioned on operator compliance with all NDAC Chapter 43-02-05 provisions and Oil and Gas Division injection permit.

Direct

📄 Industrial Commission Order, dated 13 October 2025, pages 1-2
📅 2025-10-13 (Exact confidence)

This is the anchoring regulatory authorization. All subsequent drilling, completion, and injection activity must conform to conditions embedded in this order and the referenced injection permit. The order explicitly conditions approval on compliance with the Oil and Gas Division permit (which specifies maximum injection pressure of 1,315 psi surface equivalent, 30,000 BWPD maximum rate, and Class 2D designation).

Injection permit (UIC No. UICSWD1250) specifying maximum allowable surface injection pressure of 1,315 psi, maximum injection rate of 30,000 BPD, required MIT pressure of 1,000 psi, and fracture gradient of top confining zone at 0.8 psi/ft with bottom hole fracture pressure of 3,901 psi.

Direct

📄 Well Completion Report, UIC Information section, page 2 of 5; Well Fracture Analysis worksheet dated 1 October 2025
📅 2025-10-01 (Inferred confidence)

These are the operational constraints that directly condition the permit approval. The MIT pressure requirement and pressure limits are mandatory pre-injection tests. The fracture gradient calculation directly justifies why this particular injection pressure ceiling was imposed (formation fracture pressure = 1,346 psi, less hydrostatic = 1,315 psi surface equivalent).

Stipulations attached to New Well Vertical permit (APD Form) requiring: (1) immediate notification to NDIC Field Inspector or Bismarck office upon spud with Sundry Notice in NorthSTAR within 3 business days; (2) rat/mouse holes to be plugged with cement and cut 4' below grade within reasonable timeframe; (3) perimeter berm surrounding entire location required; (4) remote/automatic shutdown devices on all equipment; (5) tank level sensors required.

Direct

📄 Application for Permit for New Well—Vertical Salt Water Disposal, Stipulations section (5 stipulations listed)
📅 Unknown (Missing confidence)

These are non-standard UIC-specific stipulations that directly condition the permit's enforceability. They establish operational and safety baselines that differ from routine APD boilerplate. The shutdown device and tank level sensor requirements are direct risk-mitigation measures tied to injection facility operations.

Maximum Injection Pressure calculation dated 1 October 2025 employing FP = [fg – (0.433 × sg)] × d formula, yielding 1,346.12 psi formation fracture pressure and 1,315 psi permitted surface pressure. Specific gravity of injected fluid = 1.21 (from produced water sample analysis dated 7/23/2025, lab report 10743605).

Supporting

📄 Well Fracture Analysis (UIC Supervisor Jared Thune, 1 Oct 2025); UIC Plan Section 4; Pace Analytical Lab Report pages 1-6 (sample collection 7/23/2025, analysis 8/8/2025)
📅 2025-10-01 (Exact confidence)

This technical submission directly justifies the permit's pressure ceiling. The specific gravity measurement (1.21) is critical input; without lab confirmation of fluid properties, the pressure calculation cannot be certified. This represents the quantitative basis for the injection authorization.

Geotechnical Report (Braun Intertec, 4 August 2025) concluding that glacial till deposits with low permeability (hydraulic conductivity 1×10⁻⁶ to 1×10⁻⁸ cm/s) are suitable for retaining surface spills for at least 30 days, with recommendation for in-place soil density testing at 1-ft vertical and 10,000 sq ft horizontal intervals and compaction to 98% Standard Proctor.

Supporting

📄 Geotechnical Investigation Report, Conclusions section, pages 6-8; Boring Logs GP-01 through GP-06 with Fence Diagram
📅 2025-08-04 (Exact confidence)

This report was submitted in support of the Application for Injection permit (referenced in UIC Plan Section 7 and Appendix G). It directly justifies that site geology can support surface containment of potential spills, supporting the adequacy of the proposed facility design (perimeter berm, tank containment, synthetic liner). The compaction specifications are structural conditions for pad construction.

📖 Historical Context (5)

Industrial Commission Order No. 34944 (13 October 2025) contains conditional language requiring 'the operator receiving and complying with all provisions of the injection permit issued by the Oil and Gas Division' and 'all other provisions of NDAC Chapter 43-02-05,' establishing indefinite compliance obligation with UIC regulations that persist beyond this specific permit action.
📄 Industrial Commission Order No. 34944, Ordering Paragraph (2), page 2 · 📅 Unknown
This order remains 'in full force and effect until further order of the Commission' (Ordering Paragraph 3). All future operations, monitoring, reporting, and well modifications must remain compliant with referenced regulations. Any change in injection rate, pressure, zone, or facility design will require amendment or new authorization.

Affidavit of Company Relationships (Brandon Allen, COO Phoenix Energy One, LLC, dated August 2025) states that Firebird Services, LLC retains ownership of saltwater disposal pump skid, pump, meter, and injection flowline, while Phoenix Operating LLC retains ownership of oil wells and primary production equipment. Custody transfer of produced water occurs at metering point. Establishes operational interface and liability delineation between two subsidiaries.
📄 Affidavit of Company Relationships, pages 1-2 (signed statement with notarization dated August 2025) · 📅 Unknown
This corporate structure creates ongoing regulatory and operational accountability for well performance. In case of injection-related non-compliance, spill, or facility failure, the affidavit establishes which entity is responsible for correction. The metering point custody transfer is a material operational control point for production accounting and waste stream characterization.

UIC Plan (undated but referenced in Order No. 34944) identifies five planned source wells for produced water injection (Gail Arnold 33-28-21 1H through 5H-LL, all with Permit Status 'LOC' [Location] as of document date). Appendix D lists no third-party volumes planned. Current production from these source wells will directly determine daily injection rates and volume sustainability.
📄 UIC Plan, Section 6 and Appendix D; Application for Permit for New Well—Vertical Salt Water Disposal (source well list) · 📅 Unknown
The authorization assumes produced water availability from these five planned companion wells. If these wells do not reach productive status, are plugged, or underperform, the SWD well's utility is diminished. Conversely, if additional source wells are drilled on the pad, the injection authorization may be tested against new volumes. Any third-party volume requests would violate the stated injection plan and require permit amendment.

Formation fracture gradient of upper confining zone (Mowry Fm.) specified as 0.8 psi/ft with bottom hole fracture pressure 3,901 psi at 4,876' TVD (top of Inyan Kara injection zone). This gradient value is non-negotiable structural parameter for all future pressure management and MIT interpretation.
📄 Well Fracture Analysis (Jared Thune, 1 October 2025); UIC Plan Section 4; Well Completion Report UIC Information section · 📅 Unknown
The 0.8 psi/ft fracture gradient is the foundational input for all operational pressure ceilings. If post-drilling geophysical data (e.g., leak-off tests, formation integrity tests) reveals different fracture gradient, the entire injection pressure regime may require recalibration. Any deviation from the assumed 0.8 psi/ft gradient discovered during well operations must be reported and may trigger re-approval.

Geotechnical site characterization (Braun Intertec, 4 August 2025) documents presence of low-permeability glacial till with 1.5–2 feet topsoil and cohesive clay-rich deposits. Report notes 'significant grade raise to reach finished pad elevation will likely cause several inches of settlement' and recommends future standard penetration test (SPT) borings if 'stability of the well pad or settlement is a concern.' Geotechnical engineer explicitly reserves option for additional exploration.
📄 Geotechnical Investigation Report, Background and Conclusions sections, pages 1, 6-7 · 📅 Unknown
The report identifies unresolved settlement risk due to the 28.5-foot maximum fill at pad southwest corner. While the low permeability conclusion justifies surface containment adequacy, differential settlement could compromise tank foundation integrity, berm stability, or wellhead alignment over operational life. The engineer's conditional language ('if stability … is a concern') creates forward obligation to monitor. Settlement-induced wellhead damage could compromise the injection system's integrity.

🔧 Operator Pattern

Firebird Services, LLC operates as a subsidiary focused solely on saltwater disposal infrastructure, while Phoenix Operating LLC owns and operates oil production wells. This segregated corporate structure appears designed to isolate injection risk and regulatory accountability. Firebird's operational model is co-location of SWD infrastructure with Phoenix's multi-well pads, with a shared tank dike and perimeter containment.
Affidavit of Company Relationships establishes Firebird as 100%-owned subsidiary of Phoenix Energy One, LLC, with specific delineation of asset ownership (Firebird owns SWD pump skid, meter, injection line; Phoenix owns oil wells and primary tank battery). Multiple cross-references in UIC Plan and facility design documents indicate Firebird provides disposal service for Phoenix-operated wells. Absence of any non-affiliated third-party volume disposition language in the application suggests Firebird's current business model is limited to intra-corporate waste management for Phoenix subsidiaries.

Confidence: High
The file contains a complete regulatory record with unambiguous permit authorization (Industrial Commission Order No. 34944, dated 13 October 2025), explicitly referenced injection permit conditions (UIC UICSWD1250, maximum 1,315 psi surface pressure, 30,000 BPD max rate), and supporting technical documents with specific dates and author attribution (UIC Plan, Well Fracture Analysis by Jared Thune dated 1 October 2025; Pace Analytical Lab Report dated 8 August 2025; Geotechnical Report by Braun Intertec dated 4 August 2025). Well completion operations (spud 29 October 2025, TD reached 31 October 2025, completion 22 December 2025, first injection 22 December 2025) are documented in timestamped sundry forms with reviewer signatures. No material gaps exist between permit issuance and operational commencement. The only ambiguity is the exact effective date of the injection permit itself, which is inferred rather than explicitly stated in the permits section, but this does not undermine the clarity of the authorization order or its supporting technical justification.