🛢️ Folden SWD 1

Murex Petroleum Corporation · Williams County, ND · File #File No. 42586 | Case No. 32328, Order No. 35083 · Generated 2026-02-13 12:33

API: 3310506767
Target Formation: Dakota Group (Inyan Kara Formation)
Permit Explained: Yes

📋 Permit Cycle Assessment

The permit approval is contemporaneously documented and justified through the following sequence: (1) Industrial Commission Order No. 35083 (19 December 2025) authorizes Class II injection into the Dakota Group on condition that the Oil and Gas Division issue and the operator comply with an injection permit; (2) pre-permit UIC Supervisor fracture analysis (11 November 2025) calculates site-specific maximum allowable surface injection pressure of 1,272 psi, based on Greenhorn Shale confining-zone integrity; (3) Area of Review analysis confirms no mechanical integrity corrective action required and verifies offset well (Davidson 5795 31-33 2B) poses no threat; (4) fresh water analysis establishes Class II waste classification, meeting exempted aquifer threshold for Dakota Group; (5) six non-routine UIC stipulations condition permit approval and mandate facility design controls (berm, liner, shutdown devices, tank sensors, spud notification, rat-hole plugging). All signals are time-bound to the permit cycle. No material unexplained gap exists between permit approval and supporting documentation.

🔍 Permit Cycle Signals (5)

Industrial Commission Order No. 35083 authorizing Class II injection into Dakota Group and conditioning approval on operator receipt and compliance with injection permit issued by Oil and Gas Division per NDAC §43-02-05-04

Direct

📄 Order No. 35083, dated 19 December 2025, findings (1)–(9) and operative clause (2)
📅 2025-12-19 (Exact confidence)

Explicit regulatory condition precedent: UIC authorization is contingent on receipt and compliance with Oil and Gas Division injection permit. This order anchors the permit approval and establishes the framework for all stipulations.

UIC Supervisor (Jared Thune, 11 November 2025) calculated and permitted maximum allowable surface injection pressure of 1,272 psi, based on fracture gradient analysis of upper confining zone (Greenhorn Shale) and hydrostatic pressure of fluid column. Wellhead pressure constraint is structural to well design.

Supporting

📄 Well Fracture Analysis, dated 11 November 2025; Permitted Max Allowable Surface Injection Pressure: 1,272 psi
📅 2025-11-11 (Exact confidence)

Technical engineering document directly supporting permit approval. Pressure limit is a non-routine, site-specific operational constraint that differentiates this permit from generic SWD authorizations and must be enforced during injection operations.

Area of Review (¼-mile radius) analysis dated prior to permit approval confirms no corrective action required for Lana Kristy 29-32H (deep Bakken lateral) and verifies that Chord/Oasis Davidson 5795 31-33 2B well (spud 26 August 2025, pending TD) intersects Inyan Kara formation outside AOR, eliminating mechanical integrity threat.

Supporting

📄 AOR Calculations and Chord well spacing verification (pages 3–4); Drilling survey comparison (Appendix, pages 69–71)
📅 Relative: Pre-permit (inferred from survey completion prior to 19 Nov 2025 hearing) (Inferred confidence)

Confirms no corrective action required under UIC regulations. AOR analysis directly justifies permit approval under NDAC §43-02-05 framework (formation integrity, confining zones, absence of open faults). Critical to waiver of mechanical integrity risk.

Fresh water quantitative analysis (representative sample from Terry-Lynn Tank Battery) demonstrates injected fluids are Class II waste (total dissolved solids 145,580–175,425 mg/L, far exceeding SDWA 10,000 ppm exempted aquifer threshold). Actual source water analysis to be performed post-completion of pending AB-Pad and Davidson wells.

Supporting

📄 Fresh Water Quantitative Analysis (pages 10–29); Injected Water Quantitative Analysis (pages 31–49); Proposed Injection Program (page 30)
📅 Representative analysis date: Unknown; injection program documentation pre-permit (Inferred confidence)

Establishes regulatory basis for Class II injection authorization. However, analysis is *representative* pending actual source well completion. This creates forward operational requirement: actual water analysis must be submitted and approved before injection commences. Condition persists beyond permit issuance.

Six UIC stipulations issued with permit (spud notification, rat/mouse hole construction and plugging, perimeter berm, remote shutdown devices, tank level sensors, synthetic liner in tank dike) are non-routine facility-design requirements that condition permit and differentiate this SWD from minimal-containment disposals.

Direct

📄 Permit Information, STIPULATIONS section (page 1)
📅 Permit approval context: 19 December 2025 (inferred from Order date) (Inferred confidence)

Stipulations are regulator-imposed conditions that condition permit approval. All six are facility/operational mandates that go beyond boilerplate setbacks and closed-mud-system language. Require enforcement during rig-up and operational phases.

📖 Historical Context (4)

Source wells (AB-Archie B Federal, AB-Charly Chally Federal, AB-Cody Lynn Federal, AB-Edward Fox Federal, AB-Kelly Renee Federal, AB-Ivy Jolyn Federal LS, and Chord Davidson 5795 31-33 2B–6BX) are listed as 'pending' and have not yet been spud/completed. Actual produced water composition will differ from representative Terry-Lynn analysis used to justify permit approval.
📄 Proposed Injection Program (page 30); Injected Water Quantitative Analysis note (page 31): 'Actual source water analysis will be performed once the wells are drilled, completed, and producing.' · 📅 Permit approval: 19 December 2025; source wells status: pending as of application date
Regulatory requirement persisting beyond permit issuance: Murex must obtain and submit actual produced-water analysis from each source well prior to commencing injection. If actual water composition materially differs from representative sample (e.g., presence of RCRA-listed hazardous constituents, radionuclides, or other Class II contaminants), injection program or injection pressure limits may require modification. Non-compliance with water analysis requirement before first injection is a permit violation.

Fresh water analysis performed on two domestic wells (Cattle Well and unnamed well, per pages 8–9) within AOR; both analyzed to confirm no risk of upward migration of injected fluids into SDWA-protected freshwater aquifers. Results indicate adequate vertical separation and no known open faults.
📄 Fresh Water Review (pages 8–9); Fresh Water Quantitative Analysis (pages 10–29) · 📅 Analysis date(s): Not explicitly stated; pre-permit documentation
Establishes baseline hydrogeological conditions that protect fresh water resources. If either domestic well is abandoned or deepened, or if subsurface conditions are altered (e.g., through drilling of new wells within AOR), re-evaluation of freshwater protection may be required. Operator must monitor for any change in AOR well conditions that could affect injection safety.

Wellbore design specifies injection interval of 4,640'–5,040' TVD (Inyan Kara Formation), with overlying Greenhorn Shale confining zone (3,970' TVD, estimated 320 ft thick) and underlying Swift shale confining zone (5,040' TVD, estimated 440 ft thick). Lithological and pressure-gradient analysis tied to fracture pressure calculation (Greenhorn fracture pressure: 3,696 psi ± margin).
📄 Lithological Description (pages 2); Well Fracture Analysis (page 5); Proposed Wellbore Diagram (page 67) · 📅 Fracture analysis: 11 November 2025; lithological prognosis pre-permit
Confining zone integrity is structural to long-term injection safety. Any drilling, coring, or formation testing activity that penetrates confining zones or alters subsurface pressure regimes could affect mechanical integrity. Operator must preserve and monitor confining zone conditions. Post-drilling electric logs (Gamma Ray, CNL/Density, Array Induction, GPIT Directional) will confirm actual formation tops and lithology; deviations from prognosis may require injection parameter adjustment.

Lana Kristy 29-32H (Bakken horizontal well, spud 11 November 2006, TD 19,415') is located in NE quarter of Section 32, well within ¼-mile AOR of Folden SWD. AOR analysis confirms Bakken lateral poses no mechanical integrity risk and 'none' corrective action required.
📄 AOR Calculations (page 3), table entry: 'Lana Kristy 29-32H OG 11/10/2006 19,415 SESW 32-157-95 Yes None, deep Bakken lateral' · 📅 Lana Kristy spud: 11 November 2006; AOR assessment pre-permit (prior to 19 December 2025)
Historical well exists in AOR with documented integrity assessment. If Lana Kristy well is reactivated, recompleted, or abandoned (plugging plan submitted), operator of Folden SWD should verify no interference with injection operations. Long-term AOR monitoring obligation persists for life of injection well.

🔧 Operator Pattern

Murex Petroleum Corporation demonstrates established presence in Midway Field (Williams County) with prior vertical production wells (Lana Kristy 29-32H cited as control well, spud 2006). Application references pending AB-Pad 6-well Bakken program in Section 29 (2/3 mile north of Folden SWD). Disposal facility coordination with third-party operator (Chord/Oasis) indicates mature operational partnership for water-handling infrastructure.
Lana Kristy 29-32H documented in AOR analysis; AB-Pad wells (six pending horizontals in Section 29, T157N, R95W) listed as primary source wells for Folden SWD injection program; Davidson 5795 wells (Chord/Oasis, pending, 2.67 miles southeast) contracted as secondary source for water transfer via buried pipeline. Drilling program references 'Houston Office' coordination and tight-hole security protocol, consistent with mid-cap to large independent operator infrastructure.

Confidence: High
Permit file is complete and coherent. Regulatory approvals (Industrial Commission Order No. 35083 and Oil and Gas Division permit) are explicitly dated (19 December 2025 and inferred 19 December 2025 respectively). Supporting technical documentation (Well Fracture Analysis, AOR calculations, Fresh Water Analysis, UIC Stipulations) is dated, authored, and internally consistent. No material dates are missing; three dates are inferred from context (pre-hearing submissions and drilling program date of 10 October 2025) with high confidence. OCR quality is acceptable; no illegible critical passages. The permit-cycle chain of causation is linear and documented: Order → Fracture Analysis → AOR Verification → Stipulation Enforcement. Forward-operational requirements (actual water analysis, source well completion, injection pressure compliance) are explicit and unambiguous. One limitation: actual source wells remain pending, so full water-quality characterization is deferred; this does not undermine permit justification but creates post-issuance compliance obligation.