IDAPA 20.07.02
This rule applies to oil and gas exploration and development companies, mineral owners, land owners, other agencies and members of the public.
This rule defines and clarifies the procedures for regulating oil and gas exploration and development activities on public and private lands in the state.
This rule implements the following statutes passed by the Idaho Legislature:
Mines and Mining -
Idaho Administrative Procedure Act:
Idaho Department of Lands 300 N. 6th Street, Suite 103 P.O. Box 83720 Boise, Idaho 83720-0050 Phone: (208) 334-0200 Fax: (208) 334-3698 Email: rulemaking@idl.idaho.gov https://www.idl.idaho.gov/
This rule chapter will be reviewed in compliance with Section 67-5292, Idaho Code, and in accordance with the 8-year rule review schedule linked here.
20.07.02 – Rules Governing Conservation of Oil and Natural Gas in the State of Idaho
SUBCHAPTER A – GENERAL PROVISIONS
000. Legal Authority. ... 4
001. Scope. ... 4
002. (Reserved) ... 4
003. Incorporation By Reference. ... 4
004. -- 009. (Reserved) ... 4
010. Definitions. ... 4
011. -- 029. (Reserved) ... 7
030. Notices - General. ... 7
031. Forms. ... 7
032. Organization Reports. ... 7
033. Designation Of Agent. ... 8
034. -- 039. (Reserved) ... 8
040. Public Comment. ... 8
041. -- 099. (Reserved) ... 8
SUBCHAPTER B – EXPLORATION AND DEVELOPMENT
100. Geophysical Operations. ... 8
101. -- 199. (Reserved) ... 12
SUBCHAPTER C – DRILLING, WELL TREATMENT, AND PIT PERMITS
200. Permit To Drill, Deepen, Or Plug Back. ... 12
201. Multiple Zone Completions. ... 13
202. -- 209. (Reserved) ... 14
210. Well Treatments. ... 14
211. Hydraulic Fracturing. ... 17
212. -- 219. (Reserved) ... 18
220. Bonding. ... 18
221. Transfer Of Drilling Permits. ... 19
222. -- 229. (Reserved) ... 19
230. Pit Requirements. ... 19
231. -- 299. (Reserved) ... 23
SUBCHAPTER D – WELL SITES AND DRILLING
300. Identification Of Wells. ... 23
301. Well Site Operations. ... 23
302. Accidents And Fires. ... 23
303. -- 309. (Reserved) ... 24
310. General Drilling Rules. ... 24
311. Loss Of Tool With Radioactive Material. ... 27
312. Chokes. ... 27
313. Use Of Earthen Reservoirs. ... 27
314. Vacuum Pumps Prohibited. ... 28
| 315. Pulling Outside Strings Of Casing. | 28 |
|---|---|
| 316. -- 319. (Reserved) | 28 |
| 320. Mechanical Integrity Testing. | 28 |
| 321. -- 329. (Reserved) | 29 |
| 330. Well Directional Control. | 29 |
| 331. -- 339. (Reserved) | 30 |
| 340. Well Completion/Recompletion Report And Well Report. | 30 |
| 341. Drilling Logs. | 30 |
| 342. -- 399. (Reserved) | 30 |
| SUBCHAPTER E – PRODUCTION | |
| 400. Production Reports. | 30 |
| 401. Measurement Of Oil. | 30 |
| 402. Measurement Of Gas. | 31 |
| 403. Gas-Oil Ratio For Well Classifications. | 31 |
| 404. Gas-Oil Ratio Limitation. | 31 |
| 405. Gas-Oil Ratio Surveys And Reports. | 32 |
| 406. -- 409. (Reserved) | 32 |
| 410. Meters. | 32 |
| 411. Separators. | 32 |
| 412. Producing From Different Pools Through The Same Casing String. | 32 |
| 413. Gas Utilization. | 32 |
| 414. -- 419. (Reserved) | 32 |
| 420. Tank Batteries. | 32 |
| 421. -- 429. (Reserved) | 33 |
| 430. Gas Processing Facilities. | 33 |
| 431. -- 499. (Reserved) | 33 |
| SUBCHAPTER F – WELL ACTIVITY AND RECLAMATION | |
| 500. Active Wells. | 34 |
| 501. Inactive Wells. | 34 |
| 502. Well Plugging. | 34 |
| 503. -- 509. (Reserved) | 36 |
| 510. Surface Reclamation. | 36 |
| 511. -- 999. (Reserved) | 38 |
IN THE STATE OF IDAHO
Title 47, Chapter 3, Idaho Code.; (7-1-25)
01. Scope. These rules apply to the exploration and extraction of all crude oil and natural gas resources in the state of Idaho, not including biogas, manufactured gas, or landfill gas, regardless of ownership. (7-1-25)
02. Other Laws. Owners or operators engaged in the exploration and extraction of crude oil and natural gas resources will comply with all applicable laws and rules of the state of Idaho including, but not limited to rules administered by the Idaho Department of Environmental Quality (IDEQ) and rules administered by the Idaho Department of Water Resources (IDWR). (7-1-25)
The following documents are incorporated by reference into these rules: (3-18-22)
01. American Petroleum Institute (API) Bulletin E3, Wellbore Plugging and Abandonment Practices. 2nd Edition, updated April 2018. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103. (7-1-25)
02. API SPEC 5CT, Specifications for Casing and Tubing. The 11th edition, updated December, 1, 2023. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103. (7-1-25)
03. API SPEC 10a, Specification for Cements and Materials for Well Cementing. The 25th Edition dated February, 2019, updated through Addendum 2, August 2022. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103. (7-1-25)
04. American Society for Testing and Materials (ASTM) D69812(2021), Standard Test Methods for Laboratory Compaction Characteristics of Soil Using Standard Effort (12,400 ft-lbf/ft3 (600 kN-m/m3)). June 25, 2012 revision. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103. (7-1-25)
05. ASTM 1250-19e1, Standard Guide for the Use of the Joint API and ASTM Adjunct for Temperature and Pressure Volume Correction Factors for Generalized Crude Oils, Refined Products, and Lubricating Oils: API MPMS Chapter 11.1 May 15, 2020 revision. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103. (7-1-25)
06. ASTM D155712(2021), Standard Test Methods for Laboratory Compaction Characteristics of Soil Using Modified Effort (56,000 ft-lbf/ft3 (2,700 kN-m/m3)). July 5, 2021 revision. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103. (7-1-25)
07. Environmental Protection Agency (EPA) SW-846 Method 9090A, Compatibility Test for Wastes and Membrane Liners. Revision 1, July 1992. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103 and this website: https://www.epa.gov/hw-sw846/sw-846-test-method-9090a-compatibility-test-wastes-and-membrane-liners. (7-1-25)
08. Occupational Safety and Health Administration (OSHA) Standard 1910.1200 (Hazard Communication). Last revised 2013. Available at the office of the Idaho Department of Lands at 300 North 6th Street, Suite 103 and this website: https://www.osha.gov/laws-regs/regulations/standardnumber/1910/1910.1200. (7-1-25)
In addition to the definitions found in Section 47-310, Idaho Code, the following apply: (7-1-25)
---01. Act. The Idaho Oil and Gas Conservation Act, Title 47, Chapter 3, Idaho Code. (3-18-22)02. Active Well. A permitted well used for production, disposal, or injection that is not idled for more than twenty-four (24) continuous months. (3-18-22)03. Barrel. Forty-two (42) U. S. gallons at sixty (60) Degrees F at atmospheric pressure. (3-18-22)04. Blowout. An unplanned sudden or violent escape of fluids from a well. (3-18-22)05. Blowout Preventer. A casinghead control equipped with special gates or rams that can be closed and sealed around the drill pipe, or that otherwise completely closes the top of the casing. (3-18-22)06. Casinghead. A metal flange attached to the top of the conductor pipe that is the primary interface for the diverter system during drilling out for surface casing. (3-18-22)07. Common Source of Supply. The geographical area or horizon definitely separated from any other such area or horizon, and contains, or from competent evidence appears to contain, a common accumulation of oil or gas or both. Any oil or gas field or part thereof which comprises and includes any area which is underlaid, or which from geological or other scientific data or experiments or from drilling operations or other evidence appears to be underlaid by a common pool or accumulation of oil or gas or both oil and gas. (7-1-25)08. Completion. An oil well is considered completed when the first new oil is produced through wellhead equipment into lease tanks from the ultimate producing interval after the production casing has been run. A gas well is considered completed when the well is capable of producing gas through wellhead equipment from the ultimate producing zone after the production casing has been run. (3-18-22)09. Conductor Pipe. The first and largest diameter string of casing to be installed in a well. This casing extends from land surface to a depth great enough to keep surface waters from entering and loose earth from falling in the hole and to provide anchorage for the diverter system prior to setting surface casing. (3-18-22)10. Cubic Foot of Gas. The volume of gas contained in one (1) cubic foot of space at a standard pressure base and a standard temperature base. The standard pressure base shall be fourteen and seventy-three hundredths (14.73) pounds per square inch absolute and the standard temperature base shall be sixty (60) Degrees F. (3-18-22)11. Development. Any work that actively promotes bringing in production. (3-18-22)12. Drilling Logs. The recorded description of the lithologic sequence encountered in drilling a well, and any electric, gamma ray, geophysical, or other logging done in the hole. (3-18-22)13. Fresh Water, Fresh-water, or Freshwater. All surface waters and those ground waters that are used, or may be used in the future, for drinking water, agriculture, aquaculture, or industrial purposes other than oil and gas development. The possibility of future use is based on hydrogeologic conditions, water quality, future land use activities, and social/economic considerations. (7-1-25)14. Gas-Oil Ratio. The volume of gas produced in standard cubic feet to each barrel of oil or condensate produced concurrently during any stated period. (3-18-22)15. Gas Well. (3-18-22)a. A well that produces primarily natural gas; (3-18-22)b. Any well capable of producing gas in commercial quantities and also producing oil from the same common source of supply but not in commercial quantities; or (3-18-22)c. Any well classed as a gas well by the Commission for any reason. (3-18-22)---
16. Geophysical or Seismic Operations. Any geophysical method performed on the surface of the land utilizing certain instruments operating under the laws of physics respecting vibration or sound to determine conditions below the surface of the earth that may contain oil or gas and is inclusive of, but not limited to, the preliminary line survey, the acquisition of necessary permits, the selection and marking of shot-hole locations, necessary clearing of vegetation, shot-hole drilling, implantation of charge, placement of geophones, detonation and backfill of shotholes, and vibroseis. (7-1-25)
17. Hydraulic Fracturing, Frac'ing, or Fracking. A method of stimulating or increasing the recovery of hydrocarbons by perforating the production casing and injecting fluids or gels into the potential target reservoir at pressures greater than the existing fracture gradient in the target reservoir. (7-1-25)
18. Inactive Well. An unplugged well that has no reported production, disposal, injection, or other permitted activity for a period of greater than twenty-four (24) continuous months, and for which no extension has been granted. (3-18-22)
19. Intermediate Casing. The casing installed within the well to seal intermediate zones above the anticipated bottom hole depth. The casing is generally set in place after the surface casing and before the production casing. (3-18-22)
20. Junk. Debris in a hole that impedes drilling or completion. (3-18-22)
21. Lease. A tract(s) of land that by virtue of an oil and gas lease, fee or mineral ownership, a drilling, pooling or other agreement, a rule, regulation or order of a governmental authority, or otherwise constitutes a single tract or leasehold estate for the purpose of the development or operation thereof for oil or gas or both. (3-18-22)
22. Mechanical Integrity Test (MIT). A test designed to determine if there is a significant leak in the casing, tubing, or packer of a well. (7-1-25)
23. Oil Well. Any well capable of primarily producing oil in paying quantities, but not a gas well. (3-18-22)
24. Pit. Any excavated or constructed depression or reservoir used to contain reserve, drilling, well treatment, produced water, or other fluids at the drill site. This does not include enclosed, mobile, or portable tanks used to contain fluids. (3-18-22)
25. Pollution. Constituents of oil, gas, salt water, or other materials used in oil and gas extraction, occurring in fresh water supplies at levels that exceed the standards in IDAPA 58.01.02, “Water Quality Standards,” and IDAPA 58.01.11, “Ground Water Quality Rules,” as the result of the drilling, casing, treating, operation or plugging of wells. (3-18-22)
26. Produced Water. Water that is produced along with oil or gas. (3-18-22)
27. Production Casing. The casing set across the reservoir interval and within which the primary completion components are installed. (3-18-22)
28. Proppant. Sand or other materials used in hydraulic fracturing to prop open fractures. (3-18-22)
29. Release. Any unauthorized spilling, leaking, emitting, discharging, escaping, leaching, or disposing into soil, ground water, or surface water. (3-18-22)
30. Spud. To start the drilling process by removing rock, dirt, and other sedimentary material with the drill bit by the drilling rig that is capable of drilling the well to the permitted total depth. (7-1-25)
31. Surface Casing. The first casing that is run and cemented in place after the conductor pipe to anchor blow out prevention equipment and seal out freshwater zones. (7-1-25)
32. Surface Water. Rivers, streams, lakes, and springs when flowing in their natural channels. (3-18-22)
33. Systems Approach. The disclosure of chemical information by Chemical Abstracts Service (CAS) name only, without disclosing component percentages or chemical relationships. (7-1-25)
34. Tank. A concrete, metal, or plastic stationary vessel used to contain fluids. (3-18-22)
35. Tank Battery. One (1) or more tanks that are connected to receive crude oil, condensate, or produced waters from a well(s) and that serves as the point of collection and disbursement of oil or gas from a well(s). (3-18-22)
36. Tank Dike. An impermeable man-made structure constructed around a tank to contain leakage from the tank. (3-18-22)
37. Tubing. Pipe used inside the production casing to convey oil or gas from the producing interval to the surface. (3-18-22)
38. Volatile Organic Compound (VOC). Organic chemical compounds whose composition makes it possible for them to evaporate under normal indoor atmospheric conditions of sixty-eight (68) degrees F and an absolute pressure of fourteen point seven (14.7) pounds per square inch (psi) atmospheric. (7-1-25)
39. Well Report. The written record progressively describing the strata, water, oil, or gas encountered in drilling a well with such additional information as to give volumes, pressures, rate of fill-up, water depths, caving strata, casing record, etc., as is usually recorded in normal procedure of drilling; also, it includes electrical radioactivity, or other similar logs run, lithologic description of all cores, and all drillstem tests, including depth-tested, cushion-used, time tool open, flowing and shut-in pressures and recoveries. (7-1-25)
40. Well Site. The areas that are directly disturbed during the drilling and subsequent operation of, or affected by production facilities directly associated with, any oil well, gas well, or injection well, and its associated well pad. (3-18-22)
41. Well Treatment. Actions performed on a well to acidize, fracture, or stimulate the target reservoir. (3-18-22)
42. Wildcat Well. An exploratory well drilled in an area of unknown subsurface conditions. (3-18-22)
011. -- 029. (RESERVED)
01. Written Authorization Required. Any notice, request to do work, or request to change previously approved plans, must be filed with the Department in writing unless otherwise directed, and must be approved before work begins. Such approval may be given orally and thereafter confirmed by the Department in writing. (7-1-25)
02. Emergency Authorization. In case of emergency, or a situation where operations might be unduly delayed, written notice required by these rules and regulations may be given orally or electronically and if approval is obtained, confirmed in writing. (7-1-25)
03. Publication of Legal Notices. Whenever these rules require publication of a legal notice in a newspaper, the notice must be published once a week for two (2) consecutive weeks. (7-1-25)
The Department will adopt such forms of notices, requests, permits, and reports as it may deem advisable or necessary in carrying out the provisions of law and its rules. (3-18-22)
01. Required Content. Before any person engages in any activity covered by the Act and these rules,
that person must file an organization report with the Department. The organization report must include the following information: (7-1-25)
a. The person's name and the type of the business being operated or conducted; (3-18-22) b. The mailing address to which all correspondence from the Department is to be sent; (3-18-22) c. The telephone number(s), facsimile number(s), and email address(es) for which contact by the Department may be made; (7-1-25) d. The names of persons authorized to submit required forms, reports, and other documents to the Department; and (3-18-22) e. If a legal entity, proof the person is authorized to transact business within the state. (3-18-22)
02. Updates. A supplementary report must be filed with the Department within thirty (30) days of any change to facts stated in a previously-filed organization report. (3-18-22)
033. DESIGNATION OF AGENT.
A "Designation of Agent" must be submitted to the Department in a manner and form approved by the Department before commencing operations. A Designation of Agent will be accepted as authority of the agent to fulfill all legal obligations or powers of the owner and to sign any papers or reports required under these rules. All authorized orders or notices given to the designated agent by the Department, when given in the manner hereinafter provided, will be deemed service of such orders or notices upon the owner and the lessee. All changes of address and any termination of the agent's authority must be immediately reported in writing to the Department, and, in the latter case, the designation of a new agent(s) immediately made. If any agent(s) is incapacitated for duty or absent from the address provided, the owner must designate in writing a substitute to serve in their place. In the absence of such owner or of notice of appointment of a substitute, notices may be mailed by the Department to the agent(s) at the address shown on the current Designation of Agent on file in the Department's office. Such notice will be deemed service upon the owner and lessee. (7-1-25)
034. -- 039. (RESERVED)
040. PUBLIC COMMENT.
Applications submitted under Sections 100, 200, 210, 230 and 330 of these rules will be posted on the Department's website for a ten-day (10) written public comment period. The Department will also send an electronic copy of the application to the respective county, and city if applicable, where the proposed operation is located. (7-1-25)
041. -- 099. (RESERVED)
SUBCHAPTER B – EXPLORATION AND DEVELOPMENT
100. GEOPHYSICAL OPERATIONS.
01. Permit Required. Before beginning seismic operations, a representative of the client company and the seismic contractor will meet with Department staff, file an application for a permit to conduct seismic operations, and pay an application fee. No seismic operation may be conducted without a permit. The permit for seismic operations may be revoked or suspended or the application for the permit denied by the Department for failure to comply with these rules, the Act, and orders of the Commission or the Department. The Department may revoke, suspend, or deny the application for a seismic permit without a hearing; provided that the seismic contractor will be given an opportunity for a hearing at the next regularly scheduled Commission meeting. Revocation or suspension of a permit does not excuse the seismic contractor or client company from properly plugging existing seismic holes but does prohibit drilling any more. The application for a permit for seismic operations must include: (7-1-25)
a. The proposed route of the seismic line on a topographic or recent air photo base map at a sufficient scale to show roads, buildings, surface waters, and section, township, and range lines. The map must also show additional area as needed for any alternative routing. The alternative routing must be within at least one-half (1/2)
mile of the proposed route. Reapplication must be made if the final route strays from the proposed route and outside the designated alternative routing areas. (7-1-25)
b. The proposed energy sources for the seismic operation, such as vibroseis, shot holes, surface shot, or others. (7-1-25)
c. The approximate number, depth, and location of seismic holes and the size of the explosive charges. The application must be accompanied by a map with a scale of one inch equaling two (2) miles that shows the depth and location of the shotholes. (7-1-25)
d. The name and permanent address of the client company the Department may contact about the seismic operation. (3-18-22)
e. The name, permanent address, and phone number of the seismic contractor and their local representative whom the Department may contact about the seismic activity. (7-1-25)
f. The name, phone number, and permanent address of the hole plugging contractor, if different from the seismic contractor. (3-18-22)
g. A detailed description of the hole plugging procedures, and a description of the surface reclamation procedures, if such reclamation is needed. (3-18-22)
h. The anticipated starting date of seismic operations. (3-18-22)
i. The anticipated completion date of seismic operations, and the anticipated date of any required reclamation or hole plugging. (3-18-22)
j. A description of the identifying mark that will be on the hat or nonmetallic plug used in the plugging of the seismic hole. (7-1-25)
02. Operating Requirements. All geophysical operations must comply with the following: (7-1-25)
a. Vehicles utilized by the permit holder, its agents, or contractors, shall be clearly identified by signs or markings utilizing letters or numbers, or a combination thereof, a minimum of three (3) inches in height and one-half (1/2) inch wide, indicating the name of the permit holder, its agent, or contractor. (7-1-25)
b. No seismic source generation from vibroseis, shot holes, surface shot, or other method may be conducted within two hundred (200) feet of any residence, water well, oil well, gas well, injection well, or other structure without having first secured the express written authority of the owner thereof and the permit holder shall be responsible for any resulting damages. (7-1-25)
c. Written authority from the owner of a residence, water well, oil well, gas well, injection well or other structure must also be obtained if any explosive charge exceeds the maximum allowable charge within the scaled distance below:
| DISTANCE TO STRUCTURE (Feet)* | MAXIMUM ALLOWABLE CHARGE WEIGHTS (Pounds)* |
|---|---|
| 50 | 0.5 |
| 100 | 2.0 |
| 150 | 4.5 |
| 200 | 8.0 |
| 250 | 12.0 |
| 300 | 18.0 |
| DISTANCE TO STRUCTURE (Feet)* | MAXIMUM ALLOWABLE CHARGE WEIGHTS (Pounds)* |
|---|---|
| 350 | 25.0 |
| * Based upon a charge weight of seventy (70) Foot/Pound1 |
(7-1-25)
d. The maximum allowable charge weight is twenty-five (25) pounds, unless the permit holder requests and secures the Department’s prior written authorization. (7-1-25)
e. All seismic sources placed for detonation shall contain additives to accelerate the biodegradation thereof and be handled with due care in accordance with industry standards. Cap leads for any seismic sources that fail to detonate shall be buried at least three (3) feet deep. (7-1-25)
f. All vegetation cleared to the ground shall be cleared in a competent and workmanlike manner in the exercise of due care. (3-18-22)
g. Unless otherwise consented to by the surface owner in writing, permit holder may not cut down any tree measuring six (6) inches or more in diameter, as measured at a height of three (3) feet from the ground surface, unless there are no reasonable alternatives to the removal of such tree(s) available to permit holder. Permit holder shall compensate surface owner the value of all such trees removed. (7-1-25)
h. All excessive rutting or soil disturbances shall be repaired or restored to the original condition and contour to the extent reasonable, unless otherwise agreed to by the permit holder and the surface owner in writing. (3-18-22)
i. All fences removed shall be replaced, unless otherwise agreed to by the permit holder and the surface owner in writing. (3-18-22)
j. All debris associated with the seismic activity shall be removed and properly disposed. (3-18-22)
03. Bond Required. (3-18-22)
a. Before beginning geophysical operations, the geophysical contractor must file and have approved by the Department a bond of at least ten thousand dollars ($10,000). The Department may increase this bonding requirement for geophysical contractors based on the amount of potential damage from the contemplated operation. The condition of such bond shall comply with the Act, these rules, and orders of the Commission or the Department. The obligation of the bond shall not be discharged until one (1) year from completion of the survey or until the geophysical contractor has complied with the Act, these rules, and orders of the Commission or the Department. (7-1-25)
b. Persons or other entities who engage in plugging seismic holes and are not a regular full-time employee of the seismic company, owner, or operator shall have posted with the Administrator a surety bond in favor of the Department. Said bond shall be on a form prescribed by the Department and in the amount of five thousand dollars ($5,000). The condition of the bond shall comply with the Act, these rules, and orders of the Commission or the Department. (7-1-25)
04. Newspaper Notice. Before beginning geophysical operations, the geophysical contractor shall publish a legal notice in a newspaper of general circulation in the county where the survey will be conducted, stating the nature and approximate time period of the seismic operations. These requirements do not apply to operations conducted within a well or by aerial surveys. (7-1-25)
05. Owner and Occupant Notification. No person may conduct seismic operations without the permit holder having first given notice at least thirty (30) calendar days prior to commencement of field seismic operations, or at the time permission is granted if less than thirty (30) days. (7-1-25)
a. The notice shall be in writing and given either personally or by certified United States mail to the following persons: (3-18-22)
i. Surface owners reflected in the tax records of the counties where the lands are located, at the mailing addresses identified for such surface owners in such records; (3-18-22)
ii. Occupants residing on the lands who are not the surface owners, if it can be reasonably ascertained that there are such occupants; and (3-18-22)
iii. Owners or operators of oil and gas wells within the seismic survey area, as reflected in Department records. (3-18-22)
b. The notice shall contain the following: (3-18-22)
i. Name of the person or entity that is conducting the seismic operations; (3-18-22)
ii. Proposed location of the seismic operations; and (3-18-22)
iii. Approximate date the person or entity proposes to commence seismic operations. (3-18-22)
06. Department Notifications. (3-18-22)
a. The permit holder shall also notify the Department within five (5) business days of the commencement and completion of each seismic operation. (3-18-22)
b. Before beginning geophysical operations other than seismic operations, the geophysical contractor shall file a notice of intention to do so with the Department. Said notice shall describe the geophysical method to be used and be accompanied by a map of a scale of one (1) inch equals two (2) miles showing the location of the project. (3-18-22)
07. Reports and Notices Required. (3-18-22)
a. Activity Report. Upon completion of the seismic activity or at thirty (30) day intervals after the work has commenced, whichever occurs first, the seismic contractor shall file with the Department a report of the completion or progress of the seismic project. The final completion report shall be in affidavit form and include a seven and one-half (7.5) - or fifteen (15) minute United States Geological Survey topographic quadrangle map (at a scale of one (1) inch equals two thousand (2,000) feet or one (1) inch equals four thousand (4,000) feet that shows section, township, and range) and the location of each survey so that the shot holes and other potential impacts can be easily located. The final completion report must also include a statement that all work has been performed in compliance with the application for a permit to perform seismic activity, Section 100 of these rules, and permit provisions. Said maps, applications, and reports will be kept confidential by the Department for a period of one (1) year from the date of receipt, subject to the needs of the Department to use them to enforce these rules, the Act, and the orders of the Commission or the Department. Also, surface owners may be advised of the location of seismic lines or seismic holes on their land and of the exploration method used. (7-1-25)
b. Plugging Notice. Seismic contractors shall give the Department at least twenty-four (24) hours advance notice of shothole plugging operations, provided that notice of plugging operations planned for Sunday or Monday may be given on the previous Friday. (3-18-22)
08. Client-Contractor Responsibility. The client company may be held responsible along with the seismic contractor for the seismic contractor's failure to comply with these rules, the Act, and orders of the Commission or the Department. The hats used in the plugging of seismic holes must be imprinted with the name of the contractor responsible for the plugging of the hole. (7-1-25)
09. Plugging. Unless the seismic contractor can prove to the satisfaction of the Department that another method will provide better protection to ground water and long-term land stability, seismic shothole
operations must be conducted as follows:
(7-1-25)
a. When water is used in conjunction with the drilling of seismic shotholes and artesian flow is not encountered at the surface, seismic holes are to be filled with a high grade bentonite/water slurry mixture. The slurry must have a density that is at least four percent (4%) greater than the density of fresh water and a Marsh funnel viscosity of at least sixty (60) seconds per quart. Density and viscosity are to be measured prior to adding cuttings to the slurry. Cuttings not added to the slurry are to be disposed of per Paragraph 100.09.f. of this rule. Any other suitable plugging material commonly used in the industry may be substituted for the bentonite/water slurry if the physical characteristics of said substitute are comparable to those of the bentonite/water slurry. Between November 1 and May 1, coarse ground bentonite approved by the Department must be used as a plugging material. (7-1-25)
b. The hole will be filled with the slurry from the bottom up to a depth of three (3) feet below ground level. A nonmetallic plug will be set at this depth and the remaining hole will be filled and tamped to the surface with cuttings and native soil. (7-1-25)
c. When drilling with air and nonartesian water is encountered, the hole shall be plugged with the slurry mixture, or coarse ground bentonite, as specified in Paragraph 100.09.a. (7-1-25)
d. When drilling with air only and in completely dry holes, plugging may be accomplished by returning the cuttings to the hole, tamping the returned cuttings to the above-referenced depth of three (3) feet below ground level, and setting the Permaplug topped with more cuttings and soil as per Paragraph 100.09.b. A small mound will be left over the hole for settling allowance. Auger holes twenty (20) feet or less in depth may be plugged in this same manner. (7-1-25)
e. Seismic holes shall be properly plugged and abandoned as soon as practical after the shot has been fired and may not be left unplugged for more than thirty (30) days without written approval of the Department. (7-1-25)
f. Any slurry, drilling fluid, or cuttings deposited on the surface around the seismic hole will be raked or otherwise spread out to at least within one (1) inch of the surface, so that the growth of the natural grasses or foliage will not be impaired. (7-1-25)
g. The requirements of Paragraphs 100.09.a. through 100.09.f. of this rule may be modified by any reasonable written agreement between the seismic company and the surface owner. (3-18-22)
h. If artesian flow (water flowing at the surface) is encountered in the drilling of any seismic hole, cement will be used to seal off the water flow thereby preventing cross-flow, erosion, and/or contamination of freshwater supplies. Said holes shall be cemented immediately. (3-18-22)
i. After completing the plugging of seismic shot holes and spreading the cuttings as required by this rule, the seismic contractor shall record the Global Positioning System (GPS) location of the seismic hole, and the contractor shall provide the location data to the Department. (7-1-25)
10. Forfeiture of Geophysical Exploration Bond. The Department may forfeit the bond submitted under Subsection 100.03 of this rule upon failure of the owner or operator to conduct the seismic survey and complete reclamation in conformance with Section 100 of this rule. The owner or operator will be given an opportunity to address compliance issues prior to the Department acting against the bond. (7-1-25)
101. -- 199. (RESERVED)
01. Permits Required. Prior to the commencement of operations to drill, deepen, or plug back to any source of supply other than the existing producing horizon, an application must be filed with the Department and approval obtained. Any permit issued under Subchapter C of this rule may be revoked or suspended or the application
for permit denied by the Department for failure to comply with these rules, the Act, and orders of the Commission or the Department. (7-1-25)
02. Fees. An application fee must accompany each application for permit to drill, deepen, or plug back. No service fee is required for a permit to deepen or plug back if completed within one (1) year from issuance of permit to drill a well. (7-1-25)
03. Time Required to Commence Operations; Term of Permit. Permits to drill, deepen, or plug back will expire one (1) year after being issued by the Department, unless the work for which the permit was issued has been started. Prior to the expiration of the permit, the owner or operator may apply to the Department for a one-time, six-month extension if work has not started. If conditions have not changed and no changes to the permit are requested, the extension may be approved by the Department. If a permit expires due to the failure to commence operations, then reapplication is required prior to commencing operations. (7-1-25)
04. Application. The Application for Permit to Drill shall include a Department approved form and the following: (3-18-22)
a. An accurate plat showing the location of the proposed well with reference to the nearest lines of an established public survey. (3-18-22)
b. The location of the nearest structure with a water supply, or the nearest water well as shown on the IDWR registry of water rights or well log database. (3-18-22)
c. Information on the type of tools to be used and the proposed logging program. (3-18-22)
d. Proposed total depth of the well, estimated depth to the top of the important geologic markers, and the estimated depth to the top of the target formations. (7-1-25)
e. The proposed casing program, including size and weight thereof, the depth at which each casing type is to be set. (3-18-22)
f. The type and amount of cement to be used, and the intervals cemented. (3-18-22)
g. Information on the drilling plan. (3-18-22)
h. Best management practices to be used for erosion and sediment control. (3-18-22)
i. Plan for interim reclamation of the drill site after the well is completed, and a plan for final reclamation of the drill site following plugging and abandonment of the well. These plans must contain the information needed to implement reclamation as described in Subsection 310.16 and Section 510 of these rules. (3-18-22)
j. Applications that include the following actions must also provide the information from the respective Section of these rules: (3-18-22)
i. Well treatments require the submittal of the information in Section 210. (3-18-22)
ii. Pit construction and use requires the submittal of the information in Section 230. (3-18-22)
iii. Directional or horizontal drilling requires the submittal of the information in Section 330. (3-18-22)
k. Any other information which may be required by the Department based on site-specific reasons. (7-1-25)
01. Requirements of the Owner or Operator; Request for Approval. A multiple zone completion may be approved by the Department upon application by the owner or operator and payment of an application fee. The application must include an exhibit showing the location of wells on applicant’s lease and all offset wells on leases, and shall set forth all material facts involved, and the manner and method of completion proposed, including a diagrammatic sketch of the mechanical installation of the proposed well. The applicant must mail notice of the filing of such application to each offset operator. The notice must contain a full description of the proposed completion for which approval is requested. Proof of mailing notice must be made by an affidavit attached to the application showing names and addresses of those to whom notice was mailed. (7-1-25)
02. Conditions for Approval; Cause for Hearing. If the Department agrees with the application and no offset operator files a written objection to the application with the Department within ten (10) days of the date of the offset operator’s receipt of application, the application shall be approved as an amendment to the drilling permit. If any offset operator files said objection, or if the Department is not in agreement with the application, the matter shall be immediately set for hearing and Notice of Hearing duly given by the Department. (7-1-25)
03. Zone Effectiveness; Requirement for Production Testing. The Department may require such tests as necessary to determine the effectiveness of the segregation of the different productive zones. (3-18-22)
04. Commingling Production. The Department may require that oil or gas from multiple zones be produced through different sets of tubing, if needed to protect correlative rights or to prevent waste. (3-18-22)
202. -- 209. (RESERVED)
01. Application Required. An Application for Permit to Drill required by Section 200 must include any plans for well treatment if they are known before the well is drilled. If well treatments are not covered in the original drilling permit, then an application to amend the permit must be made to the Department with an application fee. Approval by the Department is required before the well treatments are implemented. Actions to clean the casing or perforations not in excess of pressures sufficient to overcome the fracture gradient in the surrounding formation are not considered to be well treatments, but operators must notify the Department when such actions occur. Applications for well treatments must include the permit number, well name, well location, as-built description if drilling has been completed, and the following: (7-1-25)
i. Information specific to hydraulic fracturing as described in Section 211 of these rules; (3-18-22)
j. Summary identifying all water bearing zones from the surface down to the bottom of the well; (3-18-22)
05. Reporting Requirements. A report on the well treatment must be submitted within thirty (30) days of the treatment. The report shall present a detailed account of the work done and the manner in which such work was performed, including: (3-18-22)
c. Percentages by volume and total volumes of base treatment fluid, individual additives, and proppant(s). This requirement can be met by the submittal of well completion field tickets if they contain this information. (3-18-22)
d. Documentation demonstrating the chemicals used in the well treatment have been reported to the website https://fracfocus.org, its successor website, or another publicly accessible database approved by the Department. The chemical information must be reported in a systems approach. (7-1-25)
g. The amounts, handling, and if necessary, disposal at an identified appropriate disposal facility, or reuse of the well stimulation fluid load recovered during flow back, swabbing, recovery, or all from production facility vessels. Reporting of recovered fluids must be included with other monthly production reports required by the Department. Storage of such fluid must be protective of groundwater by using either tanks or authorized lined pits as described in Section 230 of these rules. (7-1-25)
h. Any other information related to operations which alter the performance or characteristics of the well. (3-18-22)
06. Freshwater Protections for Well Treatments. (7-1-25)
a. The Department will not authorize pits, lagoons, ponds, or other methods of subsurface storage for treatment fluids within IDEQ recognized source water assessment or protection areas for public drinking water systems. Owners or operators must store and transport treatment fluids using above ground storage facilities and tanker trucks for well treatments in these locations. (3-18-22)
b. The Department will not authorize well treatments to create fractures within five hundred (500) vertical feet above or below freshwater aquifers. (7-1-25)
c. The owner or operator must complete freshwater monitoring at the owner's or operator's cost before and after a well treatment unless the Department, in consultation with IDEQ, determines that the proposed treatment does not pose a threat of pollution to fresh waters. The Department will review and approve all monitoring proposals with IDEQ. The monitoring will be done using representative existing water wells or surface waters within one-quarter (1/4) horizontal mile of the treated well. For wells that deviate from the vertical, sampling may be required within one-quarter (1/4) horizontal mile of the wellbore's projected location on the surface. If no water wells or surface waters are present in this area, the sampling area may be enlarged as needed with approval by the Department. If the Department determines that existing water wells are not representative of the ground waters that could be impacted, then the Department may require the owner or operator to install one (1) or more ground water monitoring wells at the owner's or operator's cost. The owner or operator must obtain consent from appropriate property owners to gain access prior to any sampling or well construction. When monitoring is required by the Department, the operator will prepare a monitoring plan that includes the following: (7-1-25)
ii. Construction details of any sampled or constructed wells including total well depth, depth of screened interval(s), screen size, and drilling log. For existing wells, the operator must make every reasonable attempt to locate this information; (3-18-22)
iii. When possible, data from the existing wells collected within the last five (5) years and analyzed in a state or EPA certified drinking water lab; (3-18-22)
iv. List of proposed analytes, testing methods, and their detection limits; (3-18-22)
v. Additional tests such as stable isotopic analysis; and (3-18-22)
vi. Pre-treatment sampling and analysis when no relevant data exists, and a schedule for post-treatment sampling and analysis. (3-18-22)
d. The owner or operator will provide the Department with copies of any analysis or reports within thirty (30) days of samples being taken. All samples must be analyzed in a state or EPA certified drinking water lab. (3-18-22)
e. Pollution of freshwater supplies due to a well treatment is a violation of these rules and Title 47, Chapter 3, Idaho Code. (7-1-25)
01. Application Requirements. In addition to the information required by Subsection 210.01 of this rule, the owner or operator shall provide the following application information regarding hydraulic fracturing: (3-18-22)
a. The geological names and descriptions of the formation into which well stimulation fluids are to be injected; (3-18-22)
b. Detailed information on the base stimulation fluid source. For each stage of the well stimulation program, provide the chemical additives and proppants and concentrations or rates proposed to be mixed and injected, including: (3-18-22)
i. Stimulation fluid identified by additive type (such as but not limited to acid, biocide, breaker, brine, corrosion inhibitor, crosslinker, demulsifier, friction reducer, gel, iron control, oxygen scavenger, pH adjusting agent, proppant, scale inhibitor, surfactant); (3-18-22)
ii. The chemical compound name and CAS number as found on the previously submitted SDS (such as the additive biocide is glutaraldehyde, or the additive breaker is ammonium persulfate, or the proppant is silica or quartz sand, and so on for each additive used); (7-1-25)
iii. The proposed rate or concentration for each additive and the total volume of each (such as gel as pounds per thousand gallons, or biocide at gallons per thousand gallons, or proppant at pounds per gallon, or expressed as percent by weight or percent by volume, or parts per million, or parts per billion); and (7-1-25)
iv. The formulary disclosure of the chemical compounds used in the well stimulation(s) for the purpose of protecting public health and safety. (3-18-22)
c. A detailed description of the proposed well stimulation design that shall include: (3-18-22)
i. The anticipated surface treating pressure range; (3-18-22)
ii. The maximum injection treating pressure, which shall be within accepted safety limits. Accepted safety limits are generally eighty percent (80%) of the maximum pressure rating of the pressurized system; (3-18-22)
iii. The estimated or calculated fracture height in both the horizontal and vertical directions. (3-18-22)
02. VOCs and Petroleum Distillates. The injection of VOCs, such as benzene, toluene, ethyl benzene, and xylene, also known as BTEX compounds, or any petroleum distillates into ground water in excess of applicable
ground water quality standards is prohibited. VOCs or petroleum distillates may be appropriate as additives, but they are not appropriate for use as the base fluids. The proposed use of VOCs or any petroleum distillates for well stimulation into hydrocarbon bearing zones may be authorized with prior approval of the Administrator. Produced water, which may contain small amounts of naturally occurring VOCs or petroleum distillates, may be used as well stimulation fluid in hydrocarbon bearing zones. (7-1-25)
03. Well Integrity. Prior to the well stimulation, the owner or operator will perform a suitable MIT of the casing, or of the casing-tubing annulus or other MIT methods and submit an affidavit to the Department certifying that the well was tested in anticipation of proposed treatment pressures. The owner or operator will notify the Department of this test twelve (12) to twenty-four (24) hours in advance. (7-1-25)
04. Pressure Monitoring. During the well stimulation operation, the owner or operator shall monitor and record the annulus pressure at the casinghead. If intermediate casing has been set on the well being stimulated, the pressure in the annulus between the Intermediate casing and the production casing shall also be monitored and recorded. If the annulus pressure increases by more than five hundred (500) psi gauge as compared to the pressure immediately preceding the stimulation, the owner or operator shall verbally notify the Department as soon as practicable but no later than twenty-four (24) hours following the incident. (7-1-25)
05. Post-Treatment Report. In addition to the information required by Subsection 210.05 of this rule, the owner or operator shall provide the following post-treatment reporting: (7-1-25)
01. Individual Bond. The Department shall, except as hereinafter provided, require from the owner or operator a good and sufficient bond in the sum of not less than ten thousand dollars ($10,000) plus one dollar ($1) for each foot of planned well length in favor of the Department. The bond shall be conditioned upon the performance of the owner's or operator's duty to comply with the requirements of the Act and the rules of the Commission, with respect to the drilling, maintaining, operating, and plugging of each well drilled for oil and gas and the reclamation of surface disturbance associated with these activities. Said bond shall remain in force and effect until the plugging of said well is approved by the Department and the well site is reclaimed as described in Section 510 of these rules, or the bond is released by the Department. (3-18-22)
02. Blanket Bond. In lieu of the bond in Subsection 220.01 of this rule, any owner or operator may file
with the Department a good and sufficient blanket bond covering all active wells drilled or to be drilled in the state of Idaho. The amount of the blanket bond will be as follows according to the number of active wells covered by the bond: (3-18-22)
a. Up to ten (10) wells, fifty thousand dollars ($50,000); (3-18-22) b. Eleven (11) to thirty (30) wells, one hundred thousand dollars ($100,000); or (3-18-22) c. More than thirty (30) wells, one hundred fifty thousand dollars ($150,000). (3-18-22)
03. Inactive Well Bond. An owner or operator must provide the Department with a bond of at least ten thousand dollars ($10,000) plus eight dollars ($8) for each foot of planned well length for each inactive well that is conditioned upon the performance of the duty to comply with the requirements of the Act, these rules, and orders issued by the Commission or the Department; with respect to the drilling, maintaining, operating, and plugging of each well drilled for oil and gas. Said bond shall remain in force and effect until the plugging of said well is approved by the Department, or the bond is released by the Department. Inactive wells may not be covered by a blanket bond as provided in Subsection 220.02 of this rule. (7-1-25)
04. Additional Bonding. The Department may impose additional bonding on an owner or operator given sufficient reason, such as non-compliance, unusual conditions, horizontal drilling, or other circumstances that suggest a particular well or group of wells has potential risk or liability in excess of that normally expected. The owner or operator may request a hearing to appeal either the decision to impose an additional bond or the proposed amount of the bond. (3-18-22)
05. Authorized Bonds. The bond(s) referred to in Section 220 must be by a corporate surety authorized to do business in the state of Idaho or in cash. If cash is used to satisfy the bonding requirements in these rules, interest on the cash will be allocated to the General Fund. (7-1-25)
221. TRANSFER OF DRILLING PERMITS.
No person with a permit may transfer the permit to any other location or to any other person unless the following requirements are met: (7-1-25)
01. Prior to Drilling Well. If, prior to the drilling of a well, the person to whom the permit was originally issued desires to change the location, he shall submit a letter so stating and another application properly filled out showing the new location. Drilling may not start until the transfer has been approved and the new permit posted at the new location. (7-1-25)
02. During Drilling or After Completion. If, while a well is being drilled or after it has been completed, the person to whom the permit was originally issued disposes of his interest in the well, he shall submit a written statement to the Department setting forth the facts and requesting that the permit be transferred to the person who has acquired the well. (3-18-22)
03. Terms for Acceptance of Transfer. Before the transfer of a drilling permit shall be recognized, the person who has acquired the well must submit a written statement setting forth that he has acquired such well and assumes full responsibility for its operation and abandonment in conformity with the Act, these rules, and orders issued by the Commission or the Department. If bond is required to guarantee compliance with these rules and regulations of the Commission, the person acquiring such well shall furnish bond. (7-1-25)
222. -- 229. (RESERVED)
230. PIT REQUIREMENTS.
01. Plans Required. If pits are proposed to be constructed in connection with another permit application required by these rules, then the owner or operator must include plans for pit construction in the application. If a pit is needed after the other permits have been approved, then an application to amend the permit must be made to the Department with an application fee. Approval by the Department is required prior to the pit being constructed unless the pit is necessary for an emergency action. Pit applications must include the permit number, well name, well location, as-built description if drilling has been completed, proposed pit location, and plans
for pit construction, operation, and reclamation. (3-18-22)
a. Pits must be located where they are structurally sound and the liner systems can be adequately protected against factors such as wildfires, floods, landslides, surface and ground water systems, equipment operation, and public access. (7-1-25)
b. Pits located in a one-hundred-year floodplain must be in conformance with any applicable floodplain ordinances pertaining to activities within the one-hundred-year floodplain. (7-1-25)
c. Pits may not be located within IDEQ recognized source water assessment or protection areas for public drinking water systems. (7-1-25)
03. Site Preparation. All sites must be properly prepared prior to pit construction. Vegetation, roots, brush, large woody debris and other deleterious materials, topsoil, historic foundations and plumbing, or other materials that may adversely affect appropriate construction, must be removed from the footprint of the pit unless approved by the Department. (3-18-22)
a. Pits that have constructed berms ten (10) or more feet in height or hold fifty (50) acre-feet or more of fluid must also comply with the dam safety requirements of IDAPA 37.03.06, “Safety of Dams Rules.” (3-18-22)
b. Pits must be designed to hold the maximum volume of fluids being used for drilling or well treatment and the volume of water associated with a one hundred-year, twenty-four-hour precipitation event. (3-18-22)
c. Snowmelt events shall be considered in determining the containment capacity. (3-18-22)
d. Pits that are left over winter must be able to contain one hundred twenty-five percent (125%) of the average annual precipitation that falls from October through May. (3-18-22)
e. Pits must be designed to maintain a minimum two (2) foot freeboard at all times. Contingency plans for managing excess fluids shall be described in the application. At no time may fluids in a pit be allowed to escape from the impoundment. (7-1-25)
05. Minimum Plans and Specifications for Reserve, Well Treatment, and Other Short-Term Pits. Pits used for one (1) year or less, not including extensions, are short-term pits. Construction plans and specifications for short term pits must include the requirements under Subsections 230.02 through 230.04 of this rule and the following: (7-1-25)
a. A prepared subbase, which shall be free of plus three (3) inch rocks, roots, brush, trash, debris or other deleterious materials, and compacted to ninety-five percent (95%) of Standard Proctor Test ASTM D698-07e1 or ninety-five percent (95%) of Modified Proctor Test ASTM D1557-09; (3-18-22)
b. Slopes of two (2) feet horizontal to one (1) foot vertical (2H:1V) or flatter for all interior and exterior pit walls. The top of a bermed pit wall must be a minimum of two (2) feet wide; (3-18-22)
c. A primary liner system consisting of a synthetic liner of at least twenty (20) millimeters thick constructed according to manufacturers’ standards with at least four (4) inches of welded seam overlap and complete coverage on the floor and inside walls of the pit. Seams must run parallel to the line of maximum slope so they do not traverse across the slope. The liner edges must be anchored in a compacted earth filled trench at least eighteen (18) inches deep. The liner must be protected against cracking, sun damage, ice, frost penetration or heaving, wildlife and wildfires, and damage that may be caused by personnel or equipment operating in or around these facilities. Liner compatibility must comply with EPA SW-846 method 9090A. Alternative liner systems with similar standards may be proposed by the owner or operator and approved at the Department’s discretion; (7-1-25)
d. Minimum factors of safety, and the logic behind their selection, for the stability of the earthworks and the pit lining system; (7-1-25)
e. Site-specific methods for excluding people, terrestrial animals, and avian wildlife from the pit; (7-1-25)
f. Segregation and stockpiling of topsoil in a manner that will support reestablishment of the pre-disturbance land use after pit closure; and (3-18-22)
g. A closure plan including the following: (3-18-22)
i. Testing of residual fluids and any accumulated solids, if anything other than water-based drilling fluid was placed in the pit; (7-1-25)
ii. Plans for removal and disposal of residual fluids and accumulated solids, with the liner material, at an appropriate facility; (3-18-22)
iii. Regrading plan, replacement of topsoil, and erosion control measures; and (3-18-22)
iv. Reseeding and Revegetation. (3-18-22)
06. Minimum Plans and Specifications for Long Term Pits. Pits used for more than one (1) year, not including extensions, are long term pits. Construction plans and specifications for long term pits must include the requirements under Subsections 230.02 through 230.05 of this rule and the following: (3-18-22)
a. A quality control/quality assurance construction and installation plan; (3-18-22)
b. Type of fluids to be contained in the pit; (3-18-22)
c. Secondary containment synthetic liners, which must have a minimum thickness of sixty (60) millimeters consisting of High Density Polyethylene (HDPE) and a maximum coefficient of permeability of $10-9$ cm/sec, or comparable liners approved by the Department; (7-1-25)
d. Leak detection and collection systems. The plans and specifications shall: (3-18-22)
i. Provide a material between primary and secondary containment synthetic liners to collect, transport, and remove all fluids that pass through the primary containment synthetic liner at such a rate as to prevent hydraulic head from developing on the secondary containment synthetic liner to the level at which it may be reasonably expected to result in discharges through the secondary containment synthetic liner; (7-1-25)
ii. Provide routines and schedules for evaluating the efficiency and effectiveness of fluid removal from the layer placed between primary and secondary containment synthetic liners. The properly working system shall continually relieve head pressures on the secondary containment synthetic liner; (7-1-25)
iii. Provide specific triggers for maintenance routines, which will be initiated in response to inadequate performance of primary or secondary containment synthetic liners; and (7-1-25)
iv. Specify operation and maintenance procedures, which will be initiated in response to inadequate performance of primary and secondary containment or leak detection and collection systems. (7-1-25)
e. All piping, including that contained in the leak detection and collection system, shall have a minimum wall thickness of polyvinyl chloride (PVC) Schedule 80 and be designed to: (7-1-25)
i. Withstand chemical attack from oil field waste or leachate; (3-18-22)
ii. Withstand structural loading from stresses and disturbances from cover materials or equipment
operation; and (3-18-22)
iii. Facilitate clean-out and maintenance. (3-18-22)
f. Protections for the liner from excessive hydrostatic force or mechanical damage at the point of discharge into, or suction from, the pit. External discharge or suction lines may not penetrate the liner; (7-1-25)
g. Plans for erosion control during and immediately following construction; and (3-18-22)
h. Operating and maintenance plans. (3-18-22)
07. Time Limits for Short-Term Pits. Reserve, well treatment, and other short-term pits must be closed out and reclaimed within one (1) year of being constructed. The owner or operator may request a one-time extension for up to six (6) months. The Department may grant the request if the owner or operator gives sufficient cause and presents a plan for ensuring that the pit is adequately monitored and maintained. (7-1-25)
a. Fluids may be left in a pit for up to six (6) months after the associated well activities are conducted. The owner or operator may request a one-time extension for up to one (1) year. The Department may grant the request if the owner or operator gives sufficient cause and presents a plan for keeping the fluids in a usable state. (3-18-22)
b. Notwithstanding the above time limits, the owner or operator may request additional time based upon conditions wholly outside of the owner’s or operator’s control including, but not limited to, governmental lease requirements and delays related to difficult drilling conditions. The Department may impose additional construction or monitoring requirements prior to granting additional time. (3-18-22)
08. Emergency Pits. Pits constructed during an emergency situation may be approved by an after-the-fact application submitted to the Department. The requirements in Subsections 230.02 through 230.05 of this rule shall apply, and the pit must be closed out and reclaimed within six (6) months of being constructed. The Department must be notified within twenty-four (24) hours of an emergency situation requiring an emergency pit. (3-18-22)
09. Operating Requirements. (3-18-22)
a. Waste oil, hydraulic fluid, transmission fluids, trash, or any other miscellaneous waste products must not be disposed of in a pit. (7-1-25)
b. If a pit liner’s integrity is compromised, or if any penetration of the liner occurs above the liquid’s surface, then the owner or operator shall notify the appropriate Department area office within forty-eight (48) hours of the discovery and repair the damage or replace the liner. (3-18-22)
c. If a pit or closed-loop system develops a leak, or if any penetration of the pit liner occurs below the liquid’s surface, then the owner or operator shall remove all liquid above the damage or leak line within forty-eight (48) hours, notify the appropriate Department area office within forty-eight (48) hours of the discovery, and repair the damage or replace the pit liner. (3-18-22)
d. The owner or operator shall install, or maintain on site, an oil absorbent boom or other device to contain and remove oil from a pit’s surface. Visible oil must be removed from short-term pits immediately following the cessation of activity for which the pit was constructed. Visible oil must be removed from long-term pits as soon as it is discovered. (7-1-25)
10. Closure of Pits. (3-18-22)
a. The owner or operator shall remove all liquids from the pit before closure and dispose of them at an appropriate facility or reuse them at a different location. If the nature of the fluids has substantially altered during their use, then the fluids must be sampled and tested to determine which disposal facility can accept them. (7-1-25)
b. Any solids that have accumulated in the bottom of the pit will be tested to determine which disposal facility can accept the material. The solid material and liner will then be removed and disposed of at an appropriate
facility. (7-1-25)
c. The owner or operator must notify the Department at least forty-eight (48) hours prior to removal of the pit liner so an inspection may be conducted. (3-18-22)
d. The pit foundation will be inspected for signs of leakage. If evidence of leakage is observed, the owner or operator must contact the Department and IDEQ within twenty-four (24) hours and report the type of fluids released and the estimated extent of release. The owner or operator must then remediate the site in conformance with the applicable standards administered by IDEQ in IDAPA 58.01.02, “Water Quality Standards,” Sections 850 through 852. (7-1-25)
e. After addressing any pit leakage concerns, the owner or operator shall undertake surface reclamation activities as provided for in Section 510 of these rules. (7-1-25)
11. Improper Impoundment. The Department may order the owner or operator of a pit that does not properly impound fluids under this rule to dispose of such fluids in conformance with IDAPA 58.01.16, “Wastewater Rules,” and other applicable rules. (7-1-25)
231. -- 299. (RESERVED)
01. Signs; Lease Access Roads. The owner or operator of a producing lease must place a sign where the principal lease road enters the lease. Such sign will identify the name of the lease, the owner or operator thereof, and the section, township, and range. (7-1-25)
02. Signs; Well Sites. Prior to spud activity, a legible sign must be placed near the well to identify the operator, permit number, well name, and emergency telephone number. If a multiple completion, each wellhead connection shall be identified. (7-1-25)
The owner or operator must conduct all operations and maintain the well site at all times in a safe and workmanlike manner. Best management practices and good housekeeping practices must be used at well sites. (3-18-22)
01. Fencing. Within sixty (60) days after completion of the well, the owner or operator must install a fence around the well site to maintain safe working conditions, secure the well site, and prevent access by wildlife and livestock. The fence design must be acceptable to both the landowner and owner or operator. (3-18-22)
02. Storage. All chemicals must be stored and maintained in accordance with applicable SDS requirements. Materials related to operations must be palletized where applicable. Vehicles and materials not in use must be removed from the well site. (7-1-25)
03. Vegetation. All well sites must be kept free of excessive vegetation. (3-18-22)
04. Trash. All trash, debris, and scrap metal must be removed from the well site. Before removal, any trash or debris that might constitute a fire hazard shall be removed to a distance of at least one hundred (100) feet from the well location, tanks, and separator. (7-1-25)
The owner or operator must take all reasonable precautions to prevent accidents and fires, including preparation of an emergency response plan. Such plan must be available at the well for use or inspection. Coordination with local emergency responders and the Idaho Bureau of Homeland Security is recommended prior to rig set up. The following actions must be taken in event of a release, industrial accident, or fire of major consequence: (7-1-25)
01. Provide Information to Emergency Response. Emergency workers will be given information on
all fluids or chemicals involved in a spill or accident as needed according to OSHA Standard 1910.1200 (Hazard Communication). All information required by a health care professional, a doctor, or a nurse shall be supplied, immediately upon request, by the owner or operator, or their contractors, directly to the requesting health care professional, doctor, or nurse, including the percent by volume of the chemical constituents (and associated CAS numbers) in the fluids and the additives; (7-1-25)
02. Initiate Spill Response and Corrective Actions. Owner or operator must comply with the requirements of IDAPA 58.01.02, “Water Quality Standards,” Sections 850 through 852; and (3-18-22)
03. Notify the Department. Notify the Department within twenty-four (24) hours and submit a full report thereon within fifteen (15) days. (3-18-22)
303. -- 309. (RESERVED)
01. General Design Requirements for Casing and Cementing. Casing and cementing programs adopted for wells must be planned to protect any potential oil- or gas-bearing horizons penetrated during drilling from infiltration of injurious waters from other sources, and to prevent the migration of oil or gas from one horizon to another. Owners and operators shall follow the standards for casing and tubing in API SPEC 5CT and the standards for cementing in API SPEC 10A. (7-1-25)
02. Wildcat and High-Pressure Conditions. When drilling wildcat territory or in any field where high pressures are likely to exist, the owner or operator shall take all necessary precautions to keep the well under control at all times and use proper high-pressure fittings and equipment at the time the well is started. Under such conditions all strings of casings must be securely anchored. (7-1-25)
03. High Temperature Conditions. Due to high geothermal gradients in Idaho, the temperature of the return drilling mud shall be monitored daily during the drilling of the surface casing hole and all deeper holes. The owner or operator must use cements appropriate for the temperatures expected or encountered. (3-18-22)
04. Conductor Pipe or Casing Requirements. A minimum of forty (40) feet of conductor pipe shall be installed. If geologic conditions are such that forty (40) feet is not feasible, the owner or operator may request a variance from the Department. The annular space must be cemented solid to the surface. A twenty-four (24) hour cure period for the grout must be allowed prior to drilling out the shoe unless sufficient additives, as determined by the Department, are used to obtain early strength. (7-1-25)
05. Surface Casing Requirements. (3-18-22)
a. The owner or operator will notify the Department in writing seventy-two (72) hours in advance of planned spud activity for surface casing. The Department will post the spud activity notice on its website and send an electronic copy to the county where the well is located. (7-1-25)
b. Surface casing must be set at a minimum depth equal to ten percent (10%) of the proposed total well depth. In areas where pressures and formations are unknown, a minimum of two hundred (200) feet of surface casing shall be set. (7-1-25)
c. Surface casing shall provide for control of formation fluids, protection of fresh water, and for adequate anchorage of blow out prevention equipment. The casing must be seated through a sufficient series of low permeability, competent lithologic units such as claystone, siltstone, basalt, etc., to ensure a solid anchor for blow out prevention equipment and to protect usable ground water from contamination. Additional surface casing may be required if the first string has not been cemented through a sufficient series of low permeability, competent lithologic units, or rapidly increasing thermal gradients or formation pressures are encountered. (7-1-25)
d. All surface casing shall be cemented solid to the surface by pump and plug, displacement, or other approved method. When surface samples are cured, additional drilling activities may commence. (3-18-22)
e. The Department must be notified in writing twenty-four (24) hours before planned cementing activity for surface casing. The Department will witness and document all surface casing cementing activities. (7-1-25)
06. Requirements for BOP Equipment. Unless altered, modified, or changed for a particular pool(s) upon hearing before the Commission, blowout preventer (BOP) and related equipment shall be installed and maintained during the drilling of all wells as follows: (7-1-25)
a. BOP equipment installed on wells in which formation pressures to be encountered are abnormal or unknown shall consist of a double-gate, hydraulically operated preventer with pipe and blind rams or two (2) single-ram-type preventers; one (1) equipped with pipe rams, the other with blind rams and an annular type preventer. In addition, upper and lower kelly cocks, pit level indicators with alarms, flow sensors, or both, with alarms, and surface facilities to handle pressure kicks shall be installed before drilling any formation with known abnormal pressure. (7-1-25)
i. Accumulators shall maintain a pressure capacity reserve at all times to provide for operation of the hydraulic preventers and valves with no outside source. (3-18-22)
ii. In all other drilling operations, BOP equipment shall consist of at least one (1) double-gate preventer with pipe and blind rams or two (2) single-ram-type preventers, one (1) equipped with pipe rams, the other with blind rams, and sufficient valving to permit fluid circulation at the surface. (3-18-22)
b. All BOP equipment, choke lines, and manifolds shall be installed above ground level. Casing heads and optional spools may be installed below ground level provided they are visible and accessible. (3-18-22)
c. BOP equipment and related casing heads and spools shall have a vertical bore no smaller than the inside diameter of the casing to which they are attached. (3-18-22)
d. The working pressure rating of all BOP and related equipment shall equal or exceed the maximum anticipated pressure to be contained at the surface. (3-18-22)
e. All ram-type BOP and related equipment, including casing, shall be tested to the full working pressure rating of said equipment upon installation, provided that components need not be tested to levels higher than the lowest working pressure rated component. Annular type BOP and related equipment must be tested in conformance with the manufacturer’s published recommendations. If, for any reason, a pressure seal in the assembly is disassembled, a test to a full working pressure rating of that seal shall be conducted before the resumption of any drilling operation. In addition to the initial pressure tests, ram-type BOP shall be checked for physical operation at least once per week and all components, with exception of the annular-type BOP, tested at least once every twenty-one (21) days to at least fifty percent (50%) of the rated pressure of the BOP equipment or to the maximum anticipated pressure to be contained at the surface, whichever is greater. (7-1-25)
f. The owner, operator, or contractor must submit an affidavit covering the initial pressure tests after installation. The Department must be advised at least twenty-four (24) hours in advance of all tests. The Department may inspect and witness all BOP operations and testing. (7-1-25)
g. A schematic diagram of the BOP and wellhead assembly shall be submitted to the Department upon application for a permit to drill. The schematic diagram should indicate the minimum size and pressure rating of all components of the wellhead and BOP assembly. (7-1-25)
h. Studs on all wellhead and BOP flanges shall be checked for tightness each week. Hand wheels for locking screws shall be installed and operational, and the entire BOP and wellhead assembly shall be kept clean of mud and ice. (7-1-25)
i. A drillstem safety valve shall be available on the rig floor at all times with correct thread for the pipe in use. (3-18-22)
j. A drillstem float valve shall be installed in bit sub or as close to bit as reasonably possible.
(3-18-22)07. Intermediate Casing. (3-18-22)a. Intermediate casing, if installed, shall be cemented solidly to the surface or to the top of the casing. (3-18-22)b. Intermediate casing not run to surface will be lapped into at least one hundred (100) feet of the surface casing, or at least one hundred (100) feet of the next larger casing to provide overlap and secure a seal. (3-18-22)c. Such casing shall be cemented and pressure tested before cement plugs are drilled. (3-18-22)d. The Department must be notified in writing twenty-four (24) hours in advance of planned cementing activity for intermediate casing. The Department may witness and document all intermediate casing cementing activities. (3-18-22)08. Production Casing; Cementing and Testing Requirements. (3-18-22)a. Production casing, if needed, shall be cemented and pressure tested before cement plugs are drilled. (7-1-25)b. The Department must be notified in writing twenty-four (24) hours in advance of planned cementing activity for production casing. The Department may witness and document all production casing cementing activities. (3-18-22)c. When not run to the surface, production casing will be lapped into and cemented from the bottom of the hole up into at least one hundred (100) feet of the next larger casing to provide overlap and secure a seal. (7-1-25)d. If the bottom plug will be drilled out, the open hole interval must be completed to protect any potential oil-bearing or gas-bearing horizons penetrated during drilling from infiltration of injurious waters from other sources, and to prevent the migration of oil or gas from one horizon to another. (3-18-22)09. Step-off. An owner or operator may submit to the Department a step-off request to complete a new borehole from surface if a borehole without production casing deviates from vertical plumb by more than five (5) degrees. A step-off borehole must be drilled within the existing pad of the permitted well. The incomplete borehole must be plugged and abandoned under Section 502 of these rules. (7-1-25)10. Well Control (Rotary Tools); Reserve Mud Tanks. When drilling with rotary tools, the owner or operator shall provide, as required by the Department, a reserve mud pit or tank of suitable capacity for the anticipated depth of the well and maintain an on-site supply of mud additives that can raise the mud weight by one (1) pound per gallon in case of loss of well control. (3-18-22)11. Mud Pits. Before drilling, proper and adequate mud pits shall be constructed for the reception and confinement of mud and cuttings and to facilitate the drilling operation. Special precautions shall be taken, if necessary, to prevent contamination of fresh waters. These pits must comply with Section 230 of these rules. If tanks will be used, then mud pits may not be required. (7-1-25)12. Well Control (Cable Tools); Fluid Containment. Natural gas or oil which may be encountered in a substantial quantity in any section of a cable tool drilled hole above the ultimate objective shall be shut off with reasonable diligence either by mudding, casing, or other approved method, and confined to its original source to the Department's satisfaction. The use of cable tools for drilling activities requires written approval by the Department before spud activities. A request to use cable tools must include the following: (7-1-25)a. Proposed pressure control measures; (3-18-22)
b. Diversion and disposal methods for stray gas; (3-18-22) c. Safety protocols for mud weights and well controls; and (3-18-22) d. Annual drill rig safety inspection information, including the date of last replacement of cables, draw works inspection report, and metallurgic report of safety compliance for structural integrity of the drill rig. (3-18-22)
13. Drilling Mud Disposal. Drilling mud will be disposed of at an appropriate facility in compliance with applicable state and federal requirements. (3-18-22)
14. Report of Water Encountered; Owner's or Operator's Duties. Owners or operators drilling an oil or gas well or drilling a seismic, core, or other exploratory hole must report to the Department all potential water bearing zones encountered. Such report shall be in writing and give the location of the well or hole, the depth at which the zones were encountered, the thickness of such zones, and the rate of flow of water if known. This requirement can be met by the submittal of the logs required in Section 341 of this rule. (7-1-25)
15. SPCC Plan. The owner or operator must have an SPCC Plan in conformance with the requirements of the EPA. This plan must be updated as needed when facilities or activities change. (7-1-25)
16. Interim Drill Site Clean Up. If a well is completed for production or other purposes, interim reclamation must be completed within six (6) months of the rig being removed. Interim reclamation includes the following: (7-1-25)
a. Debris and waste materials including, but not limited to, concrete, sack bentonite and other drilling mud additives, sand, plastic, pipe, and cable associated with the drilling, re-entry, or completion operations shall be removed and disposed of properly. (3-18-22)
b. All disturbed areas affected by drilling or subsequent operations, except areas reasonably needed for production operations or for subsequent drilling operations to be commenced within twelve (12) months, shall be reclaimed and revegetated to approximately the pre-drilling condition or to the condition specified in an agreement with the surface owner. The reclamation standards in Subsections 510.04 through 510.07 of these rules, shall apply. (3-18-22)
311. LOSS OF TOOL WITH RADIOACTIVE MATERIAL.
01. Recovery or Cementing of Tool. If a gamma ray tool, or some other tool containing radioactive material, becomes lost in a well, the owner or operator shall make every reasonable attempt to retrieve the tool from the well. If the tool cannot be recovered, the owner or operator must immediately cover the tool with cement sufficient to secure it in place and prevent it from contacting any fluids in the well. A whipstock or other approved deflection device shall be placed on top of the cement plug to prevent accidental or intentional mechanical disintegration of the radioactive source. (3-18-22)
02. Sidetracking. If the hole is later sidetracked above the radioactive material, the sidetracked hole must be at least fifteen (15) feet from the original hole with the lost radioactive material. (3-18-22)
03. Reporting. A report must be sent to the Department and IDEQ within thirty (30) days of cementing the tool. The report must describe the tool that was lost, the depth it was lost at, the specific type and amount of radioactive material in the tool, and an estimate of the length of cement covering the tool. This report may be included in a plugging report if the well will be plugged. (3-18-22)
312. CHOKES. All flowing wells shall be equipped with adequate chokes or beans to properly control the flow thereof. (3-18-22)
313. USE OF EARTHEN RESERVOIRS. Oil may not be produced, stored, or retained in earthen reservoirs or in open receptacles. (7-1-25)
The use of vacuum pumps or other devices for the purpose of placing a vacuum on any gas- or oil-bearing stratum is prohibited; however, the Department may upon application and hearing and for good cause shown permit the use of vacuum pumps. (3-18-22)
Casing may not be recovered if its recovery will expose any abnormal pressure, lost circulation, oil, gas, or water zone. In pulling outside strings of casing from any oil or gas well, the space outside the casing left in the hole shall be kept and left full of mud-laden fluid of adequate specific gravity to seal off all fresh and saltwater strata and any strata bearing oil or gas which is not producing. Casing may not be pulled without first making application to the Department and receiving approval. The application must describe how fresh waters will be protected. (7-1-25)
a. The MIT shall include one (1) of the following to determine whether leaks are present in the casing, tubing, or packer: (7-1-25)
i. A pressure test with liquid or gas at a pressure of not less than three hundred (300) psi or the minimum injection pressure, whichever is greater, and not more than the maximum injection pressure; (7-1-25)
ii. The monitoring and reporting to the Department, on a monthly basis for sixty (60) consecutive months, of the average casing-tubing annulus pressure, following an initial pressure test; or (3-18-22)
iii. Any equivalent test or combinations of tests approved by the Department. (7-1-25)
b. The MIT shall include one (1) of the following to determine whether there are fluid movements in vertical channels adjacent to the well bore: (7-1-25)
i. Tracer surveys; (3-18-22)
ii. Cement bond log or other acceptable cement evaluation log; (3-18-22)
iii. Temperature surveys; or (3-18-22)
iv. Any other equivalent test or combination of tests approved by the Department. (7-1-25)
c. Mechanical integrity tests shall be performed at the rate of not less than one (1) test every five (5) years, regardless of well status. The first five-year period shall commence on the date of the initial MIT. (7-1-25)
02. Inactive Wells. If, at any time, surface equipment excluding the wellhead is removed or the well becomes incapable of production, an MIT shall be performed within thirty (30) days. The MIT for an inactive well shall be isolation of the wellbore with a bridge plug or similar approved isolating device set one hundred (100) feet or less above the highest perforations and a pressure test with liquid or gas at a pressure of not less than three hundred (300) psi surface pressure or any equivalent test or combination of tests approved by the Department. (7-1-25)
03. Prior Notification. At least twenty-four (24) hours prior to the performance of any MIT required by this rule, any person required to perform the test shall notify the Department, in writing, of the scheduled date on which the test will be performed. (7-1-25)
04. Reporting Requirements. MIT results shall be submitted to the Department within thirty (30) days of testing. (7-1-25)
05. Mechanical Integrity Required. All wells shall maintain mechanical integrity. All wells that fail a
an MIT, or that are determined through any other means to lack mechanical integrity, shall immediately be investigated by the owner or operator. The well shall be repaired or immediately shut down following the investigation. Repairs shall be completed within six (6) months, or the well shall be plugged and abandoned. If the repair cannot be completed within six (6) months, the owner or operator may request an extension from the Department and provide a plan for the repair to the Department's satisfaction. (7-1-25)
01. General Restrictions; Allowable Deviation. The maximum point at which a well penetrates the producing formation may not unreasonably vary from the vertical drawn from the center of the hole at the surface. Deviation is permitted without special permission to remedy blowouts and, for short distances, to straighten the hole, sidetrack junk, or correct other mechanical difficulties. (7-1-25)
02. Controlled Directional Drilling. Except for the purposes recited in Subsection 330.01, no well drilled may be intentionally directionally deviated from the vertical unless the owner or operator thereof first files an application and submits an application fee to amend the drilling permit and receive approval from the Department. Such application shall contain the following information: (7-1-25)
03. Copy of Application to Offset Operators. At the time the application is filed with the Department, a copy of the application and the plat shall be forwarded by registered mail to all offset operators to the lease on which the well is to be drilled. (3-18-22)
04. Department Action. Upon receipt, the Department will hold the application for ten (10) days. If any offset operator objects to the proposed intentional deviation within ten (10) days of receipt of the application by said operator, or if the Department is not in agreement with the proposed deviation, the application shall be set down for public hearing. If no objection from either an offset operator or the Department is raised within the ten (10) day period, the application shall be approved and permit issued by the Department. If written consent of the offset operator(s) is filed concurrently with the application to drill directionally, the Department may immediately approve the application without waiting ten (10) days. (7-1-25)
05. Angular Deviation and Directional Survey. Upon completion, a complete angular deviation and directional survey of the well obtained by an approved well surveying company shall be filed with the Department, together with other regularly required reports. (3-18-22)
06. Application for Exceptions. In the event the proposed, or final, location of the producing interval of the directionally deviated well is not in agreement with spacing or other rules of the Commission applicable to the reservoir, proper applications shall be made to obtain approval of exceptions to such rules. Such approval shall be granted or denied at the discretion of the Department, and shall be accorded with the same consideration and treatment as if the well had been drilled vertically to the producing interval. (3-18-22)
Within thirty (30) days after the completion of a well drilled for oil or gas, or the recompletion of a well into a different source of supply, or where the producing interval is changed, a completion report shall be filed with the Department, on a form prescribed by the Department. Such report shall include name, number, and exact location of the well; lease name, date of completion and date of first production, if any; name and depth of hydrocarbon reservoir(s), if a multiple completion, from which well is producing; annulus pressure test; initial production test, including oil, gas, and water, if any; a well report as defined in Section 010; and such other relevant information as the Department may require. (3-18-22)
01. Minimum Required Logs. All wells shall have a lithologic log from the bottom of the hole to the top, to the extent practicable. (3-18-22)
02. Bottom Hole Survey. All wells shall have a bottom hole location survey. (3-18-22)
03. Cement Bond Log. All wells that are cased and cemented shall have a cement bond log run across the casing. (3-18-22)
04. Other Logs. If other logs are run, including, but not limited to, resistivity, gamma-neutron log, sonic log, etc., then the owner or operator shall retain a copy regardless of results. (3-18-22)
05. Log Submittal. The above logs shall be submitted to the Department in pdf and final processed digital formats within thirty (30) days of the log being run. If logs were run in color, then the submitted copies shall also be in color. Digital formats must be Tiff and LAS 2.0 or higher. Logs submitted to the Department must have a scale of one (1) inch or two (2) inch for correlation logs and five (5) inches for detail logs. (7-1-25)
01. Required Content. An owner or operator must report production on a form created by the Department. Production reports submitted to the Department must include gas quantities sold in thousand cubic feet (mcf), condensate sold in barrel quantities (bbl), oil sold in barrel quantities (bbl), and formational waters produced in barrel quantities (bbl). (3-18-22)
02. Annual Production Report. By January 31 of each year, an owner or operator must submit to the Department an aggregated report of all hydrocarbons and formational waters produced and sold or disposed of for each well during the previous calendar year. (3-18-22)
The volume of production of oil shall be computed in terms of barrels of clean oil on the basis of meter measurements or tank measurements of oil-level difference made and recorded to the nearest quarter-inch (1/4') of one hundred percent (100%) capacity tables, subject to the following corrections: (3-18-22)
01. Correction for Impurities. The percentage of impurities (water, sand, and other foreign
substances, not constituting a natural component part of the oil) shall be determined to the satisfaction of the Department, and the observed gross volume of oil will be corrected to exclude the entire volume of such impurities. (7-1-25)
02. Temperature Correction. The observed volume of oil corrected for impurities will be further corrected to the standard volume at sixty (60) Degrees F in accordance with ASTM D-1250-08, Table 7, or any revisions thereof and any supplements thereto, or any close approximation thereof approved by the Department. (7-1-25)
03. Gravity Determination. The gravity of oil at sixty (60) degrees F will be determined in accordance with ASTM D-1250-08, Table 5, or any revisions thereof and any supplements thereto approved by the Department. (7-1-25)
For computing volume of gas to be reported to the Department, the standard of pressure shall be fourteen point seventy-three (14.73) psi atmospheric, and the standard of temperature shall be sixty (60) Degrees F. All volumes of gas to be reported to the Department will be adjusted by computation to these standards, unless otherwise authorized by the Department. (7-1-25)
In the absence of an order by the Commission setting a field-specific oil-gas ratio, a well that produces gas of five thousand (5,000) cubic feet or greater to one (1) bbl of oil at standard temperature and pressure will be classified as a gas well. (3-18-22)
01. Waste Prevention; Conditions for Emergency Order. To further prevent waste resulting from the production of wells with inefficient gas-oil ratios, the Department may enter an emergency order temporarily prohibiting the production of oil or gas from all wells in a pool producing both oil and gas when the Department believes that waste may be occurring or is imminent in said pool by reason of the operation of wells with inefficient gas-oil ratios. The order shall specify a date for the hearing described in Subsection 404.02 of these rules. The Department may use information provided by an offset operator or an owner or operator in a common source of supply to determine if waste is occurring. (3-18-22)
02. Notice and Cause for Hearing. The Department will notify all offset operators and owners or operators in the common source of supply of the hearing date. A hearing regarding waste due to inefficient gas-oil ratios may be held for any of the following reasons: (7-1-25)
i. If the Department issues an order described in Subsection 404.01 of these rules. The hearing will be scheduled between five (5) and fifteen (15) days after the effective date of the order. (7-1-25)
ii. Upon application to the Department from any person with an ownership interest in the common source of supply who believes that waste is occurring due to inefficient oil and gas ratios. The application must include credible evidence of such waste. The hearing shall be held within thirty (30) days of the Department receiving the application. (3-18-22)
iii. Prior to an emergency situation and upon its own motion with reasonable cause, the Department may schedule a hearing regarding potential waste due to inefficient gas-oil ratios. (3-18-22)
03. Determination of Inefficient Ratios; Power to Limit Production. If the Department after conducting a hearing for any of the reasons specified in Section 404.02 of these rules finds that a well(s) in the pool are operating with inefficient gas-oil ratios, and that waste is occurring or is imminent as a result thereof, it shall enter an order limiting the production of oil and gas from said pool to that amount which the pool can produce without waste and in accordance with sound engineering practice. The order shall also limit the amount of oil or gas, or both, that may be produced from any well in the pool, so that each owner or operator is given an opportunity to produce his just and equitable share in the pool in accordance with sound engineering practice. (7-1-25)
Within thirty (30) days following the completion or recompletion of each well producing oil and gas, and thereafter as the Department may require, the owner or operator of such well shall make a gas-oil ratio test of such well and report the results to the Department within twenty (20) days. Certain wells may be excepted from this rule by the Department upon written request. Entire fields may be excepted from this rule after notice and hearing. (7-1-25)
01. General Requirements. Meter fittings of adequate size to measure the gas efficiently for the purpose of obtaining gas-oil ratios shall be installed on the gas vent line of every separator or proper connections made for orifice well tester. Wellhead equipment shall be installed and maintained in excellent condition. Valves shall be installed so that pressures can be readily obtained on both casing and tubing. (7-1-25)
02. Visibility. All required meters shall be accessible and viewable by the Department for the purpose of monitoring daily, monthly, and cumulative production volumes from individual wells. (7-1-25)
All flowing oil wells must be produced through an adequate oil and gas separator or emulsion treater, provided, however, the Administrator may approve producing wells without a separator or emulsion treater. (7-1-25)
No well may produce either oil or gas from different pools through the same string of casing without first receiving written permission from the Department. (7-1-25)
After a well is completed and while it is being tested, the owner or operator may flare gas for no more than fourteen (14) days without paying royalties and severance taxes on the flared gas. Under no conditions may gas be flared for more than sixty (60) days after a well is completed or recompleted. Prior to flaring gas, owners or operators must notify the county in which the well is located and all owners of occupied structures within a one-quarter (1/4) mile radius of the well. After the owner or operator has tested a well, no gas from such well shall be permitted to escape into the air, and all gas produced therefrom shall be utilized without waste. (7-1-25)
01. Requirements. All tank batteries consisting of tanks containing produced fluids or crude oil storage tanks or containing tanks equipped to receive produced fluids must be surrounded by tank dikes that meet the following requirements: (7-1-25)
a. Tank dikes must have a capacity of at least one and one-half (1½) times the volume of the largest tank which the dike surrounds. (7-1-25)
b. The material used to construct a tank dike and the material used to line the bottom and sides of the containment reservoir must have a maximum coefficient of permeability of 10-6 cm/sec so as to contain fluids and resist erosion. An operator must submit proof of compliance for tank dike liner construction to the Department in the form of a manufacturer's statement of design or a nuclear density test performed by a third party trained to perform the test. (7-1-25)
c. All piping and man-made improvements that perforate the tank dike wall or tank battery floor must be sealed to a minimum radius of twelve (12) inches from the outside edge of the piping or improvement. (7-1-25)
d. Valves and quick-connect couplers on tank batteries must be at least eighteen (18) inches from the inside wall of the tank dike. (3-18-22)
e. Vegetation on the top and outside surface of tank dike must be properly maintained to prevent fire hazards. (7-1-25)
f. A ladder or other permanent device must be installed over the tank dike to access the containment reservoir. (3-18-22)
g. The containment reservoir must be kept free of vegetation, stormwater, produced fluids, other oil and gas field related debris, general trash, or any flammable material. Drain lines installed through the tank dike for the purpose of draining storm water from the containment reservoir must have a valve installed and remain closed and capped when not in use. Any fluids collected, spilled or discharged within the containment reservoirs must be removed as soon as practical, characterized, treated if necessary, and disposed in conformance with IDAPA 58.01.16, “Wastewater Rules,” and other applicable rules. (7-1-25)
01. Operations. Operators of gas processing facilities must notify the Department which wells, by API number, are served by a gas processing facility. All gas processing facilities not constructed on a well site must comply with Sections 301 and 302 of these rules. (7-1-25)
02. Meters and Facility Plans. Gas processing facilities must account for all liquids and gas entering and leaving the facility with accurate meters. A supervisory control and data acquisition systems or other data recording system must be used to monitor the liquids and gas in the facility. Operators of gas processing facilities must submit an as-built facility design plan to the Department upon completion of the facility. A facility design plan must contain: (7-1-25)
a. Site layout; (3-18-22)
b. Piping and instrumentation diagram; (3-18-22)
c. Process Flow schematics; (3-18-22)
d. Electronic controls and sensing schematic; (3-18-22)
e. Equipment operations and maintenance manuals for, pumps, meters, heat exchangers, and any other operationally critical equipment that requires periodic maintenance and calibration; (7-1-25)
f. Periodic maintenance schedule for critical equipment; (3-18-22)
g. Troubleshooting metric; and (3-18-22)
h. Other information or documentation necessary for the safe and continued operation of a gas processing facility. (3-18-22)
03. Flaring. Flaring at gas processing facilities must be in conformance with IDAPA 58.01.01, Rules for the Control of Air Pollution in Idaho, and any permit issued by IDEQ. (7-1-25)
04. Inspections. Gas processing facilities must have site-specific facility design plans and a log book of gas metered in and out of the facility available for review by Department staff. During inspections, gas processing facility staff must demonstrate knowledge of all operations and the location of all emergency shut off equipment, direction of flow lines, and heat exchangers. (7-1-25)
01. Gas Storage Wells. Gas storage wells are to be considered active at all times unless physically plugged. (3-18-22)
02. Extension of Active Status. An owner or operator may request an extension of active well status for wells that are idled for more than twenty-four (24) continuous months. The owner or operator shall provide a written request to the Department stating the reason for the extension, the length of extension, the method used to close the well to the atmosphere, and the plans for future operation. The Department shall review the request for approval, modification, or denial, and may set the duration of the extension if approved. An extension may not exceed five (5) years and may be renewed upon request up to a maximum of ten (10) total years. (7-1-25)
03. Annual Reports for Active Wells. The owner or operator shall submit an annual report to the Department describing the current status of the well and the plans for future well operation by January 31 of each year. (7-1-25)
01. Determination of Inactive Status. The Department will declare a well inactive after twenty-four (24) continuous months of inactivity if the owner or operator has not received approval for an extension of active status under Section 500.02 of these rules, or if an owner or operator fails to submit an annual report for an active well under Section 500.03 of these rules. The Department will immediately notify an owner or operator of this determination by certified mail, and the owner or operator may appeal this determination to the Commission. (7-1-25)
02. Owner’s or Operator’s Responsibility for Inactive Wells. The owner or operator must plug and abandon an inactive well under Section 502 of these rules within six (6) months of being notified by the Department unless the owner or operator supplies the following information: (7-1-25)
a. A written request to extend inactive status; (3-18-22)
b. An individual bond, as provided for in Subsection 220.03 of these rules, if the well was covered by a blanket bond; and (3-18-22)
c. A description of how the well is closed to the atmosphere with a swedge and valve, packer, or other approved method, and how the well is to be maintained. (3-18-22)
03. Inactive Review and Decision. The Department will review the request for approval, modification, or denial, and set the duration of the extension if approved. Extensions may not exceed three (3) years and may be renewed upon request up to a maximum of six (6) total years. (7-1-25)
04. Testing of Inactive Wells. In addition to the requirements of Section 320 of these rules, inactive wells must have an MIT performed within two (2) years after the date of last use in order to retain inactive status. (7-1-25)
05. Converting Inactive Wells to Active Wells. The owner or operator must apply to the Department to change the status of a well from inactive to active. The Department will review the request for approval, modification, or denial. An MIT may be required by the Department if the well has been worked over or if a test has not been conducted for five (5) years or longer. If approved, the well may again be covered by a blanket bond. (7-1-25)
01. Plugging Required. The owner or operator may not allow any well drilled for oil, gas, saltwater disposal or any other purpose in connection with the production of oil and gas, to remain unplugged after such well is no longer used for the purpose for which it was drilled or converted. (7-1-25)
02. Notice of Intention to Abandon Well. Before beginning abandonment work on an oil or gas well, a Notice of Intention to Abandon must be filed with the Department and approval obtained as to the method of abandonment. The notice must show the reason for abandonment and must give a detailed statement of the proposed work, including such information as kind, location, and length of plugs (by depths), and plans for mudding, cementing, shooting, testing, and removing casing as well as any other pertinent information requested by the Department. (7-1-25)
03. Plugging Dry Holes. If a nonproductive well, or dry hole, is drilled and not needed for any specific purpose, it must be plugged and abandoned prior to removal of the drill rig. A verbal notification and approval may be used for dry holes in lieu of the written notification referenced in Subsection 502.02 of these rules. The standards in Subsections 502.04 through 502.06 of these rules will still apply. (3-18-22)
04. Plugging of Wells. The owner or operator of any well drilled for oil or gas, or any seismic, core, or other exploratory holes, whether cased or uncased, and regardless of diameter must plug said hole in a manner sufficient to properly protect all freshwater-bearing and possible or probable oil- or gas-bearing formations. The material used in plugging, whether cement, mechanical plug, or some other equivalent method approved in writing by the Administrator, must be placed in the well in a manner to permanently prevent migration of oil, gas, water, or other substances from the formation or horizon in which it originally occurred. The preferred plugging cement slurry is that recommended in API Bulletin E3. Pozzolan, gel, and other approved extenders may be used if the owner or operator can document to the Department's satisfaction that the slurry design will achieve a minimum compressive strength of three hundred (300) psi after twenty-four (24) hours, and eight hundred (800) psi after seventy-two (72) hours measured at ninety-five (95) degrees F and at eight hundred (800) psi. No substances of any nature or description other than those normally used in plugging operations may be placed in any well at any time during plugging operations. (7-1-25)
05. Plugged Intervals. The following plugging standards shall be followed for all wells: (3-18-22)
a. Cement must be placed for a length of at least one hundred (100) feet on either side of each casing shoe, or casing bottom if no shoe is present. If the bottom of the hole is less than one hundred (100) feet from the bottom of the lowest casing, then the entire length of the uncased hole below the casing must be cemented. (7-1-25)
b. In the uncased portions of a well, cement plugs must be placed to extend from one hundred (100) feet below the bottom up to one hundred (100) feet above the top of any oil, gas, and abnormally high pressure zones, so as to isolate fluids in the strata and prevent their escape into other strata. (7-1-25)
c. A cement plug shall be placed a minimum of one hundred (100) feet above all producing zones in uncased portions of a well. (3-18-22)
d. A cement plug shall be placed a minimum of fifty (50) feet above and below the following intervals: (3-18-22)
i. Where the casing is perforated or ruptured. If no cement is present behind the casing, then cement must also be squeezed out the perforations or ruptures and into the annular space between the casing and the borehole. (3-18-22)
ii. Top and bottom of freshwater zones. If freshwater zone is less than one hundred (100) feet thick, then continuous cement must be placed from fifty (50) feet below the zone upward to fifty (50) feet above the zone. (7-1-25)
e. The top of all cement plugs will be tagged to verify their depth. (3-18-22)
f. The owner or operator may choose to place cement in the hole by: (7-1-25)
i. Dump bailer; (3-18-22)
ii. Pumping a balanced cement plug through tubing or drill pipe; (3-18-22)
iii. Pump and plug; or (3-18-22)
iv. Equivalent method approved by the Administrator prior to plugging. (7-1-25)
g. Unless prior approval is given by the Department, all wellbores shall have waterbased drilling muds, high viscosity pills, or other approved fluids between all plugs. (7-1-25)
h. All abandoned wells shall have a plug or seal placed at the surface of the ground or the bottom of the cellar in the hole so as not to interfere with soil cultivation or other surface use. The top of the pipe must be sealed with either a cement plug and a screw cap, or cement plug and a steel plate welded in place or by other approved method, or in the alternative be marked with a permanent monument which shall consist of a piece of pipe not less than four (4) inches in diameter and not less than ten (10) feet in length, of which four (4) feet shall be above the general ground level, the remainder to be embedded in cement or to be welded to the surface casing. (7-1-25)
06. Report of Abandonment. If a well is plugged or abandoned, a record of work done must be filed with the Department within thirty (30) days after the work is completed. The report shall give a detailed account of the manner in which the abandonment of plugging work was carried out, including the weight of mud, the nature and quantities of materials used in plugging, the location and extent (by depths) of the plugs of different materials, and the records of any tests or measurements made and of the amount, size, and location (by depths) of casing left in the well. If an attempt was made to part any casing, a complete report of the method used and the results obtained must be included. (7-1-25)
07. Wells Used for Fresh Water (Cold Water < 85 degrees Fahrenheit), Low Temperature Geothermal (85 - 212 Degrees Fahrenheit), or Geothermal Wells (>212 Degrees Fahrenheit). (7-1-25)
a. Oil and gas wells, seismic, core, or other exploratory holes no longer being used for their original purpose may not be converted into freshwater, low temperature geothermal, or geothermal wells unless: (7-1-25)
i. The owner, operator, or surface owner files an application with the IDWR describing the conversion and the proposed use for the water or geothermal resource and any modifications necessary to meet the applicable well construction standards; (7-1-25)
ii. The surface owner provides written documentation assuming responsibility for the converted well including, should it become necessary, decommissioning (plugging) of the converted well in accordance with applicable law; (3-18-22)
iii. IDWR issues a permit for a geothermal resource well, a water right, or recognizes a domestic exemption authorizing the withdrawal of water from the converted well; and (3-18-22)
iv. A licensed driller in Idaho inspects and certifies that the converted well meets all well construction standards for its intended purpose. (3-18-22)
b. The Department’s bond may not be released, and the oil and gas permit cancelled, until all requirements in Paragraph 502.07.a. of these rules are met. (3-18-22)
503. -- 509. (RESERVED)
01. Timing of Reclamation. After the plugging and abandonment of a well or closure of other oil and gas facilities, all reclamation work described in this Section shall be completed within twelve (12) months. The Administrator may grant an extension where unusual circumstances are encountered, but every reasonable effort shall be made to complete reclamation before the next local growing season. (7-1-25)
02. General Clean Up. All debris, abandoned gathering line risers and flowline risers, surface equipment, supplies, rubbish, and other waste materials shall be removed within three (3) months of plugging a well. The burning or burial of such material on the premises shall be performed in accordance with applicable local, state,
or federal solid waste disposal and air quality regulations. Material may be burned or buried on the premises only with the prior written consent of the surface owner. (7-1-25)
03. Road Removal. All access roads to plugged and abandoned wells and associated production facilities shall be ripped, regraded, and recontoured unless otherwise specified in a surface use agreement. Culverts and any other obstructions that were part of the access road(s) shall be removed. Roads not reclaimed will be graded to drain and prepared with rolling dips or other best management practices to minimize erosion. (7-1-25)
04. Regrading. Drill pads, pits, berms, cut and fill slopes, and other disturbed areas will be regraded to approximate the original contour. Where possible, slopes should be reduced to three (3) horizontal feet to one (1) vertical foot (3H:1V) or flatter. (3-18-22)
05. Compacted Areas. All areas compacted by drilling and subsequent oil and gas operations that are no longer needed following completion of such operations must be cross-ripped. Ripping will be undertaken to a depth of eighteen (18) inches or bedrock, whichever is reached first. (7-1-25)
06. Topsoiling. Stockpiled topsoil shall be replaced in a manner that supports reestablishment of the pre-disturbance land use and contoured to control erosion and provide long-term stability. If necessary, topsoiled areas will be tilled adequately in order to establish a proper seedbed. (7-1-25)
07. Revegetation. (3-18-22)
a. The owner or operator will select and establish plant species that can be expected to result in vegetation comparable to that growing on the affected lands prior to the oil and gas operations. Certified weed free seed should be used in revegetation. The owner or operator may use available technical data and results of field tests for selecting seeding practices and soil amendments that will result in viable revegetation. (7-1-25)
b. The disturbed areas shall be reseeded in the first favorable season following rig demobilization, site regrading, and topsoil replacement. (3-18-22)
c. Unless otherwise specified in the approved permit, the success of revegetation efforts will be measured against the existing vegetation onsite prior to the oil and gas operations, or against an adjacent reference area supporting similar types of vegetation. Reseeding or replanting is required until the following cover standards are met: (7-1-25)
i. The ground cover of living plants on the revegetated area should be comparable to the ground cover of living plants on an adjacent reference area for two (2) full growing seasons after cessation of soil amendment or irrigation, if used; (3-18-22)
ii. Ground cover will be considered comparable if the planted area has at least seventy percent (70%) of the pre-disturbance, or adjacent reference area, ground cover; (7-1-25)
iii. For locations with an average annual precipitation of more than twenty-six (26) inches, the Department, in approving a drilling permit or a pit, may set a minimum standard for success of revegetation as follows: Vegetative cover of seventy percent (70%) for two (2) full growing seasons in areas planted to herbaceous species only; or fifty percent (50%) vegetative cover for two (2) full growing seasons and six hundred (600) woody plants per acre in areas planted to a mixture of herbaceous and woody species; (3-18-22)
iv. As used in this section, “herbaceous species” means grasses, legumes, and other forbs; “woody plants” means woody shrubs, trees, and vines; and “ground cover” means the area of the ground surface covered by the combined aerial parts of vegetation and the litter that is produced naturally on-site, expressed as a percentage of the total area measured. Rock surface areas will be excluded from this calculation; and (3-18-22)
v. In all cases, vegetative cover shall be established to the extent necessary to control erosion. (3-18-22)
d. Introduced species may be planted if they are known to be comparable to previous vegetation, or if known to be of equal or superior use for the approved post-reclamation land use, or, if necessary, to achieve a quick,
temporary cover for soil stabilization purposes. Species classified as poisonous or noxious weed species may not be used in revegetation. (7-1-25)
e. By mutual agreement of the Department, the surface owner, and the owner or operator, a site may be converted to a different, more desirable or more economically suitable habitat. (3-18-22)
f. Planting of grasses and forbs should be done in a manner which promotes rapid stabilization of the soil surface. Wherever terrain permits, grasses and forbs should be drilled or compacted into the ground using agricultural grass planting equipment or other seeders specifically designed for revegetation applications. Broadcast and hydroseeding may be used on areas where other methods are impractical or unavailable. (3-18-22)
g. The owner or operator should plant shrubs or shrub seed, as required, where shrub communities existed prior to oil and gas operations. Shrub seed may be planted as a portion of a grass seed mix or planted as bare-root transplants after grass seeding. Where the surface owner desires a specific land use such as grazing or cropland, shrubs will not be required in the revegetation species mix. Shrub lands undergoing revegetation with shrubs shall be protected from erosion by vegetation, chemical binders, or other acceptable means during establishment of the shrubs. (3-18-22)
h. Tree stocking of forestlands should meet the following criteria: (3-18-22)
i. Trees that are adapted to the site should be planted in a density which can be expected over time to yield a timber stand comparable to pre-disturbance timber stands; (3-18-22)
ii. Trees must be established for two (2) full growing seasons after cessation of any soil amendments and irrigation before they are considered established; and (7-1-25)
iii. Forestlands undergoing revegetation with trees should be protected from erosion by vegetation, chemical binders, or other acceptable means during seedling establishment. (3-18-22)
i. Revegetation is not required on areas that the surface owner wishes to incorporate into an irrigated field and any roads which will be used for other oil and gas operations. (3-18-22)
j. Mulch should be used on severe sites and may be required by the permit where slopes are steeper than three (3) horizontal feet to one (1) vertical foot (3H:1V) or the mean annual rainfall is less than twelve (12) inches. Straw, or hay mulch should be obtained from certified weed free sources. “Mulch” means vegetation residues or other suitable materials to aid in the stabilization of soil and soil moisture conservation which will provide a micro-climate more suitable for germination and growth on severe sites. Annual grains such as rye, oats, and wheat may be used as a substitute for mulch where they will provide adequate protection and will be replaced by permanent species within a reasonable length of time. (7-1-25)
08. Reclamation Under a Surface Use Agreement. Notwithstanding the requirements of Subsections 510.03 through 510.07 of this rule, reclamation may be superseded by the conditions of a surface use agreement as long as the site is left in a stable, non-eroding condition that will not impact Fresh waters. (7-1-25)
511. -- 999. (RESERVED)