Utah Administrative Code 

The Utah Administrative Code is the body of all effective administrative rules as 

compiled and organized by the Division of Administrative Rules (Subsection 63G-3-102

(5); see also Sections 63G-3-701 and 702). 

NOTE: For a list of rules that have been made effective since May 1, 2012, please see 

the codification segue page. 

NOTE TO RULEFILING AGENCIES: Use the RTF version for submitting rule 

changes.

Download the RTF file

Rule R649-3. Drilling and Operating Practices. 

As in effect on May 1, 2012 

Table of Contents 

 R649-3-1. Bonding. 

 R649-3-2. Location And Siting of Vertical Wells and Statewide Spacing for 

Horizontal Wells. 

 R649-3-3. Exception to Location and Siting of Wells. 

 R649-3-4. Permitting of Wells to be Drilled, Deepened or Plugged-Back. 

 R649-3-5. Identification. 

 R649-3-6. Drilling Operations. 

 R649-3-7. Well Control. 

 R649-3-8. Casing Program. 

 R649-3-9. Protection of Upper Productive Strata. 

 R649-3-10. Tolerances for Vertical Drilling. 

 R649-3-11. Directional Drilling. 

 R649-3-12. Drilling Practices for Hydrogen Sulfide H2S Areas and Formations. 

 R649-3-13. Casing Tests. 

 R649-3-14. Fire Hazards on the Surface. 

 R649-3-15. Pollution and Surface Damage Control. 

 R649-3-16. Reserve Pits and Other On-site Pits. 

 R649-3-17. Inspection. 

 R649-3-18. On-site Predrill Evaluation. 

 R649-3-19. Well Testing. 

 R649-3-20. Gas Flaring or Venting. 

 R649-3-21. Well Completion and Filing of Well Logs. 

 R649-3-22. Completion Into Two or More Pools. 

 R649-3-23. Well Workover and Recompletion. 

 R649-3-24. Plugging and Abandonment of Wells. 

 R649-3-25. Underground Disposal of Drilling Fluids. 

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 R649-3-26. Seismic Exploration. 

 R649-3-27. Multiple Mineral Development. 

 R649-3-28. Designated Potash Areas. 

 R649-3-29. Workable Coal Beds. 

 R649-3-30. Underground Mining Operations. 

 R649-3-31. Designated Oil Shale Areas. 

 R649-3-32. Reporting of Undesirable Events. 

 R649-3-33. Drilling Procedures in the Great Salt Lake. 

 R649-3-34. Well Site Restoration. 

 R649-3-35. Wildcat Wells. 

 R649-3-36. Shut-in and Temporarily Abandoned Wells. 

 R649-3-37. Enhanced Recovery Project Certification. 

 KEY 

 Date of Enactment or Last Substantive Amendment 

 Notice of Continuation 

 Authorizing, Implemented, or Interpreted Law 

R649-3-1. Bonding.

1. An owner or operator shall furnish a bond to the division prior to approval of a 

permit to drill a new well, reenter an abandoned well or assume responsibility as 

operator of existing wells. 

1.1. An owner or operator shall furnish a bond to the division on Form 4, for wells 

located on lands with fee or privately owned minerals. 

1.2. An owner or operator shall furnish evidence to the division that a bond has 

been filed in accordance with state, federal or Indian lease requirements and 

approved by the appropriate agency for all wells located on state, federal or Indian 

leases. 

2. A bond furnished to the division shall be payable to the division and 

conditioned upon the faithful performance by the operator of the duty to plug each 

dry or abandoned well, repair each well causing waste or pollution, and maintain and 

restore the well site. 

3. Bond liability shall be for the duration of the drilling, operating and plugging of 

the well and restoration of the well site. 

3.1. The bond for drilling or operating wells shall remain in full force and effect 

until liability thereunder is released by the division. 

3.2. Release of liability shall be conditioned upon compliance with the rules and 

orders of the Board. 

4. For all drilling or operating wells, the bond amounts for individual wells and 

blanket bonds required in subsections 5. and 6. represent base amounts adjusted to 

year 2002 average costs for well plugging and site restoration. The base amounts are 

effective immediately upon adoption of this bonding rule, subject to division 

notification as described in subsection 4.1. 

4.1. The division shall provide written notification to each operator of the need to 

revise or establish bonds in amounts required by this bonding rule. 

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4.2. Within 120 days of such notification by the division, the operator shall post a 

bond with the division in compliance with this bonding rule. 

4.3. If the division finds that a well subject to this bonding rule is in violation of 

Rule R649-3- 36., Shut-in and Temporarily Abandoned Wells, the division shall 

require a bond amount for the applicable well in the amount of actual plugging and 

site restoration costs. 

4.4. The division shall provide written notification to an operator found in 

violation of Rule R649- 3-36., and identify the need to establish increased bonding 

for shut-in wells. 

4.4.1. Within 30 days of notification by the division, the operator shall submit to 

the division an estimate of plugging and site restoration costs for division review and 

approval. 

4.4.2. Upon review and approval of the cost estimate, the division will provide a 

notice of approval back to the operator specifying the approved bond amount for 

shut-in wells. 

4.4.3. Within 120 days of receiving such notice of approval, the operator shall 

post a bond with the division in compliance with this bonding rule. 

5. The bond amount for drilling or operating wells located on lands with fee or 

privately owned minerals shall be one of the following: 

5.1. For wells of less than 1,000 feet in depth, an individual well bond in the 

amount of at least $1,500, for each such well. 

5.2. For wells of more that 1,000 feet in depth but less than 3,000 feet in depth, 

an individual well bond in the amount of at least $15,000 for each such well. 

5.3. For wells of more that 3,000 feet in depth but less than 10,000 feet in depth, 

an individual well bond in the amount of at least $30,000 for each such well. 

5.4. For wells of more than 10,000 feet in depth, an individual well bond in the 

amount of at least $60,000 for each such well. 

6. If, prior to the July 1, 2003 revision of this bonding rule, an operator is drilling 

or operating more than one well on lands with fee or privately owned minerals, and a 

blanket bond was furnished and accepted by the division in lieu of individual well 

bonds, that operator shall remain qualified for a blanket bond with the division 

subject to the amounts described by this bonding rule. 

6.1. A blanket bond shall be conditioned in a manner similar to individual well 

bonds and shall cover all wells that the operator may drill or operate on lands with 

fee or privately owned minerals within the state. 

6.2. For wells of less than 1,000 feet in depth, a blanket bond in the amount of at 

least $15,000 shall be required. 

6.3. For wells of more than 1,000 feet in depth, a blanket bond in the amount of 

at least $120,000 shall be required. 

6.4. Subsequent to the July 1, 2003 revision of this rule, operators who desire to 

establish a new blanket bond that consists either fully or partially of a collateral bond 

as described in subsection 10.2. shall be qualified by the division for such blanket 

bond. 

6.4.1. Operators who elect to establish a surety bond as a blanket bond shall not 

require qualification by the division. 

6.4.2. In those cases where operator qualification for blanket bond is required, 

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the division will review the following criteria and make a written finding of the 

operator's adequacy to meet the criteria before accepting a new blanket bond: 

6.4.3. The ratio of current assets to current liabilities shall be 1.20 or greater, as 

evidenced by audited financial statements for the previous two years and the most 

current quarterly financial report. 

6.4.4. The ratio of total liabilities to stockholder's equity shall be 2.50 or less, as 

evidenced by audited financial statements for the previous two years and the most 

current quarterly financial report. 

7. If an operator desires bond coverage in a lesser amount than required by these 

rules, the operator may file a Request for Agency Action with the Board for a 

variance from the requirements of these rules. 

7.1. Upon proper notice and hearing and for good cause shown, the Board may 

allow bond coverage in a lesser amount for specific wells. 

8. If after reviewing an application to drill or reenter a well or when reviewing a 

change of operator for a well, the division determines that bond coverage in 

accordance with these rules will be insufficient to cover the costs of plugging the well 

and restoring the well site, the division may require a change in the form or the 

amount of bond coverage. In such cases, the division will support its case for a 

change of bond coverage in the form of written findings to the operator of record of 

the well and provide a schedule for completion of the requisite changes. 

8.1 Appeals of mandated bond amount changes will follow procedures established 

by Rule R649-10., Administrative Procedures. 

9. The bond shall provide a mechanism for the surety or other guarantor of the 

bond, to provide prompt notice to the division and the operator of any action alleging 

the insolvency or bankruptcy of the surety or guarantor, or alleging any violations 

that would result in suspension or revocation of the suretys or guarantor's charter or 

license to do business. 

9.1. Upon the incapacity of the surety or guarantor to guarantee payment of the 

bond by reason of bankruptcy, insolvency, or suspension or revocation of a charter or 

license, the operator shall be deemed to be without bond coverage. 

9.2. Upon notification of insolvency or bankruptcy, the division shall notify the 

operator in writing and shall specify a reasonable period, not to exceed 90 days, to 

provide bond coverage. 

9.3. If an adequate bond is not furnished within the allowed period, the operator 

shall be required to cease operations immediately, and shall not resume operations 

until the division has received an acceptable bond.

10. The division shall accept a bond in the form of a surety bond, a collateral bond 

or a combination of these bonding methods. 

10.1. A surety bond is an indemnity agreement in a sum certain payable to the 

division, executed by the operator as principal and which is supported by the 

performance guarantee of a corporation authorized to do business as a surety in 

Utah. 

10.1.1. A surety bond shall be executed by the operator and a corporate surety 

authorized to do business in Utah that is listed in "A.M. Best's Key Rating Guide" at a 

rating of A- or better or a Financial Performance Rating (FPR) of 8 or better, 

according to the "A.M. Best's Guide". All surety companies also will be continuously 

listed in the current issue of the U.S. Department of the Treasury Circular 570. 

Operators who do not have a surety bond with a company that meets the standards 

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of subsection 10.1.1. will have 120 days from the date of division notification after 

enactment of the changes to subsection 10.1.1., or face enforcement action. When the 

division in the course of examining surety bonds notifies an operator that a surety 

company guaranteeing its performance does not meet the standards of subsection 

10.1.1., the operator has 120 days after notice from the division by mail to correct the 

deficiency, or face enforcement action. 

10.1.2. Surety bonds shall be noncancellable during their terms, except that surety 

bond coverage for wells not drilled may be canceled with the prior consent of the 

division. 

10.1.3. The division shall advise the surety, within 30 days after receipt of a notice 

to cancel a bond, whether the bond may be canceled on an undrilled well. 

10.2. A collateral bond is an indemnity agreement in a sum certain payable to the 

division, executed by the operator that is supported by one or more of the following: 

10.2.1. A cash account. 

10.2.1.1. The operator may deposit cash in one or more accounts at a federally 

insured bank authorized to do business in Utah, made payable upon demand only to 

the division. 

10.2.1.2. The operator may deposit the required amount directly with the division. 

10.2.1.3. Any interest paid on a cash account shall be retained in the account and 

applied to the bond value of the account unless the division has approved the 

payment of interest to the operator. 

10.2.1.4. The division shall not accept an individual cash account in an amount in 

excess of $100,000 or the maximum insurable amount as determined by the Federal 

Deposit Insurance Corporation. 

10.2.2. Negotiable bonds of the United States, a state, or a municipality. 

10.2.2.1. The negotiable bond shall be endorsed only to the order of and placed in 

the possession of the division. 

10.2.2.2. The division shall value the negotiable bond at its current market value, 

not at face value. 

10.2.3. Negotiable certificates of deposit. 

10.2.3.1. The certificates shall be issued by a federally insured bank authorized to 

do business in Utah. 

10.2.3.2. The certificates shall be made payable or assigned only to the division 

both in writing and upon the records of the bank issuing the certificate. 

10.2.3.3. The certificates shall be placed in the possession of the division or held 

by a federally insured bank authorized to do business in Utah. 

10.2.3.4. If assigned, the division shall require the banks issuing the certificates to 

waive all rights of setoff or liens against those certificates. 

10.2.3.5. The division shall not accept an individual certificate of deposit in an 

amount in excess of $100,000 or the maximum insurable amount as determined by 

the Federal Deposit Insurance Corporation. 

10.2.4. An irrevocable letter of credit. 

10.2.4.1. Letters of credit shall be placed in the possession of and payable upon 

demand only to the division. 

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10.2.4.2. Letters of credit shall be issued by a federally insured bank authorized to 

do business in Utah. 

10.2.4.3. Letters of credit shall be irrevocable during their terms. 

10.2.4.4. Letters of credit shall be automatically renewable or the operator shall 

ensure continuous bond coverage by replacing letters of credit, if necessary, at least 

30 days before their expiration date with other acceptable bond types or letters of 

credit. 

11. The required bond amount specified in subsections 5. and 6. of all collateral 

posted as assurance under this section shall be subject to a margin determined by the 

division which is the ratio of the face value of the collateral to market value, as 

determined by the division. 

11.1. The margin shall reflect legal and liquidation fees, as well as value 

depreciation, marketability and fluctuations that might affect the net cash available 

to the division to complete plugging and restoration. 

12. The market value of collateral may be evaluated at any time, and in no case 

shall the market value of collateral be less than the required bond amount specified 

in subsections 5. and 6. 

12.1. Upon evaluation of the market value of collateral by the division, the 

division will notify the operator of any required changes in the amount of the bond 

and shall allow a reasonable period, not to exceed 90 days, for the operator to 

establish acceptable bond coverage. 

12.2. If an adequate bond is not furnished within the allowed period the operator 

shall be required to cease operations immediately and shall not resume operations 

until the division has received an acceptable bond.

13. Persons with an interest in collateral posted as a bond, and who desire 

notification of actions pursuant to the bond, shall request the notification in writing 

from the division at the time collateral is offered. 

14. The division may allow the operator to replace existing bonds with other 

bonds that provide sufficient coverage. 

14.1. Replacement of a bond pursuant to this section shall not constitute a release 

of bond under subsection15. 

14.2. The division shall not allow liability to cease under an existing bond until 

the operator has furnished, and the division has approved, an acceptable 

replacement bond. 

14.3. When the operator of wells covered by a blanket bond changes, the division 

will review the financial eligibility of a new operator for blanket bonding as described 

in subsection 6.4., and the division will make a written finding concerning the 

applicability of blanket bonding to the prospective new operator. 

14.4. Transfer of the ownership of property does not cancel liability under an 

existing bond until the division reviews and approves a change of operator for any 

wells affected by the transfer of ownership. 

14.5. If a transfer of the ownership of property is made and an operator wishes to 

request a change to a new operator of record for the affected wells, then the following 

requirements shall be met: 

14.5.1. The operator shall notify the division in writing when ownership of any 

well associated with the property has been transferred to a named transferee, and the 

operator shall request a change of operator for the affected wells. 

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14.5.2. The request shall describe each well by reference to its well name and 

number, API number, and its location, as described by the section, township, range, 

and county, and shall also include a proposed effective date for the operator change. 

14.5.3. The request shall contain the endorsement of the new operator accepting 

such change of operator. 

14.5.4. The request shall contain evidence of the new operator's bond coverage. 

14.5.5. The request may include a request to cancel liability for the well(s) 

included in the operator change that are listed under the existing operator's bond 

upon approval by the division of an adequate replacement bond in the name of the 

new operator. 

14.6. Upon receipt of a request for change of operator, the division will review the 

proposed new operator's bond coverage, and if bond coverage is acceptable, the 

division will issue a notice of approval of the change of operator. 

14.6.1. If the division determines that the new operator's bond coverage will be 

insufficient to cover the costs of plugging and site restoration for the applicable well

(s), the division may deny the change of operator, or the division may require a 

change in the form and amount of the new operator's bond coverage in order to 

approve the change of operator. In such cases, the division will support its case for a 

change of the new operator's bond coverage in the form of written findings, and the 

division will provide a schedule for completion of the requisite changes in order to 

approve the operator change. The written findings and schedule for changes in bond 

coverage will be sent to both the operator of record of the applicable well(s) and the 

proposed new operator. 

14.7. If the request for operator change included a request to cancel liability under 

the existing operator's bond in accordance with subsection 14.5.5., and the division 

approves the operator change, then the division will issue a notice of approval of 

termination of liability under the existing bond for the wells included in the operator 

change. When the division has approved the termination of liability under a bond, 

the original operator is relieved from the responsibility of plugging or repairing any 

wells and restoring any well site affected by the operator change. 

14.8. If all of the wells covered by a bond are affected by an operator change, the 

bond may be released by the division in accordance with subsection 15. 

15. Bond release procedures are as follows: 

15.1. Requests for release of a bond held by the division may be submitted by the 

operator at any time after a subsequent notice of plugging of a well has been 

submitted to the division or the division has issued a notice of approval of 

termination of liability for all wells covered by an existing bond. 

15.1.1. Within 30 days after a request for bond release has been filed with the 

division, the operator shall submit signed affidavits from the surface landowner of 

any previously plugged well site certifying that restoration has been performed as 

required by the mineral lease and surface agreements. 

15.1.2. If such affidavits are not submitted, the division shall conduct an 

inspection of the well site in preparation for bond release as explained in subsection 

15.2. 

15.1.3. Within 30 days after a request for bond release has been filed with the 

division, the division shall publish notice of the request in a daily newspaper of 

general circulation in the city and county of Salt Lake and in a newspaper of general 

circulation in the county in which the proposed well is located. 

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15.1.4. If a written objection to the request for bond release is not received by the 

division within 15 days after publication of the notice of request, the division may 

release liability under the bond as an administrative action. 

15.1.5. If a written objection to the request for bond release is received by the 

division within 15 days after publication of the notice of request, the request shall be 

set for hearing and notice thereof given in accordance with the procedural rules of 

the Board. 

15.2. If affidavits supporting the bond release application are not received by the 

division in accordance with subsection 15.1.1., the division shall within 30 days or as 

soon thereafter as weather conditions permit, conduct an inspection and evaluation 

of the well site to determine if restoration has been adequately performed. 

15.2.1. The operator shall be given notice by the division of the date and time of 

the inspection, and if the operator is unable to attend the inspection at the scheduled 

date and time, the division may reschedule the inspection to allow the operator to 

participate. 

15.2.2. The surface landowner, agent or lessee shall be given notice by the 

operator of such inspection and may participate in the inspection; however, if the 

surface landowner is unable to attend the inspection, the division shall not be 

required to reschedule the inspection in order to allow the surface landowner to 

participate. 

15.2.3. The evaluation shall consider the adequacy of well site restoration, the 

degree of difficulty to complete any remaining restoration, whether pollution of 

surface and subsurface water is occurring, the probability of future occurrence of 

such pollution, and the estimated cost of abating such pollution. 

15.2.4. Upon request of any person with an interest in bond release, the division 

may arrange with the operator to allow access to the well site or sites for the purpose 

of gathering information relevant to the bond release. 

15.2.5. The division shall retain a record of the inspection and the evaluation, and 

if necessary and upon written request by an interested party, the division shall 

provide a copy of the results. 

15.3. Within 60 days from the filing of the bond release request, if a public 

hearing is not held pursuant to subsection 15.1.5., or within 30 days after such public 

hearing has been held, the division shall provide written notification of the decision 

to release or not release the bond to the following parties: 

15.3.1. The operator. 

15.3.2. The surety or other guarantor of the bond. 

15.3.3. Other persons with an interest in bond collateral who have requested 

notification under R649- 3-1.13. 

15.3.4. The persons who filed objections to the notice of application for bond 

release. 

15.4. If the decision is made to release the bond, the notification specified in 

subsection 15.3. shall also state the effective date of the bond release. 

15.5. If the division disapproves the application for release of the bond or portion 

thereof, the notification specified in subsection 15.3. shall also state the reasons for 

disapproval, recommending corrective actions necessary to secure the release, and 

allowing an opportunity for a public hearing. 

15.6. The division shall notify the municipality in which the well is located by 

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certified mail at least 30 days prior to the release of the bond. 

16. The following guidelines will govern the Forfeiture of Bonds. 

16.1. The division shall take action to forfeit the bond if any of the following 

occur: 

16.1.1. The operator refuses or is unable to conduct plugging and site restoration. 

16.1.2. Noncompliance as to the conditions of a permit issued by the division. 

16.1.3. The operator defaults on the conditions under which the bond was 

accepted. 

16.2. In the event forfeiture of the bond is necessary, the matter will be 

considered by the Board. 

16.3. For matters of bond forfeiture, the division shall send written notification to 

the parties identified in subsection 15.3., in addition to the notice requirements of 

the Board procedural rules. 

16.4. After proper notice and hearing, the Board may order the division to do any 

of the following: 

16.4.1. Proceed to collect the forfeited amount as provided by applicable laws for 

the collection of defaulted bonds or other debts. 

16.4.2. Use funds collected from bond forfeiture to complete the plugging and 

restoration of the well or wells to which bond coverage applies. 

16.4.3. Enter into a written agreement with the operator or another party to 

perform plugging and restoration operations in accordance with a compliance 

schedule established by the division as long as such party has the ability to perform 

the necessary work. 

16.4.4. Allow a surety to complete the plugging and restoration, if the surety can 

demonstrate an ability to complete the plugging and restoration. 

16.4.5. Any other action the Board deems reasonable and appropriate. 

16.5. In the event the amount forfeited is insufficient to pay for the full cost of the 

plugging and restoration, the division may complete or authorize completion of 

plugging and restoration and may recover from the operator all costs of plugging and 

restoration in excess of the amount forfeited. 

16.6. In the event the amount of bond forfeited was more than the amount 

necessary to complete plugging and restoration, the unused funds shall be returned 

by the division to the party from whom they were collected. 

16.7. In the event the bond is forfeited and there exists any unplugged well or 

wells previously covered under the forfeited bond, then the operator must establish 

new bond coverage in accordance with these rules. 

16.8. If the operator requires new bond coverage under the provisions of 

subsection 16.7., then the division will notify the operator and specify a reasonable 

period, not to exceed 90 days, to establish new bond coverage. 

R649-3-2. Location And Siting of Vertical Wells and Statewide 

Spacing for Horizontal Wells.

1. In the absence of special orders of the board establishing drilling units or 

authorizing different well density or location patterns for particular pools or parts 

thereof, each oil and gas well shall be located in the center of a 40 acre quarterUT Admin Code R649-3. Drilling and Operating Practices. May 1, 2012 Page 9 of 41

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quarter section, or a substantially equivalent lot or tract or combination of lots or 

tracts as shown by the most recent governmental survey, with a tolerance of 200 feet 

in any direction from the center location, a "window" 400 feet square. 

1.1.No oil or gas well shall be drilled less than 920 feet from any other well 

drilling to or capable of producing oil or gas from the same pool. 

1.2. No oil or gas well shall be completed in a known pool unless it is located more 

than 920 feet from any other well completed in and capable of producing oil or gas 

from the same pool. 

2. The division shall have the administrative authority to determine the pattern 

location and siting of wells adjacent to an area for which drilling units have been 

established or for which a request for agency action to establish drilling units has 

been filed with the board and adjacent to a unitized area, where there is sufficient 

evidence to indicate that the particular pool underlying the drilling unit or unitized 

area may extend beyond the boundary of the drilling unit or unitized area and the 

uniformity of location patterns is necessary to ensure orderly development of the 

pool. 

3. In the absence of special orders of the Board, no portion of the horizontal 

interval within the potentially productive formation shall be closer than six hundredsixty (660) feet to a drilling or spacing unit boundary, federally unitized area 

boundary, uncommitted tract within a unit, or boundary line of a lease not 

committed to the drilling of such horizontal well. 

4. The surface location for a horizontal well may be anywhere on the lease. 

5. Any horizontal interval shall not be closer than one thousand three hundred 

and twenty (1,320) feet to any vertical well completed in and producing from the 

same formation. Vertical wells drilled to and completed in the same formation as in a 

horizontal well are subject to applicable drilling unit orders of the board or the other 

conditions of this rule that do not specifically pertain to horizontal wells and may be 

drilled and produced as provided therein. 

6. A temporary six hundred and forty (640) acre spacing unit, consisting of the 

governmental section in which the horizontal well is located, is established for the 

orderly development of the anticipated pool. 

7. In addition to any other notice required by the statute or these rules, notice of 

the Application for Permit to Drill for a horizontal well shall be given by certified 

mail to all owners within the boundaries of the designated temporary spacing unit. 

8. Horizontal wells to be located within federally supervised units are exempt 

from the above referenced conditions of 5, 6 and 7.

9. Exceptions to any of the above referenced conditions of 3 through 7 may be 

approved upon proper application pursuant to R649-3-3, Exception to Location and 

Siting of Wells, or R649-10, Administrative Procedures. 

10. Additional horizontal wells may be approved by order of the Board after 

hearing brought upon by a Request for Agency Action (Petition) filed in accordance 

with the Board's Procedural Rules. 

R649-3-3. Exception to Location and Siting of Wells.

1. The division shall have the administrative authority to grant an exception to the 

locating and siting requirements of R649-3-2 or an order of the board establishing 

oil or gas well drilling units after receipt from the operator of the proposed well of 

the following items: 

1.1. Proper written application for the exception well location. 

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1.2. Written consent from all owners within a 460 foot radius of the proposed well 

location when such exception is to the requirements of R649-3-2, or; 

1.3. Written consent from all owners of directly or diagonally offsetting drilling 

units when such exception is to an order of the board establishing oil or gas well 

drilling units. 

2. If for any reason the division shall fail or refuse to approve such an exception, 

the board may, after notice and hearing, grant an exception. 

3. The application for an exception to R649-3-2 or board drilling unit order shall 

state fully the reasons why such an exception is necessary or desirable and shall be 

accompanied by a plat showing: 

3.1. The location at which an oil or gas well could be drilled in compliance with 

R649-3-2 or Board drilling unit order. 

3.2. The location at which the applicant requests permission to drill. 

3.3. The location at which oil or gas wells have been drilled or could be drilled, in 

accordance with R649-3-2 or board drilling unit order, directly or diagonally 

offsetting the proposed exception. 

3.4. The names of owners of all lands within a 460 foot radius of the proposed 

well location when such exception is to the requirements of R649-3-2, or 

3.5. The names of owners of all directly or diagonally offsetting drilling units 

when such exception is to an order of the board establishing oil or gas drilling units. 

4. No exception shall prevent any owner from drilling an oil or gas well on 

adjacent lands, directly or diagonally offsetting the exception, at locations permitted 

by R649-3-2, or any applicable order of the board establishing oil or gas well drilling 

units for the pool involved. 

5. Whenever an exception is granted, the board or the division may take such 

action as will offset any advantage that the person securing the exception may obtain 

over other producers by reason of the exception location. 

R649-3-4. Permitting of Wells to be Drilled, Deepened or PluggedBack.

1. Prior to the commencement of drilling, deepening or plugging back of any well, 

exploratory drilling such as core holes and stratigraphic test holes, or any surface 

disturbance associated with such activity, the operator shall submit Form 3, 

Application for Permit to Drill, Deepen, or Plug Back and obtain approval. Approval 

shall be given by the division if it appears that the contemplated location and 

operations are not in violation of any rule or order of the board for drilling a well. 

2. The following information shall be included as part of the complete Application 

for Permit to Drill, Deepen, or Plug Back. 

2.1. The telephone number of the person to contact if additional information is 

needed. 

2.2. Proper identification of the lease as state, federal, Indian, or fee. 

2.3. Proper identification of the unit, if the well is located within a unit. 

2.4. A plat or map, preferably on a scale of one inch equals 1,000 feet, prepared 

by a licensed surveyor or engineer, that shows the proposed well location. For 

directional wells, both surface and bottomhole locations should be marked. 

2.5. A copy of the Division of Water Rights approval or the identifying number of 

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the approval for use of water at the drilling site.

2.6. A drilling program containing the following information shall also be 

submitted as part of a complete APD. 

2.6.1. The estimated tops of important geologic markers. 

2.6.2. The estimated depths at which the top and the bottom of anticipated water, 

oil, gas, or other mineral-bearing formations are expected to be encountered, and the 

owner's or operator's plans for protecting such resources. 

2.6.3. The owner's or operator's minimum specifications for pressure control 

equipment to be used and a schematic diagram thereof showing sizes, pressure 

ratings or API series, proposed testing procedures and testing frequency. 

2.6.4. Any supplementary information more completely describing the drilling 

equipment and casing program as required by Form 3, Application for Permit to 

Drill, Deepen, or Plug Back. 

2.6.5. The type and characteristics of the proposed circulating medium or 

mediums to be employed in drilling, the quantities and types of mud and weighting 

material to be maintained, and the monitoring equipment to be used on the mud 

system. 

2.6.6. The anticipated type and amount of testing, logging, and coring. 

2.6.7. The expected bottomhole pressure and any anticipated abnormal pressures 

or temperatures or potential hazards, such as hydrogen sulfide, H2

S rules are found 

in R649-3-12 expected to be encountered, along with contingency plans for 

mitigating such identified hazards. 

2.6.8. Any other facets of the proposed operation that the lessee or operator 

desires to point out for the division's consideration of the application. 

2.6.9. If an Application for Permit to Drill, Deepen, or Plug Back is for a proposed 

horizontal well, a horizontal well diagram clearly showing the well bore path from 

the surface through the terminus of the lateral shall be submitted. 

2.7. Form 5, Designation of Agent or Operator shall be filed when the operator is 

a person other than the owner. 

2.8. If located on State or Fee surface, an APD will not be approved until an 

Onsite Predrill Evaluation is performed as outlined in R649-3-18. 

3. Two legible copies, carbon or otherwise, of the APD filed with the appropriate 

federal agency may be used in lieu of the forms prescribed by the board. 

4. Approval of the APD shall be valid for a period of 12 months from the date of 

such approval. Upon approval of an APD, a well will be assigned an API number by 

the division. The API number should be used to identify the permitted well in all 

future correspondence with the division. 

5. If a change of location or drilling program is desired, an amended APD shall be 

filed with the division and its approval obtained. If the new location is at an 

authorized location in the approved drilling unit, or the change in drilling program 

complies with the rules for that area, the change may be approved verbally or by 

telegraph. Within five days after obtaining verbal or telegraphic authorization, the 

operator shall file a written change application with the division. 

6. After a well has been completed or plugged and abandoned, it shall not be 

reentered without the operator first submitting a new APD and obtaining the 

division's approval. Approval shall be given if it appears that a bond has been 

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furnished or waived, as required by R649-3-1, Bonding, and the contemplated 

work is not in violation of any rule or order of the board. 

7. An operator or owner who applies for an APD in an area not subject to a special 

order of the board establishing drilling units, may contemporaneously or 

subsequently file a Request for Agency Action to establish drilling units for an area 

not to exceed the area reasonably projected by the operator or owner to be underlaid 

by the targeted reservoir. 

8. An APD for a well within the area covered by a proper Request for Agency 

Action that has been filed by an interested person, or the division or the board on its 

own motion, for the establishment of drilling units or the revision of existing drilling 

units for the spacing of wells shall be held in abeyance by the division until such time 

as the matter has been noticed, fully heard and determined. 

9. An exception to R649-3-4-8 shall be made and a permit shall be issued by the 

division if an owner or operator files a sworn statement demonstrating to the 

division's satisfaction that on and after the date the Request for Agency Action 

requesting the establishment of drilling units was filed, or the action of the division 

or board was taken; and 

9.1. The owner or operator has the right or obligation under the terms of an 

existing contract to drill the requested well; or 

9.2. The owner or operator has a leasehold estate or right to acquire a leasehold 

estate under a contract that will be terminated unless he is permitted to commence 

the drilling of the required well before the matter can be fully heard and determined 

by the board. 

R649-3-5. Identification.

1. Every drilling and producible well shall be identified by a sign posted on the 

derrick or in a conspicuous place near the well. 

2. The sign shall be of durable construction. The lettering on the sign shall be kept 

in a legible condition and shall be large enough to be legible under normal conditions 

at a distance of 25 feet. 

3. The wells on each lease or property shall be numbered in nonrepetitive, logical, 

and distinctive sequence. Each sign shall show the number or name of the well, the 

name of the owner or operator, the lease name, and the location of the well by 

quarter section, township, and range. 

R649-3-6. Drilling Operations.

1. Drilling operations shall be conducted according to the drilling program 

submitted on the original APD and as approved by the division. Any change of plans 

to the original drilling program shall be submitted to the division by using Form 9, 

Sundry Notices and Reports on Wells and shall receive division approval prior to 

implementation. A change of plans necessary because of emergency conditions may 

be implemented without division approval. The operator shall provide the division 

with verbal notice of the emergency change within 24 hours and written notice 

within five days. 

2. An operator of a drilling well as designated in R649-2-4 shall comply with 

reporting requirements as follows: 

2.1. The spudding in of a well shall be reported to the division within 24 hours. 

The report should include the well name and number, drilling contractor, rig number 

and type, spud date and time, the date that continuous drilling will commence, the 

name of the person reporting the spud, and a contact telephone number. 

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2.2. The operator shall file Form 6, Entity Action Form with the division within 

five working days of spudding in a well. The division will assign the well an entity 

number that will identify the well on the operator's monthly oil and gas production 

and disposition reports. 

2.3. The operator shall notify the division 24 hours in advance of all testing to be 

performed on the blowout preventer equipment on a well. 

2.4. The operator shall submit a monthly status report for each drilling well on 

Form 9, Sundry Notices and Reports on Wells. The report should include the well 

depth and a description of the operations conducted on the well during the month. 

The report shall be submitted no later than the fifth day of the following calendar 

month until such time as the well is completed and the well completion report is 

filed. 

2.5. The operator shall notify the division 24 hours in advance of all casing tests 

performed in accordance with R649-3-13. 

2.6. The operator shall report to the division all fresh water sand encountered 

during drilling on Form 7, Report of Water Encountered During Drilling, The report 

shall be filed with Form 8, Well Completion or Recompletion Report and Log. 

R649-3-7. Well Control.

1. When drilling in wildcat territory, the owner or operator shall take all 

reasonably necessary precautions for keeping the well under control at all times and 

shall provide, at the time the well is started, proper high pressure fittings and 

equipment. All pressure control equipment shall be maintained in good working 

condition at all times. 

2. In all proved areas, the use of blowout prevention equipment "BOPE" shall be 

in accordance with the established and approved practice in the area. All pressure 

control equipment shall be maintained in good working condition at all times. 

3. Upon installation, all ram type BOPE and related equipment, including casing, 

shall be tested to the lesser of the full manufacturer's working pressure rating of the 

equipment, 70% of the minimum internal yield pressure of any casing subject to test, 

or one psi/ft of the last casing string depth. Annular type BOPE are to be tested in 

conformance with the manufacturer's published recommendations. The operator 

shall maintain records of such testing until the well is completed and will submit 

copies of such tests to the division if required. 

4. In addition to the initial pressure tests, ram and annular type preventers shall 

be checked for physical operation each trip. All BOPE components, with the 

exception of an annular type blowout preventer, shall be tested monthly to the lesser 

of 50% of the manufacturer's rated pressure of the BOPE, the maximum anticipated 

pressure to be contained at the surface, one psi/ft of the last casing string depth, or 

70% of the minimum internal yield pressure of any casing subject to test. 

5. If a pressure seal in the assembly is disassembled, a test of that seal shall be 

conducted prior to the resumption of any drilling operation. A shell test of the 

affected seal shall be adequate. If the affected seal is integral with the BOP stack, 

either pipe or blind ram, necessitating a test plug to be set in order to test the seal, 

the division may grant approval to proceed without testing the seal if necessary for 

prudent operations. 

6. All tests of BOPE shall be noted on the driller's log, IADC report book, or 

equivalent and shall be available for examination by the director or an authorized 

agent during routine inspections. 

7. BOPE used in possible or probable hydrogen sulfide or sour gas formations 

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shall be suitable for use in such areas. 

R649-3-8. Casing Program.

1. The method of cementing casing in the hole shall be by pump and plug method, 

displacement method, or other method approved by the division. 

2. When drilling in wildcat territory or in any field where high pressures are 

probable, the conductor and surface strings of casing must be cemented throughout 

their lengths, unless another procedure is authorized or prescribed by the division, 

and all subsequent strings of casing must be securely anchored. 

3. In areas where the pressures and formations to be encountered during drilling 

are known, sufficient surface casing shall be run to: 

3.1. Reach a depth below all known or reasonably estimated, utilizable, domestic, 

fresh water levels. 

3.2. Prevent blowouts or uncontrolled flows. 

4. The casing program adopted must be planned to protect any potential oil or gas 

horizons penetrated during drilling from infiltration of waters from other sources 

and to prevent the migration of oil, gas, or water from one horizon to another. 

R649-3-9. Protection of Upper Productive Strata.

1. No well shall be deepened for the purpose of producing oil or gas from a lower 

stratum until all upper productive strata are protected, either permanently by casing 

and cementing or temporarily through the use of tubing and packer, to the 

satisfaction of the division. 

2. In any well that appears to have defective, poorly cemented, or corroded casing 

that will permit or may create underground waste or may contaminate underground 

or surface fresh water, the operator shall proceed with diligence to use the 

appropriate method and means to eliminate such hazard of underground waste or 

contamination of fresh water. If such hazard cannot be eliminated, the well shall be 

properly plugged and abandoned. 

3. Natural gas that is encountered in substantial quantities in any section of a 

drilled hole above the ultimate objective shall be shut off with reasonable diligence, 

either by mudding, casing or other approved method, and shall be confined to its 

original source to the satisfaction of the division. 

R649-3-10. Tolerances for Vertical Drilling.

1. Deviation from the vertical for short distances is permitted in the drilling of a 

well without special approval to straighten the hole, sidetrack junk, or correct other 

mechanical difficulties. 

2. All wells shall be drilled such that the surface location of the well and all points 

along the intended well bore shall be within the tolerances allowed by R649-3-2, 

Location and Siting of Vertical Wells and Statewide Spacing for Horizontal Wells, or 

the appropriate board order. 

R649-3-11. Directional Drilling.

1. Except for the tolerances allowed under R649-3-10, no well may be 

intentionally deviated unless the operator shall first file application and obtain 

approval from the division. 

1.1. An application for directional drilling may be approved by the division 

without notice and hearing when the applicant is the owner of all the oil and gas 

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within a radius of 460 feet from all points along the intended well bore, or the 

applicant has obtained the written consent of the owner to the proposed directional 

drilling program. 

1.2. An application for directional drilling may be included as part of the initial 

APD for a proposed well. 

2. An application for directional drilling shall include the following information: 

2.1. The name and address of the operator. 

2.2. The lease name, well number, field name, reservoir name, and county where 

the proposed well is located. 

2.3. A plat or sketch showing the distance from the surface location to section and 

lease lines, the target location within the intended producing interval, and any point 

along the intended well bore outside the 460 foot radius for which the consent of the 

owner has been obtained. 

2.4. The reason for the intentional deviation. 

2.5. The signature of designated agent or representative of operator. 

3. Within 30 days following completion of a directionally drilled well, a complete 

angular deviation and directional survey of the well obtained by an approved well 

survey company shall be filed with the division, together with other regularly 

required reports. 

R649-3-12. Drilling Practices for Hydrogen Sulfide H2S Areas and 

Formations.

1. This rule shall apply to drilling, redrilling, deepening, or plugging back 

operations in areas where the formations to be penetrated are known to contain or 

are expected to contain H2

S in excess of 20 ppm and to areas where the presence or 

absence thereof is unknown. 

2. A written contingency plan, providing details of actions to be taken to alert and 

protect operating personnel and members of the public in the event of an accidental 

release of H2S gas shall be submitted to the division as part of the initial APD for a 

well or as a sundry notice. 

3. All proposed drill site locations shall be planned to obtain the maximum safety 

benefits consistent with the rig configuration, terrain, prevailing winds, etc. 

3.1. The drilling rig shall, where possible, be situated so that prevailing winds 

blow across the rig in a direction toward the reserve pit and away from escape routes. 

3.2. On-site trailers shall be located to allow reasonably safe distances from both 

the well and the outlet of the flare line. 

4. At least two cleared areas shall be designated as crew briefing or safety areas. 

4.1. Both areas shall be located at least 200 feet from the well, with at least one 

area located generally upwind from the well. 

5. Protective equipment shall be provided by the operator or its drilling 

contractor for operating personnel and shall include the following: 

5.1. An adequate number of positive pressure type self-contained breathing 

apparatus to allow all personnel normally involved on a drilling location immediate 

access to such equipment, with a minimum of one working apparatus available for 

the immediate use of each rig hand in emergencies. 

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5.2. Chalk boards or note pads to be used for communication when wearing 

protective breathing apparatus. 

5.3. First aid supplies. 

5.4. One resuscitator complete with medical oxygen.

5.5. A litter or stretcher. 

5.6. Harnesses and lifelines. 

5.7. A telephone, radio, mobile phone, or other communication device that 

provides emergency two-way communication from a safe area near the well location. 

6. Each drill site shall have an H2S detection and monitoring system that 

activates audible and visible alarms when the concentration of H2S reaches the 

threshold limit of 20 ppm in air. This equipment shall have a rapid response time 

and be capable of sensing a minimum of ten ppm H2S in air, with at least three 

sensing points, located at the shale shaker, on the derrick floor, and in the cellar. 

Other sensing points shall be located at other critical areas where H2

S might 

accumulate. Portable H2

S detection equipment capable of sensing an H2S 

concentration of 20 ppm shall be available for all working personnel and shall be 

equipped with an audible warning signal. 

7. Equipment to indicate wind direction at all times shall be installed at 

prominent locations. At least two wind socks or streamers shall be located at 

separate elevations at the well location and shall be easily visible from all areas of the 

location. Windsocks or streamers shall be located in illuminated areas for night 

operations. 

8. When H2

S is encountered during drilling, well marked, highly visible warning 

signs shall be displayed at the rig and along all access routes to the well location. 

8.1. The signs shall warn of the presence of H2S and shall prohibit approach to 

the well location when red flags are displayed. 

8.2. Red flags shall be displayed when H2S is present in concentrations greater 

than 20 ppm in air as measured on the equipment required under R649-3-12-6. 

9. Unless adequate natural ventilation is present, portable fans or ventilation 

equipment shall be located in work areas to disperse H2S when it is encountered. 

10. A flare system shall be utilized to safely gather and burn H2

S bearing gas.

10.1. Flare lines shall be located as far from the operating site as feasible and shall 

be located in a manner to compensate for wind changes. 

10.2. The outlets of all flare lines shall be located at least 150 feet from the well 

head unless otherwise approved by the division. 

11. Sufficient quantities of additives shall be maintained on location to add to the 

mud system to scavenge or neutralize H2S. 

R649-3-13. Casing Tests.

1. In order to determine the integrity of the casing string set in the well, the 

operator shall, unless otherwise requested by the division, perform a pressure test of 

the casing to the pressures specified under R649-3- 7.4 before drilling out of any 

casing string, suspending drilling operations, or completing the well. 

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R649-3-14. Fire Hazards on the Surface.

1. All rubbish or debris that might constitute a fire hazard shall be removed to a 

distance of a least 100 feet from the well location, tanks, separator, or any structure. 

All waste oil or gas shall be burned or disposed of in a manner to avert creation of a 

fire hazard. 

2. Any gas other than poisonous gas escaping from the well during drilling 

operations shall be, so far as practicable, conducted to a safe distance from the well 

site and burned in a suitable flare. 

R649-3-15. Pollution and Surface Damage Control.

1. The operator shall take all reasonable precautions to avoid polluting lands, 

streams, reservoirs, natural drainage ways, and underground water. 

1.1. The owner or operator shall carry on all operations and maintain the property 

at all times in a safe and workmanlike manner having due regard for the preservation 

and conservation of the property and for the health and safety of employees and 

people residing in close proximity to those operations. 

1.2. At a minimum, the owner or operator shall: 

1.2.1. Take reasonable steps to prevent and shall remove accumulations of oil or 

other materials deemed to be fire hazards from the vicinity of well locations, lease 

tanks and pits. 

1.2.2. Remove from the property or store in an orderly manner, all scrap or other 

materials not in use. 

1.2.3. Provide secure workmanlike storage for chemical containers, barrels, 

solvents, hydraulic fluid, and other non-exempt materials. 

1.2.4. Maintain tanks in a workmanlike manner that will preclude leakage and 

provide for all applicable safety measures, and construct berms of sufficient height 

and width to contain the quantity of the largest tank at the storage facility. 

1.2.4.1. The use of crude or produced water storage tanks without tops is strictly 

prohibited except during well testing operations. 

1.2.5. Catch leaks and drips, contain spills, and cleanup promptly. 

1.2.6. Waste reduction and recycling should be practiced in order to help reduce 

disposal volumes. 

1.2.7. Produced water, tank bottoms and other miscellaneous waste should be 

disposed of in a manner that is in compliance with these rules and other state, 

federal, or local regulations or ordinances. 

1.2.8. In general, good housekeeping practices should be used. 

R649-3-16. Reserve Pits and Other On-site Pits.

1. Small onsite oil field pits including, but not limited to, reserve pits, emergency 

pits, workover and completion pits, storage pits, pipeline drip pits, and sumps shall 

be located and constructed in such a manner as to contain fluids and not cause 

pollution of waters and soils. They shall be located and constructed according to the 

Division guidelines for onsite pits. See Ranking Criteria for Reserve and Onsite Pit 

Liner Requirements, on the Oil, Gas and Mining web page. 

2. Reserve pit location and construction requirements including liner 

requirements will be discussed at the predrill site evaluation. Special stipulations 

concerning the reserve pit will be included as part of the Division's approval to drill. 

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3. Following drilling and completion of the well the reserve pit shall be closed 

within one year, unless permission is granted by the Division for a longer period. 

4. Pit contents shall meet the Division's Cleanup Levels (guidance document for 

numeric clean-up levels) or background levels prior to burial. 

5. The contents may require treatment to reduce mobility and/or toxicity in order 

to meet cleanup levels. 

6. The alternative to meeting cleanup levels would be transporting of material to 

an appropriate disposal facility. 

R649-3-17. Inspection.

1. Inspection of wells shall be performed by the division to determine operator 

compliance with the rules and orders of the board. 

2. The inspection shall not interfere with the mechanical operation of facilities or 

equipment used in drilling and production operations. 

3. Inspections of operations involving a safety hazard shall not be conducted, nor 

shall an inspection be conducted that may cause a safety hazard. 

R649-3-18. On-site Predrill Evaluation.

1. An on-site predrill evaluation of drilling operations located on state or private 

land shall be scheduled and conducted by the division prior to approval of an APD 

and no later than 30 days after receipt by the division of a complete APD. 

1.1. An on-site predrill evaluation may be performed by the division prior to 

submittal of a complete APD at the written request of the operator. 

1.2. The division, the operator, and other persons associated with the surface 

management or construction of the well site shall attend the predrill evaluation. 

1.3. When appropriate, the operator's surveyor and archaeologist may also 

participate in the predrill evaluation. 

1.4. When the surface of the land involved is privately owned, the operator shall 

include in the APD the name, address, and telephone number of the private surface 

owner as shown on the real property records of the county where the well is located. 

1.5. The surface owner shall be invited by the division to attend the predrill 

evaluation. 

1.6. The surface owner's inability to attend the predrill evaluation shall not delay 

the scheduled evaluation. 

2. Special stipulations concerning surface use or justifications for well spacing 

exceptions may be addressed and developed at the predrill evaluations. 

2.1. Special stipulations shall be incorporated as conditions of the approved APD, 

together with any additional conditions determined by the division to be necessary 

following a review of the complete application. 

R649-3-19. Well Testing.

1. Each operator shall conduct a stabilized production test of at least 24 hours 

duration not later than 15 days following the completion or recompletion of any well 

for the production of oil or gas. 

1.1. The results of the test shall be reported in writing to the division within 15 

days after completion of the test. 

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1.2. Additional tests shall be made as requested by the division. 

2. The division may request subsurface pressure measurements on a sufficient 

number of wells in any pool to provide adequate data to determine reservoir 

characteristics. 

3. Upon written request, the division may waive or extend the time for conducting 

any test. 

4. A gas-oil ratio "GOR" test shall be conducted not later than 15 days following 

the completion or recompletion of each well in a pool that contains both oil and gas. 

4.1. The average daily oil production, the average daily gas production and the 

average GOR shall be recorded. 

4.2. The results of the GOR test shall be reported in writing to the division within 

15 days after completion of the test. 

4.3. A GOR test of at least 24 hours duration shall satisfy the requirements of 

R649-3-19-1. 

5. When the results of a multipoint test or other approved test for the 

determination of gas well potential have not been submitted to the division within 30 

days after completion or recompletion of any producible gas well, the division may 

order this test to be made. 

5.1. All data pertinent to the test shall be submitted to the division in legible, 

written form within 15 days after completion of the test. 

5.2. The performance of a multipoint or other approved test shall satisfy the 

requirements of R649-3- 19-1. 

6. All tests of any producible gas well will be taken in accordance with the Manual 

of Back-Pressure Testing of Gas Wells published by the Interstate Oil and Gas 

Compact Commission, with necessary modifications as approved by the division. 

R649-3-20. Gas Flaring or Venting.

1. Produced gas from an oil well, also known as associated gas or casinghead gas, 

may be flared or vented only in the following amounts: 

1.1. Up to 1,800 MCF of oil well gas may be vented or flared from an individual 

well on a monthly basis at any time without approval. 

1.2. During the period of time allowed for conducting the stabilized production 

test or other approved test as required by R649-3-19, the operator may vent or flare 

all produced oil well gas as needed for conducting the test. 

1.2.1. The operator shall not vent or flare gas that is not necessary for conducting 

the test or beyond the time allowed for conducting the test. 

1.3. During the first calendar month immediately following the time allowed for 

conducting the initial stabilized production test as required by R649-3-19.1, the 

operator may vent or flare up to 3,000 MCF of oil well gas without approval. 

1.4. Unavoidable or short-term oil well gas venting or flaring may occur without 

approval in accordance with R649-3-20.4, 4.1, 4.2, and 4.3. 

2. Produced gas from a gas well may be vented or flared only in the following 

amounts: 

2.1. During the period of time allowed for conducting the stabilized production 

test, the multipoint test, or other approved test as required by R649-3-19, the 

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operator may vent or flare all produced gas well gas as needed for conducting the 

test. 

2.2. The operator shall not vent or flare gas which is not necessary for conducting 

the tests or beyond the time allowed for conducting the tests. 

2.3. Unavoidable or short-term gas well gas venting or flaring may occur without 

approval in accordance with R649-3-20.4, 4.1, 4.2, and 4.3. 

3. If an operator desires to produce a well for the purpose of testing and 

evaluation beyond the time allowed by R649-3-19 and vent or flare gas in excess of 

the aforementioned limits of gas venting or flaring, the operator shall make written 

request for administrative action by the division to allow gas venting or flaring 

during such testing and evaluation. 

3.1. The operator shall provide any information pertinent to a determination of 

whether marketing or otherwise conserving the produced gas is economically 

feasible. 

3.2. Upon such request and based on the justification information presented, the 

division may authorize gas venting or flaring at unrestricted rates for up to 30 days of 

testing or no more than 50 MMCF of gas vented or flared, whichever is less. 

4. Once a well is completed for production and gas is being transported or 

marketed, the operator is allowed unavoidable or short-term gas venting or flaring 

without approval only in the following cases: 

4.1. Gas may be vented or released from oil storage tanks or other low pressure oil 

production vessels unless the division determines that the recovery of such vapors is 

warranted. 

4.2. Gas may be vented or flared from a well during periods of line failures, 

equipment malfunctions, blowouts, fires, or other emergencies if shutting in or 

restricting production from the well would cause waste or create adverse impact on 

the well or producing reservoir. 

4.3. The operator shall provide immediate notification to the division in all such 

cases in accordance with R649-3-32, Reporting of Undesirable Events. 

4.4. Upon notification, the division shall determine if gas venting or flaring is 

justified and specify conditions of approval if necessary. 

4.5. Gas may be vented or flared from a well during periods of well purging or 

evaluation tests not exceeding a period of 24 hours or a maximum of 144 hours per 

month. 

4.6. The operator shall provide subsequent written notification to the division in 

all such cases. 

5. If an operator wishes to flare or vent a greater amount of produced gas than 

allowed by this rule, the operator must submit a Request for Agency Action to the 

board to be considered as a formal board docket item. The request should include the 

following items: 

5.1. A statement justifying the need to vent or flare more than the allowable 

amount. 

5.2. A description of production test results. 

5.3. A chemical analysis of the produced gas. 

5.4. The estimated oil and gas reserves. 

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5.5. A description of the reinjection potential or other conservation oriented 

alternative for disposition of the produced gas. 

5.6. A description of the amount of gas used in lease operations. 

5.7. An economic evaluation supporting the operator's determination that 

conservation of the gas is not economically viable. The evaluation should utilize any 

engineering or geologic data available and should consider total well production, not 

just gas production, in presenting the profitability and costs for beneficial use of the 

gas. 

5.8. Any other information pertinent to a determination of whether marketing or 

otherwise conserving the produced gas is economically feasible. 

6. Upon review of the request for approval to vent or flare gas from a well, the 

board may elect to: 

6.1. Allow the requested venting or flaring of gas.

6.2. Restrict production until the gas is marketed or otherwise beneficially 

utilized. 

6.3. Take any other action the board deems appropriate in the circumstances. 

7. When gas venting or flaring from a well has not been approved by the division 

or the magnitude and duration of venting or flaring exceeds the amounts specified in 

these rules or any division or board approval, then the board may issue a formal 

order to alleviate the noncompliance and/or require the operator to appear before 

the board to provide justification of such venting or flaring. The division shall notify 

the appropriate governmental taxing and royalty agencies of any unapproved venting 

or flaring and of any subsequent board action. 

8. No extraction plant processing gas in Utah shall flare or vent such gas unless 

such venting or flaring is made necessary by mechanical difficulty of a very limited 

temporary nature or unless the gas vented or flared is of no commercial value. 

9. In the event of a more prolonged mechanical difficulty or in the event of plant 

shut-downs or curtailment because of scheduled or nonscheduled maintenance or 

testing operations or other reasons, or in the event a plant is unable to accept, 

process, and market all of the casinghead gas produced by wells connected to its 

system, the plant operator shall notify the division as soon as possible of the full 

details of such shut-down or curtailment, following which the division shall take such 

action as is necessary. 

R649-3-21. Well Completion and Filing of Well Logs.

1. For the purposes of this rule only, a well shall be determined to be completed 

when the well has been adequately worked to be capable of producing oil or gas or 

when well testing as required by the division is concluded. 

2. Within 30 days after the completion of any well drilled or redrilled for the 

production of oil or gas, Form 8, Well Completion or Recompletion Report and Log, 

shall be filed with the division, together with a copy of the electric and radioactivity 

logs, if run. 

3. In addition, one copy of all drillstem test reports, formation water analyses, 

porosity, permeability or fluid saturation determinations, core analyses and 

lithologic logs or sample descriptions if compiled, shall be filed with the division. 

4. As prescribed under R649-2-12, Test and Surveys, the directional, deviation 

and/or measurement- while-drilling (MWD) survey for a horizontal well shall be 

filed within 30 days of being run. Such directional, deviation and/or MWD survey 

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specifically related to well location or well bore path shall not be held 

confidential. Other MWD survey data that presents well log, or other geological, 

geophysical, or engineering information may be held confidential as provided in 

R649-2-11, Confidentiality of Well Log Information.

R649-3-22. Completion Into Two or More Pools.

1. The completion of a single well into more than one pool may be permitted by 

submitting an application to the division and securing its approval. 

1.1. The application shall be submitted on Form 9, Sundry Notice and Report and 

shall be accompanied by an exhibit showing the location of all wells on contiguous oil 

and gas leases or drilling units overlying the pool. 

1.2. The application shall set forth all material facts involved and the manner and 

method of completion proposed. 

2. If oil or gas is to be produced from two or more pools open to each other 

through the same string of casing so that commingling will take place, the 

application must also be accompanied by a description of the method used to 

account for and to allocate production from each pool so commingled. 

3. The application shall include an affidavit showing that the operator has 

provided a copy of the application to the owners of all contiguous oil and gas leases 

or drilling units overlying the pool. 

3.1. If none of these owners file a written objection to the application within 15 

days after the date the application is filed with the division, the application may be 

considered and approved by the division without a hearing. 

3.2. If a written objection is filed that cannot be resolved administratively, the 

application may be approved only after notice and hearing by the board. 

R649-3-23. Well Workover and Recompletion.

1. Requests for approval of a notice of intention to perform a workover or 

recompletion shall be filed by an operator with the division on Form 9, Sundry 

Notices and Reports on Wells, or if the operation includes substantial redrilling, 

deepening, or plugging back of an existing well, on Form 3, Application for Permit to 

Drill, Deepen or Plug Back. 

2. The division shall review the proposed workover or recompletion for 

conformance with the Oil and Gas Conservation General Rules and advise the 

operator of its decision and any necessary conditions of approval. 

3. Recompletions shall be conducted in a manner to protect the original 

completion interval(s) and any other known productive intervals. 

4. The same tests and reports are required for any well recompletion as are 

required following an original well completion. 

5. The applicant shall file a subsequent report of workover on Form 9, Sundry 

Notices and Reports, or a subsequent report of recompletion on Form 8, Well 

Completion or Recompletion Report and Log, within 30 days after completing the 

workover or recompletion operations. 

6. For the purpose of qualifying for a tax credit under Utah Code Ann. Section 59-

5-102(6), the operator on his behalf and on behalf of each working interest owner 

must file a request with the division on Form 15, Designation of Workover or 

Recompletion. The request must be filed within 90 days after completing the 

workover or recompletion operations. 

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7. A workover which may qualify under Utah Code Ann. Section 59-5-102(6) shall 

be downhole operations conducted to maintain, restore or increase the producibility 

or serviceability of a well in the geologic interval(s) that the well is currently 

completed in, but shall not include: 

7.1. Routine maintenance operations such as pump changes, artificial lift 

equipment or tubing repair, or other operations that do not involve changes to the 

wellbore configuration or the geologic interval(s) that it penetrates and that do not 

stimulate production beyond that which would be anticipated as the result of routine 

maintenance. 

7.2. Operations to convert any well for use as a disposal well or other use not 

associated with enhancing the recovery of hydrocarbons. 

7.3. Operations to convert a well to a Class II injection well for enhanced recovery 

purposes may qualify if the secondary or enhanced recovery project has received the 

necessary board approval. 

8. A recompletion that may qualify under Utah Code Ann. Section 59-5-102(6) 

shall be downhole operations conducted to reestablish producibility or serviceability 

of a well in any geologic interval(s). 

9. The division shall review the request for designation of a workover or 

recompletion and advise the operator and the State Tax Commission of its decision 

to approve or deny the operations for the purposes of Utah Code Ann. Section 59-5-

102(6). 

10. The division is responsible for approval of workover and recompletion 

operations that qualify for the tax credit. 

10.1. If the operator disagrees with the decision of the division, the decision may 

be appealed to the board. 

10.2. Appeals of all other workover and recompletion tax credit decisions should 

be made to the State Tax Commission. 

R649-3-24. Plugging and Abandonment of Wells.

1. Before operations are commenced to plug and abandon any well the owner or 

operator shall submit a notice of intent to plug and abandon to the division for its 

approval. 

1.1. The notice shall be submitted on Form DOGM-9, Sundry Notice and Report 

on Wells. 

1.2. A legible copy of a similar report and form filed with the appropriate federal 

agency may be used in lieu of the forms prescribed by the board. 

1.3. In cases of emergency the operator may obtain verbal or telegraphic approval 

to plug and abandon. 

1.4. Within five days after receiving verbal or telegraphic approval, the operator 

shall submit a written notice of intent to plug and abandon on Form 9. 

2. Both verbal and written notice of intent to plug and abandon a well shall 

contain the following information: 

2.1. The location of the well described by section, township, range, and county. 

2.2. The status of the well, whether drilling, producing, injecting or inactive. 

2.3. A description of the well bore configuration indicating depth, casing strings, 

cement tops if known, and hole size. 

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2.4. The tops of known geologic markers or formations. 

2.5. The plugging program approved by the appropriate federal agency if the well 

is located on federal or Indian land. 

2.6. An indication of when plugging operations will commence. 

3. A dry or abandoned well must be plugged so that oil, gas, water, or other 

substance will not migrate through the well bore from one formation to another. 

3.1. Unless a different method and procedure is approved by the division, the 

method and procedure for plugging the well shall be as follows: 

3.2. The bottom of the hole shall be filled to, or a bridge shall be placed at, the top 

of each producing formation open to the well bore, and a cement plug not less than 

100 feet in length shall be placed immediately above each producing formation open 

to the well bore. 

3.3. A solid cement plug shall be placed from 50 feet below a fresh water zone to 

50 feet above the fresh water zone, or a 100 foot cement plug shall be centered across 

the base of the fresh water zone and a 100 foot plug shall be centered across the top 

of the fresh water zone. 

3.4. At least ten sacks of cement shall be placed at the surface in a manner 

completely plugging the entire hole. If more than one string of casing remains at the 

surface, all annuli shall be so cemented. 

3.5. The interval between plugs shall be filled with noncorrosive fluid of adequate 

density to prevent migration of formation water into or through the well bore. 

3.6. The hole shall be plugged up to the base of the surface string with 

noncorrosive fluid of adequate density to prevent migration of formation water into 

or through the well bore, at which point a plug of not less than 50 feet of cement shall 

be placed. 

3.7. Any perforated interval shall be plugged with cement and any open hole 

porosity zone shall be adequately isolated to prevent migration of fluids. 

3.8. A cement plug not less than 100 feet in length shall be centered across the 

casing stub if any casing is cut and pulled, a second plug of the same length shall be 

centered across the casing shoe of the next larger casing. 

4. An alternative method of plugging, required under a federal or Indian lease, 

will be accepted by the division. 

5. Within 30 days after the plugging of any well has been accomplished, the 

owner or operator shall file a subsequent report of plugging with the division. The 

report shall give a detailed account of the following items: 

5.1. The manner in which the plugging work was carried out, including the nature 

and quantities of materials used in plugging and the location, nature, and extent by 

depths, of the plugs. 

5.2. Records of any tests or measurements made. 

5.3. The amount, size, and location, by depths of any casing left in the well. 

5.4. A statement of the volume of mud fluid used. 

5.5. A complete report of the method used and the results obtained, if an attempt 

was made to part any casing. 

6. Upon application to and approval by the division, and following assumption of 

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liability for the well by the surface owner, a well or other exploratory hole that 

may safely be used as a fresh water well need not be filled above the required sealing 

plugs set below the fresh water formation. The owner of the surface of the land 

affected may assume liability for any well capable of conversion to a water well by 

sending a letter assuming such liability to the division and by filing an application 

with and obtaining approval for appropriation of underground water from the 

Division of Water Rights. 

7. Unless otherwise approved by the division, all abandoned wells shall be 

marked with a permanent monument showing the well number, location, and name 

of the lease. The monument shall consist of a portion of pipe not less than four 

inches in diameter and not less than ten feet in length, of which four feet shall be 

above the ground level and the remainder shall be securely embedded in cement. The 

top of the pipe must be permanently sealed. 

8. If any casing is to be pulled after a well has been abandoned, a notice of intent 

to pull casing must be filed with the division and its approval obtained before the 

work is commenced. 

8.1. The notice shall include full details of the contemplated work. If a log of the 

well has not already been filed with the division, the notice shall be accompanied by a 

copy of the log showing all casing seats as well as all water strata and oil and gas 

shows. 

8.2. Where the well has been abandoned and liability has been terminated with 

respect to the bond previously furnished under R649-3-1, a $10,000 plugging bond 

shall be filed with the division by the applicant. 

R649-3-25. Underground Disposal of Drilling Fluids.

1. Operators shall be permitted to inject and dispose of reserve pit drilling fluids 

downhole in a well upon submitting an application for such operations to the 

division and obtaining its approval. Injection of reserve pit fluids shall be considered 

by the division on a case-by-case basis. 

2. Each proposed injection procedure will be reviewed by the division for 

conformance to the requirements and standards for permitting disposal wells under 

R649-5-2 to assure protection of fresh-water resources. 

3. The subsurface disposal interval shall be verified by temperature log, or 

suitable alternative, during the disposal operation. 

4. The division shall designate other conditions for disposal, as necessary, in 

order to ensure safe, efficient fluid disposal. 

R649-3-26. Seismic Exploration.

1. Form 1, Application for Permit to Conduct Seismic Exploration shall be 

submitted to the division by the seismic contractor at least seven days prior to 

commencing any type of seismic exploration operations. In cases of emergency, 

approval may be obtained either verbally or by telegraphic communication. 

1.1. Changes of plans or line locations may be implemented in an emergency 

situation without division approval. 

1.2. Within five days after the change is performed, the seismic contractor shall 

submit written notice of the change to the division. 

1.3. The permit may be revoked at any time by the division for failure to comply 

with the rules and orders of the board. 

1.4. Any request to deviate from the general plugging and operations procedures 

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of these rules shall be included on the permit application. 

1.5. The name, address, and telephone number of the seismic contractor's local 

contact shall be submitted to the division as soon as determined if not available when 

the permit application is submitted. 

1.6. After review of the application for a seismic permit, the division may require 

written permission of the owner of the surface of the affected land if it is determined 

that the seismic operation may significantly impact any building, pipeline, water 

well, flowing spring, or other cultural or natural feature in the area. 

1.7. The permit will be in effect for six months from the date of approval. The 

permit may be extended upon application to and approval by the division. 

2. Bonding shall not be required for seismic exploration requiring the drilling of 

shot holes. 

3. Seismic contractors shall give the division at least 24 hours advance notice of 

the plugging of seismic holes. The notice shall include the date and time the plugging 

activities are expected to commence, the name and address of the seismic contractor 

responsible for the holes, and, if different, the name and address of the hole plugging 

company. 

4. Unless the seismic contractor can prove to the satisfaction of the division that 

another method will provide adequate protection to ground water resources and 

other man-made or natural features and will provide long-term land stability, the 

following procedures shall be required for the conduct of seismic operations and hole 

plugging: 

4.1. Seismic contractors shall take reasonable precautions to avoid conducting 

shot hole operations closer than 1,320 feet to any building, pipeline, water well, 

flowing spring, or other cultural/natural feature, e.g., a historical monument, 

marker, or structure, that may be adversely affected by the seismic operations. 

4.2. When nonartesian water is encountered while drilling seismic shot holes, the 

holes shall be filled from the bottom up with a high grade bentonite/water slurry 

mixture. 

4.3. The slurry shall have a density that is at least four percent greater than the 

density of fresh water and shall have a marsh funnel viscosity of at least 60 seconds 

per quart. 

4.4. The density and viscosity of the slurry are to be measured prior to adding 

cuttings. Cuttings not added to the slurry are to be disposed of in accordance with 

R649-3-26-4.6. 

4.5. Upon approval by the division, any other suitable plugging material 

commonly used in the industry may be substituted for the bentonite/water slurry as 

long as the physical characteristics of the substitute plugging material are at least 

comparable to those of the bentonite/water slurry. 

4.6. The hole shall be filled with the substitute plugging material from the bottom 

up to a depth of three feet below ground level. 

4.7. A nonmetallic permaplug shall be set at a depth of three feet. The remaining 

hole shall be filled and tamped to the surface with cuttings and native soil. 

4.8. The permaplug shall be imprinted with an approved identification number or 

mark. 

4.9. When drilling with air only, and in completely dry holes, plugging may be 

accomplished by returning the cuttings to the holes, tamping the returned cuttings to 

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the depth of three feet below ground level, and setting the permaplug topped with 

more cuttings and soil. A small mound shall be left over the hole for settling 

allowance. 

4.10. If artesian flow, water flowing at the surface, is encountered in the drilling 

of any seismic hole, cement shall be used to seal off the water flow to prevent crossflow, erosion, or contamination of fresh water supplies. 

4.11. Unless severe weather conditions prevent access, the holes shall be 

cemented immediately. 

4.12. Approval may be granted to seismic operator to plug a flowing hole in 

another manner, if it is proved to this division that the alternate method will provide 

adequate protection to ground water resources and provide long term land stability. 

4.13. The owner of the surface of the land affected may assume liability for a 

seismic hole capable of conversion to a water well by sending a letter assuming such 

liability to the division and by filing an application with and obtaining approval for 

appropriation of underground water from the Division of Water Rights. 

4.14. Shotholes shall be properly plugged and abandoned as soon as practical 

after the shot has been fired. 

4.15. No shothole shall be left unplugged for more than 30 days without approval 

of the division. 

4.16. Until properly plugged, shotholes shall be covered with a tin hat or other 

similar cover. 

4.17. The hats shall be imprinted with the seismic contractor's name or initials. 

4.18. Any slurry, drilling fluids, or cuttings that are deposited on the surface 

around the seismic hole shall be raked or otherwise spread out to a height of not 

more than one inch above the surface, so that the growth of the natural grasses or 

foliage will not be impaired. 

4.19. Restoration plans required by the Mined Land Reclamation Act, Chapter 8 

of Title 40, or by any other surface management agency will be accepted by the 

division. 

4.20. The surface area around each seismic shothole shall be reclaimed and 

reseeded to its original condition insofar as such restoration is practical and is 

required by the surface management agency. 

4.21. All flagging, stakes, cables, cement, or mud sacks shall be removed from the 

drill site and disposed of in an acceptable manner.

5. Upon application to the division, approval may be obtained for preplugging of 

shotholes using coarse bentonite material or a suitable alternative used in the 

industry. Preplugging of holes in this manner shall be performed according to the 

following procedures: 

5.1. A sales receipt indicating proof of purchase of an adequate amount of coarse 

bentonite to properly plug all shotholes shall be submitted to the division upon 

request. 

5.2. For shotholes drilled with air that are completely dry, the seismic contractor 

shall have the option of preplugging with the coarse bentonite material or of using an 

alternate plugging material under R649-3-26-4.3. 

5.3. For conventionally drilled, wet holes, enough approved material shall be used 

to cover the initial water level, i.e., the depth of the initial water level in the hole prior 

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to adding coarse bentonite material shall be equal to the final plug depth. 

5.4. An additional ten feet of approved material shall be placed above this depth 

and hole cuttings shall be used to fill the remainder of the hole to a depth of three 

feet below ground level. 

5.5. A nonmetallic plug imprinted with an approved identification number or 

mark shall be installed at this depth. 

5.6. The remaining three feet of hole shall be filled and tamped to the surface with 

cuttings and native soil. 

5.7. The remaining cuttings shall be raked or spread to a height not to exceed one 

inch above ground level. 

5.8. When using heliportable drills and insufficient cuttings are available, the 

hole shall be preplugged with bentonite plugging material or an approved alternate 

material to a depth of three feet below ground level. 

5.9. Installation of a nonmetallic plug and filling the remainder of the hole shall 

be performed as required by R649-3-26-5.3. 

5.10. The coarse bentonite plugging material shall have the following 

specifications - chemically unaltered sodium bentonite, coarse ground, three quarter 

inch maximum size, not more than 19% moisture content and not more than 15% 

inert solids by volume. 

6. Form 2, Seismic Exploration Completion Report shall be submitted to the 

Division within 60 days after completion of each seismic exploration project. The 

report shall include: Certification by the seismic contractor that all shot holes have 

been plugged as prescribed by the division. 

R649-3-27. Multiple Mineral Development.

1. Drilling operations conducted in areas designated by the board for multiple 

mineral development shall comply with all rules or orders of the board for drilling, 

casing, cementing, and plugging except as the general rules or orders may be 

modified by this rule. 

2. It is the policy of the division to promote the development of all mineral 

resources on land under its jurisdiction. Consistent with that policy, operators 

engaged in oil and gas operations on lands on which operators are exploring for and 

developing mineral resources other than oil and gas may enter into a cooperative 

agreement with these other operators with respect to multiple mineral development. 

The agreement shall define: 

2.1. The extent and limits of liability when one operator, either intentionally or 

unintentionally, interferes with or damages the deposits of another. 

2.2. The coordination of access to and development of the area. 

2.3. Mitigation of surface impact including but not limited to issues pertaining to 

relocation of natural gas pipeline gathering and distribution systems and other 

surface facilities occasioned by placement of a spent shale pile; phased or 

coordinated surface occupancy so as to allow each operator to enjoy his respective 

mineral estate with the least disruption of operations and damage to the oil and gas 

deposits, either directly or indirectly, through waste; and limitation of oil and gas 

operations in areas of concentrated surface oil shale facilities. 

2.4. Mitigation of subsurface impact including but not limited to issues pertaining 

to the interface in the underground environment of oil shale mining operations with 

other mineral operations. 

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2.5. The extent of exchange of geological, engineering, and production data. 

2.6. Other cooperative efforts consistent with multiple mineral development 

under the rules and orders of the board pertaining to oil and gas operations, oil shale 

operations, and mined land reclamation. 

3. The division, together with the Division of Forestry, Fire and State Lands, and 

School and Institutional Trust Lands Administration shall be signatory to the 

agreement, where applicable. 

4. In the event the operators cannot agree on cooperative development of their 

respective mineral deposits, or having once entered into a cooperative agreement 

subsequently disagree on the application of the terms and provisions thereof, any 

operator whose oil and gas or mining operation or deposit may be adversely affected 

or damaged by the operations of another operator may apply to the board for, or the 

board may on its own motion enter an order, after notice and hearing, delineating 

the respective rights and obligations of all operators with respect to development of 

all minerals concerned. 

5. After notice and hearing the board may modify its order to more effectively 

carry out the policies of multiple mineral development. 

R649-3-28. Designated Potash Areas.

1. In any area designated as a potash area, either by the board, or an appropriate 

state or federal government agency, all wells shall be drilled, cased, cemented, and 

plugged in accordance with the rules and orders of the board. The following 

minimum requirements and definitions shall also apply to the drilling, logging, 

casing, and plugging operations within the Salt Section to protect against migration 

of oil, gas, or water into or within any formation or zone containing potash. As used 

in this rule, Salt Section shall mean the Paradox Salt Section of Pennsylvanian Age. 

2. Any drilling media used through the Salt Section shall be such that sodium 

chloride is not soluble in the media at normal temperatures. 

3. Gamma ray-neutron, gamma ray-sonic or other appropriate logs shall be run 

promptly through the Salt Section. One field copy of the log through the Salt Section 

shall be submitted to the division within ten days, or upon the request of the 

division, whichever is the earlier. 

4. A directional survey shall be run from a point at least 20 feet below the Salt 

Section to the surface. The survey shall be filed with the division prior to completion 

or plugging and abandonment of the well. 

5. In addition to the requirements of the R649-3-8, any casing set into or through 

the Salt Section shall be cemented solidly through the Salt Section above the casing 

shoe. 

6. Any cement used in setting casing or in plugging that comes in contact with the 

Salt Section shall be of such chemical composition as to avoid dissolution of the Salt 

Section and to provide weight, strength, and physical properties sufficient to protect 

uphole formations and prevent blowouts or uncontrolled flows. 

7. If a well is dry, cement plugs at least 200 feet in length shall be placed across 

the top and the base of the Salt Section, across any oil, gas or water show, and across 

any potash zone. 

7.1. Plugs shall not be required inside a properly cemented casing string. The 

division shall approve the location of the plugs after examining the appropriate logs, 

drilling and testing records for the well. 

7.2. No well shall be temporarily abandoned with open hole in the Salt Section. 

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8. The division may inspect the drilling operations at all times, including any 

mining operations that may affect any drilling or producing well bores. A potash 

owner, if contributing by agreement to the logging and directional survey costs of a 

well, may inspect the well for compliance with this rule. 

9. Before commencing drilling operations for oil or gas on any land within 

designated potash area, the operator shall furnish by registered mail, a copy of the 

APD, together with the plat or map required under R649-3-4, to all potash owners 

and lessees whose interests are within a radius of 2,640 feet of the proposed well. 

10.After proper notice and hearing, the board may modify this rule for a 

particular well or area by requiring that greater or lesser precautions be taken to 

prevent the escape of oil, gas, or water from one stratum into another. The board 

may also expand or contract from the designated potash areas. 

R649-3-29. Workable Coal Beds.

1. Prior to commencing drilling operations for oil and gas on any lands where 

there are mine workings, the operator shall furnish a copy of the APD, a plat or map 

as required under R649-3-4, and a designation of the proposed angle and direction 

of the well, if the well is to be deviated substantially from a vertical course, to all coal 

owners and lessees whose interests are within a radius of 5,280 feet of the proposed 

well. 

2. A well penetrating one or more workable coal beds or mine workings shall be 

drilled to a depth and shall be of a size, to permit the placing of casing in the hole at 

the points and in the manner necessary to exclude all oil, gas or gas pressure from 

the coal bed, other than oil, gas or gas pressure originating in the coal bed. 

3. Unless otherwise authorized by the division, the casing run through a coal bed 

shall be seated at least 50 feet into the closest impervious formation below the coal 

bed. The casing shall be cemented solidly through the coal bed to a height at least 50 

feet into the closest impervious formation above the coal bed. 

4. A directional survey or a cement bond log shall be performed and furnished to 

the division upon written request by the division. 

5. Upon penetrating a coal bed the operator shall notify the division, in writing, 

before completing or plugging and abandoning the well. 

R649-3-30. Underground Mining Operations.

1. Prior to commencing drilling operations for oil and gas on any land where there 

are known or suspected underground mining operations, solution mining operations 

or surface mining operations, including solar evaporation ponds, the operator shall 

include in the APD or in a separate cover letter, any information known to the 

operator concerning the name and address of the owner or operator of the mining 

workings. 

2. The division may, with the concurrence of the operator, change the surface 

location of the proposed well if there appears to be any possibility of interference 

between the proposed well bore and the mine workings. 

R649-3-31. Designated Oil Shale Areas.

1. Designated oil shale areas are subject to the general drilling, plugging and other 

performance standards described in this section, except where the board has 

adopted, by order, specific standards for individual oil shale areas. As of June 8, 

2001, the board has adopted specific standards for individual oil shale areas by board 

orders in Cause Nos. 190-5(b), 190-3, and 190-13. The board may adopt specific 

standards in other areas, or modify the above orders, in the future. 

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2. Lands may be designated as an oil shale area by the board, either upon its own 

motion, or upon the petition of an interested person following notice and hearing. 

3. As used in this rule, oil shale section means the sequence of strata containing 

oil shale beds, including any interbedded strata not containing oil shale, consisting of 

the Parachute Creek Member of the Green River Formation of Tertiary Age, defined 

as the stratigraphic equivalent of the interval between 1,428 feet and 2,755 feet below 

the Kelly Bushing on the induction-electrical log of the Ute Trail No. 10 API No. 43-

047-15382 well drilled by Dekalb Agricultural Association, Inc. and located in the NE 

1/4 of Section 34, Township 9 South, Range 21 East, S.L.M., Uintah County, Utah. 

The Mahogany Zone is defined as the stratigraphic equivalent of the interval between 

2,230 feet and 2,360 feet below the Kelly Bushing on the induction-electrical log of 

the well cited above. 

4. For purposes of identifying the oil shale intervals, an appropriate electrical log 

shall be run through the oil shale section. One field copy of the log through the oil 

shale section shall be made available to the division pursuant to R649-3-23 or upon 

written request by the division. 

5. On all wells that are intentionally deviated from the vertical within the oil shale 

section, pursuant to the provisions of R649-3-10 and R649-3-11, a directional survey 

shall be run from a point at least 20 feet below the oil shale section to the surface and 

shall thereafter be filed with the division within 20 days after reaching total depth. 

6.Any oil shale lessee or operator whose oil shale mine workings reach a distance 

of 2,640 feet from a producing well or any oil and gas lessee or operator whose 

producing well is approached by oil shale mine workings within a distance of 2,640 

feet shall request agency action with the board. The board may promulgate an order 

after notice and hearing with respect to the running of a directional survey through 

the oil shale section, the cost and potential resource loss liability and responsibility 

as to the oil and gas operator and the oil shale lessee or operator and any other issues 

regarding multiple mineral development. 

7. The directional survey shall be the confidential property of the parties paying 

for the survey and shall be kept confidential until released by said parties or the 

division. 

8. In addition to the requirements pertaining to the cementing of casing 

contained in the R649-3-8, any casing set into or through the oil shale section shall 

be cemented over the entire oil shale section. 

9. If a well is dry, junked or abandoned, a cement plug shall be placed across that 

portion of the oil shale section extending 200 feet above and 200 feet below the 

longitudinal center of the Mahogany Zone. The cement plug shall not be required 

inside a casing cemented in accordance with R649-3-31-8. When the casing is 

cemented, cement plugs 200 feet in length shall be centered across the top and 

across the base of the Parachute Creek Member of the Green River Formation. 

10. In the event the casing is not cemented in accordance with R649-3-31-8, the 

division shall approve the method and procedure to prevent the migration of oil, gas, 

and other substances through the wellbore from one formation to another. 

11. The division shall approve the adequacy and location of the cement plugs after 

examining the appropriate logs and drilling and testing records for the well, to 

ensure that the oil shale section is adequately protected. 

12. Upon written request of the owner or operator under R649-8-6, the division 

shall keep all well logs confidential. The division may inspect the drilling operations 

at all times, including any mining operations that may affect drilling or producing 

well bores. 

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13. Before commencing drilling operations for oil or gas on any land within a 

designated oil shale area, the operator shall furnish a copy of the APD, together with 

a plat or map as directed under R649-3-4, to all oil shale owners or their lessees 

whose interests are within a radius of 2,640 feet of the proposed well. The operator 

shall furnish a notice of intention to plug and abandon any well in the oil shale area, 

as required under R649-3-24-1, to the owners or their lessees prior to 

commencement of plugging operations. 

14. The operator shall use generally accepted techniques for vertical or directional 

drilling as defined under R649-3-10 and R649-3-11 to maintain the well bore within 

an intact core of a mine pillar. Within 20 days of reaching the total depth or before 

completion of the well, whichever is the earlier, a directional survey shall be run as 

prescribed by this rule. 

R649-3-32. Reporting of Undesirable Events.

1. The division shall be notified of all fires, leaks, breaks, spills, blowouts, and 

other undesirable events occurring at any oil or gas drilling, producing, or 

transportation facility, or at any injection or disposal facility. 

2. Immediate notification shall be required for all major undesirable events as 

outlined in R649-3- 32-5. 

2.1. Immediate notification shall mean a verbal report submitted to the division 

as soon as practical but within a maximum of 24 hours after discovery of an 

undesirable event. 

2.2. A complete written report of the incident shall also be submitted to the 

division within five days following the conclusion of an undesirable event. 

2.3. The requirements for written reports are specified in R649-3-32-4. 

3. Subsequent notification shall be required for all minor undesirable events as 

outlined in R649-3- 32-6. 

3.1. Subsequent notification shall mean a complete written report of the incident 

submitted to the division within five days following the conclusion of an undesirable 

event. 

3.2. The requirements for written reports are specified in R649-3-32-4. 

4. Complete written reports of undesirable events may be submitted on Form 9, 

Sundry Notice and Report on Wells. The report shall include: 

4.1. The date and time of occurrence and, if immediate notification was required, 

the date and time the occurrence was reported to the Division. 

4.2. The location where the incident occurred described by section, township, 

range, and county. 

4.3. The specific nature and cause of the incident.

4.4. A description of the resultant damage. 

4.5. The action taken, the length of time required for control or containment of 

the incident, and the length of time required for subsequent cleanup. 

4.6. An estimate of the volumes discharged and the volumes not recovered. 

4.7. The cause of death if any fatal injuries occurred. 

5. Major undesirable events include the following: 

5.1. Leaks, breaks or spills of oil, salt water or oil field wastes that result in the 

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discharge of more than 100 barrels of liquid, that are not fully contained on 

location by a wall, berm, or dike. 

5.2. Equipment failures or other accidents that result in the flaring, venting, or 

wasting of more than 500 Mcf of gas. 

5.3. Any fire that consumes the volumes of liquid or gas specified in R649-3-32-

5.1 and R649-3-32- 5.2. 

5.4. Any spill, venting, or fire, regardless of the volume involved, that occurs in a 

sensitive area stipulated on the approval notice of the initial APD for a well, e.g., 

parks, recreation sites, wildlife refuges, lakes, reservoirs, streams, urban or suburban 

areas. 

5.5. Each accident that involves a fatal injury. 

5.6. Each blowout, loss of control of a well. 

6. Minor undesirable events include the following: 

6.1. Leaks, breaks or spills or oil, salt water, or oil field wastes that result in the 

discharge of more than ten barrels of liquid and are not considered major events in 

R649-3-32-5. 

6.2 Equipment failures or other accidents that result in the flaring, venting or 

wasting of more than 50 Mcf of gas and are not considered major events in R649-3-

32-5. 

6.3. Any fire that consumes the volumes of liquid or specified in R649-3-32-6.1 

and R649-3-32- 6.2. 

6.4. Each accident involving a major or life-threatening injury. 

R649-3-33. Drilling Procedures in the Great Salt Lake.

1. For all drilling activities proposed within the Great Salt Lake, the APD required 

by R649-3-4 shall be filed at least 30 days prior to the date on which the operator 

intends to commence operations. As part of the APD, the operator shall include: 

1.1. The name of the drilling contractor and the number and type of rig to be used. 

1.2. An illustration of the boundaries of all state or federal parks, wildlife refuges, 

or waterfowl management areas within one mile of the proposed well location. 

1.3. An illustration of the locations of all evaporation pits, producing wells, 

structures, buildings, and platforms within one mile of the proposed well location. 

1.4.An oil spill emergency contingency plan. 

2. Unless permitted by the board after notice and hearing, no well shall be drilled 

that has a surface location: 

2.1. Within 1,320 feet from an evaporation pit without the consent of the operator 

of such pit. 

2.2. Within one mile from the boundary of a state or federal park, wildlife refuge, 

or waterfowl management area without the consent of the appropriate state or 

federal regulatory agency. 

2.3. Within three miles of Gunnison Island during the Pelican nesting season 

(March 15 through September 30) or within one mile from said island at any other 

time. 

2.4. Within any area south of the Salt Lake Base Meridian Line. 

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2.5. Within any area north of Township 10 North. 

2.6. Within one mile inside of what would be the water's edge if the water level of 

the Great Salt Lake were at the elevation of 4,193.3 feet above sea level. 

3. Well casing and cementing shall be subject to the following special 

requirements for the purpose of this rule, the several casing strings in order of 

normal installation are drive or structural casing, conductor casing, surface casing, 

intermediate casing, and production casing. All depths refer to true vertical depth: 

3.1. The drive or structural casing shall be set by drilling, driving or jetting to a 

minimum depth of 50 feet below the floor of the lake bed or to such greater depth 

required to support unconsolidated deposits and to provide hole stability for initial 

drilling operations. If drilled in, the drilling fluid shall be a type that will not pollute 

the lake; in addition, a quantity of cement sufficient to fill the annular space back to 

the lake floor with returns circulated, must be used. 

3.2. The conductor casing shall be set at a minimum depth of 200 feet below the 

floor of the lake, and shall be cemented with a quantity sufficient to fill the annular 

space back to the lake surface with returns circulated. 

3.3. The surface casing shall be set at a minimum depth of 500 feet if the 

proposed depth of the well is less than 7,000 feet; or 1,000 feet if the proposed depth 

is over 7,000 feet but less than 11,000 feet; or 1,500 feet if the depth is 11,000 feet. 

The casing shall be cemented with a quantity sufficient to fill the annular space back 

to the lake surface with returns circulated, and the bottom of the casing shall be in 

competent rock. 

3.4. The intermediate and production casing shall be set at any time when drilling 

below the surface casing and hole conditions justify setting casing. This casing will be 

cemented in such a manner that all hydrocarbons, water aquifers, lost-circulation or 

zones of significant porosity and permeability, significant beds containing priority 

minerals, and abnormal pressure intervals are covered or isolated. 

3.5. Prior to drilling the plug after cementing, all casing strings except the drive or 

structural casing, shall be pressure tested. This test shall not exceed the rated 

working pressure of the casing. If the pressure declines more than ten percent in 30 

minutes, or if there are other indications of a leak, corrective measures must be taken 

until a satisfactory test is obtained. All casing pressure tests shall be recorded on the 

driller's log. 

4. Blowout preventers and related well control equipment shall be installed, and 

tested in a manner necessary to prevent blowouts and shall be subject to the 

following special conditions: 

4.1. Prior to drilling below the surface casing, blowout prevention equipment 

shall be installed and maintained ready for use until drilling operations are 

completed. 

4.2. An inside blowout preventer assembly and a full opening string safety valve 

in the open position shall be maintained on the rig floor at all times while drilling 

operations are being conducted. 

4.2.1. Valves shall be maintained on the rig floor to fit all pipe in the drill string. 

4.2.2. A top kelly cock shall be installed below the swivel and another at the 

bottom of the kelly of such design that it can be run through the blowout preventers. 

4.3. Before drilling below the surface casing the blowout prevention equipment 

shall include a minimum of: 

4.3.1. Three remotely and manually controlled, hydraulically operated blowout 

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preventers with a rated working pressure that exceeds the maximum anticipated 

surface pressure, including one equipped with pipe rams, one with blind rams and 

one hydril type. 

4.3.2. A drilling spool with side outlets, if side outlets are not provided in the 

blowout preventer body. 

4.3.3. A choke manifold. 

4.3.4. A kill line. 

4.3.5. A fill-up line. 

4.4. Ram-type blowout preventers and related control equipment shall be tested 

to the rated working pressure of the stack assembly or to the working pressure of the 

casing, whichever is the lesser, at the following times: 

4.4.1. When installed. 

4.4.2. Before drilling out after each string of casing is set. 

4.4.3. Not less than once each week while drilling.

4.4.4. Following repairs that require disconnecting a pressure seal in the 

assembly. 

4.5. The hydril-type blowout preventer shall be tested to 70 percent of the 

pressure testing requirements of ram-type blowout preventers. The hydril-type 

blowout preventer shall be actuated on the drill pipe once each week. 

4.6. Accumulators or accumulators and pumps shall maintain a reserve capacity 

at all times to provide for repeated operation of hydraulic preventers. 

4.7. A blowout prevention drill shall be conducted weekly for each drilling crew to 

insure that all equipment is operational and that crews are properly trained to carry 

out emergency duties. All blowout preventer tests and crew drills shall be recorded 

on the driller's log. 

5. The characteristics and use of drilling mud and the conduct of related drilling 

procedures shall be such as are necessary to maintain the well in a safe condition to 

prevent uncontrolled blowouts of any well. Quantities of mud materials sufficient to 

insure well control shall be maintained and readily accessible for use at all times. 

6. Mud testing equipment shall be maintained on the derrick floor at all times, 

and mud tests consistent with good operating practice shall be performed daily, or 

more frequently as conditions warrant. The following mud system monitoring 

equipment must be installed, with derrick floor indicators, and used throughout the 

period of drilling after setting and cementing the surface casing: 

6.1. A recording mud pit level indicator including a visual and audio warning 

device to determine mud pit volume gains and losses. 

6.2. A mud return indicator to determine when returns have been obtained, or 

when they occur unintentionally, and additionally to determine that returns 

essentially equal the pump discharge rate. 

7. In the conduct of all oil and gas operations, the operator shall prevent pollution 

of the waters of the Great Salt Lake. The operator shall comply with the following 

pollution prevention requirements: 

7.1. Oil in any form, liquid or solid wastes containing oil, shall not be disposed of 

into the waters of the lake. 

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7.2. Liquid or solid waste materials containing substances that may be harmful to 

aquatic life or wildlife, or injurious in any manner to life and property, or that in any 

way unreasonably adversely affects the chemicals or minerals in the lake shall not be 

disposed of into the waters of the lake. 

7.3. Waste materials, exclusive of cuttings and drilling media, shall be 

transported to shore for disposal. 

8. All spills or leakage of oil and liquid or solid pollutants shall be immediately 

reported to the division. A complete written statement of all circumstances, including 

subsequent clean-up operation, shall be forwarded to said agencies within 72 hours 

of such occurrences. 

9. Standby pollution control equipment consistent with the state of the art, shall 

be maintained by, and shall be immediately available to, each operator. 

R649-3-34. Well Site Restoration.

1. The operator of a well shall upon plugging and abandonment of the well restore 

the well site in accordance with these rules. 

2. For all land included in the well site for which the surface is federal, Indian, or 

state ownership, the operator shall meet the well site restoration requirements of the 

appropriate surface management agency. 

3. For all land included in the well site for which the surface is fee or private 

ownership, the operator shall meet the well site restoration requirements of the 

private landowner or the minimum well site restoration requirements established by 

the division. 

4. Well site restoration on lands with fee or private ownership shall be completed 

within one (1) year following the plugging of a well unless an extension is approved 

by the division for just and reasonable cause. 

5. These rules shall not preclude the opportunity for a private landowner to 

assume liability for the well as a water well in accordance with R649-3-24.6. 

6. The operator shall make a reasonable effort to establish surface use agreements 

with the owners of land included in the well site prior to the commencement of the 

following actions on fee or private surface: 

6.1. Drilling a new well. 

6.2. Reentering an abandoned well. 

6.3. Assuming operatorship of existing wells. 

7. Upon application to the division to perform any of the aforementioned and 

prior to approval of such actions by the division, the operator shall submit an 

affidavit to the division stating whether appropriate surface use agreements have 

been established with and approved by the surface landowners of the well site. 

8. If necessary and upon request by the division, the operator shall submit a copy 

of the established surface use agreements to the division. 

9. If no surface use agreement can be established, the division shall establish 

minimum well site restoration requirements for any well located on fee or private 

surface for the purposes of final bond release. 

10. Established surface use agreements may be modified or terminated at any 

time by mutual consent of the involved parties; however, the operator shall notify the 

division if such is the case and if a surface use agreement is terminated without a 

new agreement established, the division shall establish minimum well site 

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reclamation requirements. 

11. The operator shall be responsible for meeting the requirements of any surface 

use agreement, and it shall be assumed by the division until notified otherwise that 

surface use agreements remain in full force and effect until all the requirements of 

the agreement are satisfied or until the agreement has been terminated by mutual 

consent of the involved parties. 

12. The surface use agreement shall stipulate the minimum well site restoration to 

be performed by the operator in order to allow final release of the bond. 

13. The final bond release by the division shall include a determination by the 

division whether or not the operator has met the requirements of an established 

surface use agreement, and the division may suspend final bond release until the 

operator has completed all the requirements of the surface use agreement. 

14. The agreement may state requirements for well site grading, contouring, 

scarification, reseeding, and abandonment of any equipment or facilities for which 

the landowner agrees to assume liability. 

15. The agreement shall not address operations regulated by the rules and orders 

of the board such as: 

15.1. Disposal of drilling fluid, produced fluid, or other fluid waste associated with 

the drilling and production of the well. 

15.2. Reclamation or treating of waste crude oil. 

15.3. Any other operation or condition for which the board has jurisdiction. 

16. If the operator cannot establish surface use agreements then the operator 

shall so notify the division. 

17. Within 30 days of the notification or as soon as weather conditions permit, the 

division shall conduct an inspection and evaluation of the well site in order to 

establish minimum well site restoration requirements for the purpose of final bond 

release. 

18. The operator shall be given notice by the division of the date and time of the 

inspection, and if the operator cannot attend the inspection at the scheduled date 

and time, the division may reschedule the inspection to allow the operator to 

participate. 

19. The surface landowner, agent or lessee shall be given notice by the operator of 

such inspection and may participate in the inspection; however, if the surface 

landowner cannot attend the inspection, the division shall not be required to 

reschedule the inspection in order to allow the surface landowner to participate. 

20. The evaluation shall consider the condition of the land prior to disturbance, 

the extent of proposed disturbance, the degree of difficulty to conduct complete 

restoration, the potential for pollution, the requirements for abating pollution, and 

the possible land use after plugging and restoration are completed. 

21. Within 30 days after performing the inspection, the division shall provide the 

operator with the results of the inspection and the evaluation listing the minimum 

well site restoration requirements established by the division. 

22. The division shall retain a record of the inspection and the evaluation, and if 

necessary and upon written request by an interested party, the division shall provide 

a copy of the minimum well site restoration requirements established by the division. 

23. If any person disagrees with the results of the inspection and the evaluation 

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and desires a reconsideration of the minimum well site restoration requirements 

established by the division, such person may submit a request to the board for a 

hearing and order to modify the requirements. 

24. The board, after proper notice and hearing, may issue an order modifying the 

minimum well site restoration requirements established by the division. 

25. The minimum well site restoration requirements established by the division 

or by board order shall be considered part of any permit granted by the division to 

conduct operations at a well site, and the inability of the operator to meet such 

requirements shall be considered grounds for forfeiture of the bond. 

26.If the minimum well site restoration requirements suggest to the division that 

bond coverage for a well should be increased, the division shall take action as stated 

in R649-3-1. 

R649-3-35. Wildcat Wells.

1. For purposes of qualifying for a severance tax exemption under Section 59-5-

102(5)(b), an operator must file an application with the division for designation of a 

wildcat well. 

1.1. The application may be filed prior to drilling the well, and a tentative 

determination of the wildcat designation will be issued at that time. An application 

or request for final designation of wildcat status as appropriate, must be filed at the 

time of filing of Form 8, Well Completion or Recompletion Report and Log. 

1.2. The application shall contain, where applicable, the following information: 

1.2.1. A plat map showing the location of the well in relation to producing wells 

within a one mile radius of the wellsite. 

1.2.2. A statement concerning the producing formation or formations in the 

wildcat well and also the producing formation or formations of the producing wells 

in the designated area, including completion reports and other appropriate data. 

1.2.3. Stratigraphic cross sections through the producing wells in the designated 

area and the proposed wildcat well. 

1.2.4. A statement as to whether the well is in a known geologic structure. 

However, whether the well is in a known geologic structure shall not be the sole basis 

of determining whether the well is a wildcat. 

1.2.5. Bottomhole pressures, as applicable, in a wildcat well compared to the wells 

producing in the designated area from the same zone. 

1.2.6. Any other information deemed relevant by the applicant or requested by 

the division. 

2. Information derived from well logs, including certain information in 

completion reports, stratigraphic cross sections, bottomhole pressure data, and other 

appropriate data provided in R649-3-35-1 will be held confidential in accordance 

with R649-2-11 at the request of the operator. 

3. The division shall review the submitted information and advise the operator 

and the State Tax Commission of its decision regarding the wildcat well designation 

as related to Section 59-5-102(5)(b). 

4. The division is responsible for approval of a request for designation of a well as 

a wildcat well. If the operator disagrees with the decision of the division, the decision 

maybe appealed to the board. Appeals of all other tax-related decisions concerning 

wildcat wells should be made to the State Tax Commission. 

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R649-3-36. Shut-in and Temporarily Abandoned Wells.

1. Wells may be initially shut-in or temporarily abandoned for a period of twelve 

(12) consecutive months. If a well is to be shut-in or temporarily abandoned for a 

period exceeding twelve (12) consecutive months, the operator shall file a Sundry 

Notice providing the following information: 

1.1. Reasons for shut-in or temporarily abandonment of the well, 

1.2. The length of time the well is expected to be shut-in or temporarily 

abandoned, and 

1.3. An explanation and supporting data, for showing the well has integrity, 

meaning that the casing, cement, equipment condition, static fluid level, pressure, 

existence or absence of Underground Sources of Drinking Water and other factors do 

not make the well a risk to public health and safety or the environment. 

2. After review the Division will either approve the continued shut-in or 

temporarily abandoned status or require remedial action to be taken to establish and 

maintain the well's integrity. 

3. After five (5) years of nonactivity or nonproductivity, the well shall be plugged 

in accordance with R649-3-24, unless approval for extended shut-in time is given by 

the Division upon a showing of good cause by the operator. 

4. If after a five (5) year period the well is ordered plugged by the Division, and 

the operator does not comply, the operator shall forfeit the drilling and reclamation 

bond and the well shall be properly plugged and abandoned under the direction of 

the Division. 

R649-3-37. Enhanced Recovery Project Certification.

1. In order for incremental production achieved from an enhanced recovery 

project to qualify for the severance tax rate reduction provided under Subsection 59-

5-102(7), the operator on behalf of the producers shall present evidence 

demonstrating that the recovery technique or techniques utilized qualify for an 

enhanced recovery determination and the Board must certify the project as an 

enhanced recovery project. 

2. For enhanced recovery projects certified by the Board after January 1, 1996: 

2.1. As part of the process of certifying incremental production that qualifies for a 

reduction in the severance tax rate under Subsection 59-5-102(7), the operator shall 

furnish the Division: 

2.1.1. An extrapolation (projection) and tabulation of expected non-enhanced 

recovery of oil and gas production from the project. 

2.1.2. The projection shall be for not less than seventy-two (72) months 

commencing with the first month following the project certification by the Board. 

2.1.3. The projection shall be based on production history of all wells within the 

project area for not less than twelve (12) months immediately preceding either 

certification or commencement of the project; reservoir and production 

characteristics; and the application of generally accepted petroleum engineering 

practices. 

2.1.4. The projected production volumes approved by the division shall serve as 

the base level production for purposes of determining the incremental oil and gas 

production that qualifies for a reduction in the severance tax rate. 

2.2. The operator shall provide a statement as to all assumptions made in 

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preparing the projection and any other information concerning the project that 

the division may reasonably require in order to evaluate the operator's projection. 

2.3. An operator's request for incremental production certification may be 

approved administratively by the Director or authorized agent. The Director or 

authorized agent shall review the request within 30 days after its receipt and advise 

the operator of the decision. If the operator disagrees with the Director or authorized 

agent's decision, the operator may request a hearing before the Board at its next 

regularly scheduled hearing. The Director or authorized agent may also refer the 

matter to the Board if a decision is in doubt. 

2.4. Upon approval of a request for incremental production certification, the 

Director or authorized agent shall forward a copy of the certification to the Utah Tax 

Commission. 

KEY

oil and gas law 

Date of Enactment or Last Substantive Amendment

July 1, 2003 

Notice of Continuation

February 3, 2012 

Authorizing, Implemented, or Interpreted Law

40-6-1 et seq. 

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http://www.rules.utah.gov/contact/agencycontacts.htm. 

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UT Admin Code R649-3. Drilling and Operating Practices. May 1, 2012 Page 41 of 41

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