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State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations
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State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations

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A tool for reviewing state-specific differences from federal regulations for upstream oil and gas operations …

A tool for reviewing state-specific differences from federal regulations for upstream oil and gas operations

Allows auditors to compare
state requirements with BSEE, BOEM and BLM requirements
• Field-tested by experienced compliance auditors

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  • 1. Sample State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations Coming Soon for Texas, followed by other jurisdictions Sign up to keep apprised of delivery dates www.stpub.com
  • 2. State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations © STP
  • 3. State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations A tool for reviewing statespecific differences from federal regulations for upstream oil and gas operations © STP
  • 4. Users of This Guide Include • Exploration companies • Onshore and offshore oil and gas companies • Utilities • Senior EHS management • Facility compliance staff • EHS auditors • Attorneys • Regulatory agencies • And many more… © STP
  • 5. Features of This Guide • Complements the STP Onshore and Offshore Upstream Oil and Gas Operations: Federal Auditing Guide • Allows auditors to compare state requirements with BSEE, BOEM and BLM requirements • Field-tested by experienced compliance auditors © STP
  • 6. Features of This Guide • Enables companies to perform self-assessments of their ongoing compliance • Saves time and reduces compliance and audit costs • Helps avoid citations and fines • Provides an overview of the state regulatory structure • Summaries • Checklists © STP
  • 7. Comprehensive Topic Areas • Overall state regulatory structure • General obligations • Exploration/development operations plans • Pollution prevention and control • Drilling operations • Well completion • Well workovers © STP
  • 8. Comprehensive Topic Areas • Production safety systems • Platforms and structures • Pipelines and rights-of-way • Production and operations • Decommissioning activities • Surface activities • Fracturing and other field stimulation • Operations in hydrogen sulfide areas © STP
  • 9. Features – Introduction Provides a brief overview of the state’s regulatory structure © STP
  • 10. Sample Introduction COMING SOON © STP
  • 11. Features – Summaries Provide a comprehensive set of requirement statements with detailed guidance on compliance issues and inspection procedures © STP
  • 12. Sample Summary TEXAS Regulatory Differences Summary . 1. Introduction Applicability This Texas Onshore and Offshore Upstream Oil and Gas Operations Guide addresses Texas Railroad Commission (RRC) requirements found in 16 TAC 3 (Oil and Gas Division) as well as certain Texas General Land Office (GLO) requirements found in 31 TAC 9 (Exploration and Leasing of State Oil and Gas). This guide does not address permitting procedures (such as content of applications or public hearings), leasing procedures, or aspects of collecting royalties. Overall Regulatory Structure Railroad Commission of Texas Upstream oil and gas operations in the state of Texas on privately held land are subject to regulation by the state agency with the unlikely name of the Railroad Commission of Texas (RRC). With few miles of navigable waterways—and none going east-west—Texas’ post–Civil War commerce and future development was dependent on the railroads. The RRC was created in 1891 in response to discriminatory rate-setting and abuses of state tax incentives and land grants by the railroads. Over the years, the charter for the RRC continued to expand its oversight of areas important to commerce and development of natural resources in the state, at one point even overseeing rate-setting and activities for motor carriers and buses. As the agency currently has no responsibility for railroads in the state of Texas, the Texas legislature has considered numerous times, but not yet acted on, changing the name of RRC. Currently the Railroad Commission has primary regulatory responsibility in the state for the oil and natural gas industry (except for leasing and collection of royalties managed by the GLO), pipelines, natural gas utilities, the LP-gas industry, coal and uranium surface mining, and research and education concerning the use of LP-gas as an alternative fuel. Through its Oil and Gas Division, RRC regulates the exploration, production, and transportation of oil and natural gas in Texas. RRC does not have authority for activities on the outer continental shelf, which for Texas, begins about 9 miles offshore. Information about offshore oil and gas activity can be found in STP’s Onshore and Offshore Upstream Oil and Gas Operations: Federal Auditing Guide.. The statutory role for the Railroad Commission is to do the following: • prevent waste of the state's natural resources; • protect the correlative rights of different interest owners; • prevent pollution; and • provide safety in matters such as hydrogen sulfide. OILGASSD TEXAS Summary S-1 - 5/13 © STP
  • 13. Features – Checklists Enable convenient collection of audit findings and assist in report generation © STP
  • 14. Sample Checklist COMING SOON © STP
  • 15. Formats • Online single-user • Online multi-user • CD • Multi-user through risk management systems NOTE: This guide is only available in combination with Onshore and Offshore Upstream Oil and Gas Operations: Federal Auditing Guide © STP
  • 16. Periodic updates Sample Release Notes COMING SOON Release Notes are issued with each update to provide quick overview of changes © STP
  • 17. The following pages are a longer sample from State Differences Summaries and Checklists for Onshore and Offshore Upstream Oil and Gas Operations © STP
  • 18. 5. Drilling Operations Drilling operations for oil and gas in the state of Texas are regulated by the Texas Railroad Commission (RRC) under 16 TAC 3. RRC requirements apply to all wells drilled in the state of Texas (including those on submerged lands within 9 nautical miles of the coast). The Texas General Land Office (GLO) has established additional requirements for activities on public lands under 31 TAC 9. Activity on State Lands With few exceptions, GLO regulations controlling oil and gas activity on state lands provide few specifics. Instead, GLO has established general performance obligations—operators must conduct drilling operations on state lands with the highest degree of care, take all proper safeguards to prevent pollution, and conduct operations as a reasonably prudent operator using standard industry practices and procedures (31 TAC 9.32). Because RRC requirements (which are much more expansive and specific) apply to all upstream oil and gas activities in the state, evaluation of drilling on state lands must consider both RRC and GLO requirements. GLO’s general requirements are presented in Section 3 of this guide; GLO-specific requirements for drilling offset wells include the following: • An offset well must be drilled on state property whenever an encroaching well is completed unless one of the following conditions applies: (31 TAC 9.37(a)) – The lessee has properly pooled the state property with the property containing the encroaching well (see 31 TAC 9.81, Pooling and Unitizing of State Property). – GLO has granted written approval to allow payment of compensatory royalties in lieu of drilling an offset well. – GLO has agreed that the encroaching well cannot be draining state hydrocarbons. • The lessee must drill any offset well on any state property other than Relinquishment Act property. On Relinquishment Act property (whether leased or unleased), the surface owner, lessee, sublessee, receiver or other agent in control of the property must drill the well. (31 TAC 9.37(a)(1)) • Offset wells must be drilled to a sufficient depth and in a manner that prevents drainage of oil or gas from state land. (31 TAC 9.37(a)(2)) • Drilling associated with an offset well must begin within 100 days of the date that the encroaching well first produces commercially (excluding test production) for wells located on Relinquishment Act lands, or within 60 days for wells located on other state properties. (31 TAC 9.37(a)(3)) OILGASSD TEXAS Summary S-24 - 5/13
  • 19. Requirements for All Wells Inclination and Deviation • All wells must be drilled as nearly vertical as possible by normal, prudent, practical drilling operations. A well may not be drilled in such a manner that the wellbore crosses lease and/or property lines (or unit lines in cases of pooling) without special permission. (16 TAC 3.11(a)) • Inclination surveys must be conducted in accordance with all of the following requirements: (16 TAC 3.11(b)(1)) – For each well drilled or deepened with rotary tools, survey must be conducted during the normal course of drilling or after the well has reached total depth. Surveys must also be conducted when, as a result of any operation, the course of the well is changed. Directional surveys may be made instead of inclination surveys. – Surveys must be conducted by persons or concerns approved by RRC and filed on the prescribed RRC form. – The first shot point of the inclination survey must be made at a depth not greater than 500 feet below the surface of the ground, and succeeding shot points must be made either at 500foot intervals or at the nearest drill bit change thereto, but not exceeding 1,000 feet apart. – Copies of all directional or inclination surveys, regardless of the reason for which they are run, must be filed with RRC as a part of or in addition to the inclination survey(s). – If computations are made from dipmeter surveys to determine the course of the wellbore in any portion of the surveyed interval, a report of those computations is required. Exceptions: Inclination surveys are not required on any of the following wells: – wells drilled to a total depth of 2,000 feet or less; – wells drilled on a regular location at least 150 feet from the nearest lease line; – wells not intentionally deviated from the vertical in any manner whatsoever; – wells deepened with rotary tools tono more than 300 feet or the distance from the surface location to the nearest lease or boundary line, whichever is less; – wells deepened with rotary tools if the well was not intentionally deviated from the vertical at any time before or after the beginning of deepening operations; and – wells that were drilled and completed as dry holes and were permanently plugged and abandoned (if such wells are reentered at a later date and completed as producers or injection or disposal wells, however, inclination reports are required and must be filed with the appropriate completion form for the well). • Inclination surveys must be filed with RRC in accordance with all of the following requirements: (16 TAC 3.11(b)(2)) – The report form must be signed and certified by a party having personal knowledge of the facts of the survey. – The report must include a tabulation of both of the following: ♦ the maximum drifts that could occur between the surface and the first shot point, and each two successive shot points, assuming that all of the unsurveyed hole between any two shot points has the same inclination as that measured at the lowest shot point; and ♦ the total possible accumulative drift, assuming that all measured angles of inclination are in the same direction. OILGASSD TEXAS Summary S-25 - 5/13
  • 20. – • • • • • The report must be accompanied by a certified statement of the operator, or of someone acting at the operator’s direction, that either the well was not intentionally deviated from vertical, or the well was deviated at random, with an explanation of the circumstances. – The report must be filed in the RRC district office by attaching one copy to each appropriate completion form for the well. Original charts, graphs, or discs resulting from the surveys may be required. If an inclination survey indicates that the maximum displacement is greater than the actual distance from the surface location to the nearest lease line or pooled unit boundary, the well is considered to be a violating well subject to plugging and to penalty action, unless the operator conducts and submits a directional survey, run by an RRC-approved surveying company, and the survey shows that the well was bottomed within the confines of the lease. Note: A new permit is required if the survey shows that the well was bottomed within the confines of the lease but not at a reasonable location (i.e., nearer to a well or lease line or pooled unit boundary than allowed by Statewide Spacing Rule (16 TAC 3.37) or a permit granting an exception). (16 TAC 3.11(c)(1)(A)) A directional survey is required if a well was drilled pursuant to a permit authorizing directional deviation or random deviation, or if required by RRC. (16 TAC 3.11(c)(1)(B) and 3.11(e)) Directional surveys must meet all of the following requirements: (16 TAC 3.11(c)(2)(A) and 3.11(c)(2)(B)) – The survey must be conducted by competent surveying companies approved by RRC. – The survey must be signed and certified by a person having actual knowledge of the facts – Unless approved differently by RRC, the survey may either single shot surveys or multi-shot surveys, provided the following requirements are met: ♦ The shot points are not more than 200 feet apart. ♦ The shot points begin within 200 feet of the surface. ♦ The bottom hole location is oriented both to the surface location and to the lease lines (or unit lines in cases of pooling). If more than 200 feet of surface casing has been run and the operator begins the directional survey immediately below the surface casing depth, the following requirements apply: (16 TAC 3.11(c)(2)(C)) – The inclination drifts from the surface of the ground to the surface casing depth must be added cumulatively. – The inclination drifts must be reported on the appropriate form. – The total inclination drift must be assumed to be in the direction least favorable to the operator – The total inclination drift must be considered the starting point of the directional survey. If, after drilling has started, there is a need for directional deviation or random deviation, the operator must provide written notice by letter or telegram (electronically might be approved) to the appropriate RRC district office and to the RRC Austin office. Upon providing notice, the operator may continue drilling, but at their own risk for directional deviation, because an RRCapproved permit for the subsurface location of each completion is required for the directional deviation before RRC can consider assigning an allowable. (16 TAC 3.11(c)(3)(B) and 3.11(c)(3)(C)) OILGASSD TEXAS Summary S-26 - 5/13
  • 21. RRC Requirements for Onshore and Inland Waters General • All casing cemented in any well must be steel casing that meets either of the following conditions: (16 TAC 3.13(b)(1)(A)) – The casing has been hydrostatically pressure tested with an applied pressure at least equal to either of the following: ♦ the maximum pressure to which the pipe will be subjected in the well; or ♦ if the pipe is new, the mill test pressure. – The casing has been inspected using a full length electromagnet, radiation thickness gauging, or ultrasonic or magnetic particle inspection. • Wellhead assemblies must be used on wells to maintain surface control of the well, and each component of the wellhead must have a pressure rating equal to or greater than the anticipated pressure to which that particular component might be exposed during the course of drilling, testing, or producing the well. (16 TAC 3.13(b)(1)(B)) • A blowout preventer or control head and other connections to keep the well under control at all times must be installed as soon as surface casing is set, and the equipment must be constructed to satisfy any reasonable test required by RRC or its agent. (16 TAC 3.13(b)(1)(C)) • When any string of casing more than 200 feet long is cemented, the casing must pass the following pressure test before the cement plug is drilled: – testing the casing at a pump pressure in pounds per square inch (psi), as calculated by multiplying the length of the casing string by 0.2 (but never over 1,500 psi, unless directed by RRC); and – showing a pressure drop of less than 10% after 30 minutes. Note: If there is a pressure drop of 10% or more, the casing must be condemned until the leak is corrected. (16 TAC 3.13(b)(1)(D)) • If the expected reservoir pressure exceeds the weight of the drilling fluid column, the well must meet all of the following conditions: (16 TAC 3.13(b)(1)(E)) – The well must be equipped to divert any wellbore fluids away from the rig floor. – The well must be maintained in an effective working condition. – The operator must discontinue drilling operations if a test indicates or the diverter system is unable to function or operate as designed. • Surface casing must be set and cemented to a depth sufficient to protect all usable-quality water strata, as defined by TCEQ. In no case, however, is surface casing to be set deeper than 200 feet below the specified depth without prior approval from RRC. (16 TAC 3.13(b)(2)(A)(i)) OILGASSD TEXAS Summary S-27 - 5/13
  • 22. Surface Casing • Any well drilled to a total depth of 1,000 feet or less below the ground surface may be drilled without setting surface casing if the following conditions are met: (16 TAC 3.13(b)(2)(A)(ii) – no shallow gas sands or abnormally high pressures are known to exist at depths shallower than 1,000 feet below the ground surface; and – the production casing is cemented from the shoe to the ground surface by the pump and plug method.) • The pump and plug method of cementing must be used with sufficient cement to fill the annular space outside the casing from the shoe to the ground surface or to the bottom of the cellar. If the cement does not circulate to ground surface or the bottom of the cellar, the operator must obtain approval from the RRC district director, indicating whether and how any additional cementing operations are required. (16 TAC 3.13(b)(2)(B)) • Surface casing strings must be allowed to stand under pressure until the following conditions are met: – The cement has reached a compressive strength of at least 500 psi in the zone of critical cement before drilling plug or initiating a test. – The cement mixture in the zone of critical cement has a 72-hour compressive strength of at least 1,200 psi. – As tested in accordance with the current American Petroleum Institute Recommended Practice for Testing Well Cements (API RP 10B), the average free water separation is no more than six milliliters per 250 milliliters of cement. Note: Cement with volume extenders may be used above the zone of critical cement to cement the casing from that point to the ground surface, but in no case may the cement have a compressive strength of less than 100 psi at the time of drill out nor less than 250 psi 24 hours after being placed. (16 TAC 3.13(b)(2)(C)) • Cement mixtures for which published performance data are not available must be tested as follows: (16 TAC 3.13(b)(2)(D)) – The cement must be tested for compressive strength using representative samples of the basic mixture of cement and additives used and using distilled water or potable tap water for preparing the slurry. – The cement must be tested using the equipment and procedures adopted by the American Petroleum Institute, as published in the current API RP 10B; – The typical performance data must be used to determine that the minimum compressive strength has been obtained for the particular cement used in the well (containing all the additives, including any accelerators used in the slurry) at atmospheric pressure and at the following temperatures: ♦ within 10°F of the formation equilibrium temperature at the top of the zone of critical cement, for the cement in the zone of critical cement: and ♦ the temperature found 100 feet below the ground surface level or 60°F, whichever is greater, for the filler cement . – Data showing that the proposed cement mixture meets the requirements must be furnished to RRC before the cementing operation begins. OILGASSD TEXAS Summary S-28 - 5/13
  • 23. • • • Upon completion of a well, a cementing report must be filed with RRC containing all of the following information: (16 TAC 3.13(b)(2)(E)) – all data concerning the cementing of surface casing in the well as specified on the RRC form; and – signatures attesting to compliance with the cementing requirements from both of the following: ♦ the operator of the well or a duly authorized agent having personal knowledge of the facts; and ♦ representatives of the cementing company performing the cementing job. Surface casing must be centralized as follows: – at the shoe, above and below a stage collar or diverting tool, if run, – by centralizing through usable-quality water zones; – by placing a centralizer at every fourth joint from the cement shoe to the ground surface or to the bottom of the cellar in nondeviated holes; and – by providing additional centralizers in deviated holes. Note: All centralizers must meet API Specification for Bow-Spring Casing Centralizers (Spec 10D) specifications. (16 TAC 3.13(b)(2)(F)) Operators must obtain approval of any alternative surface casing program or alternative method of fresh water protection before commencing operations. (16 TAC 3.13(b)(2)(G)) Intermediate Casing • Each intermediate string of casing must be cemented in the following locations: – from the shoe to a point at least 600 feet above the shoe; and – if any productive horizon is open to the wellbore above the casing shoe,the casing must be cemented from the shoe up to at least one of the following: ♦ 600 feet above the top of the shallowest productive horizon; or ♦ 200 feet above the shoe of the next shallower casing string that was set and cemented in the well. Note: If the distance from the casing shoe to the top of the shallowest productive horizon makes such cementing impossible or impractical, the multi-stage process may be used to cement the casing in a manner that will effectively seal off all possible productive horizons and prevent fluid migration to or from such strata within the wellbore. (16 TAC 3.13(b)(3)) OILGASSD TEXAS Summary S-29 - 5/13
  • 24. Production Casing • The producing string of casing must be cemented as follows: (16 TAC 3.13(b)(4)(A)) – by the pump and plug method or another method approved by RRC, with sufficient cement to fill the annular space back of the casing to the surface or to a point at least 600 feet above the shoe; or – in a manner that effectively seals off all possibly productive horizons by one of the methods specified for intermediate casing above, if any productive horizon is open to the wellbore above the casing shoe. • The producing string must meet both of the following requirements: (16 TAC 3.13(b)(4)(B)) – The position of the gas-oil contact must be determined by coring, electric log, or testing. – The producing string must be landed and cemented below the gas-oil contact or must be set completely through and perforated in the oil-saturated portion of the reservoir below the gasoil contact. Tubing and Storm Choke • All flowing oil wells must be equipped with and produced through tubing. (16 TAC 3.13(b)(5)(A)) • When tubing is run inside the casing of a flowing oil well, the following requirements must be met: (16 TAC 3.13(b)(5)(A)) – The bottom of the tubing must be at a point not higher than 100 feet above the top of the producing interval nor more than 50 feet above the top of a line, if one is used. – In a multiple zone structure when the operator equips a well so that small through-the-tubing type tools can be used to perforate, complete, plug back, or recomplete without the necessity of removing the installed tubing, the bottom of the tubing may be set at a distance up to, but not exceeding, 1,000 feet above the top of the perforated or open-hole interval actually open for production into the wellbore. – In no case may tubing be set at a depth of less than 70% of the distance from the surface of the ground to the top of the interval actually open to production. • All flowing oil, gas, and geothermal resource wells located in bays, estuaries, lakes, rivers, or streams must be equipped with a storm choke or similar safety device installed in the tubing a minimum of 100 feet below the mud line. (16 TAC 3.13(b)(5)(B)) Training • All tool pushers, drilling superintendents, and operators' representatives in control of the drilling on land underlying fresh water or marine waters must have a certification that is less than two years old demonstrating satisfactory completion of a USGS-approved school (or refresher course) on well control equipment and techniques. (16 TAC 3.13(c)(9)) OILGASSD TEXAS Summary S-30 - 5/13
  • 25. Offshore RRC Requirements • The casing program must include at least three strings of pipe, in addition to any drive pipe decided by the operator. (16 TAC 3.13(c)(1)) • Conductor casing must meet all of the following requirements: (16 TAC 3.13(c)(1)(A)) – The conductor casing must be a string of new pipe or be reconditioned pipe with substantially the same characteristics as new pipe, – The conductor casing must be set and cemented at a depth of not less than 300 feet true vertical depth (TVD) nor more than 800 feet TVD below the mud line. – The conductor casing must have sufficient cement to fill the annular space back of the pipe to the mud line (however, cement may be washed out or displaced to a maximum depth of 50 feet below the mud line to facilitate pipe removal on abandonment). – The conductor casing must be set and cemented prior to penetration of known shallow oil and gas formations, or upon encountering previously unknown formations. • All surface casing must meet all of the following requirements: (16 TAC 3.13(c)(1)(B)) – The surface casing must be a string of new pipe with a mill test of at least 1,100 pounds per square inch (psi) or be reconditioned pipe that has been tested to 1,100 psi. – The surface casing must have sufficient cement to fill the annular space behind the pipe to the mud line (however, cement may be washed out or displaced to a maximum depth of 50 feet below the mud line to facilitate pipe removal on abandonment). – The surface casing must be set and cemented in prior to penetration of known shallow oil and gas formations, or upon encountering previously unknown formations. – The surface casing must be set prior to drilling below 3,500 feet TVD. – The surface casing must be set to a minimum depth as follows: ♦ 25% of the proposed total depth of the well, for wells with a proposed total vertical depth < 7,000 feet; ♦ 2000 feet for wells with a proposed total vertical depth between 7,000 and 10,000 feet; or ♦ 2,500 feet for wells with a proposed total vertical depth > 10,000 feet; – The cement of the surface casing must stand under pressure for a minimum of eight hours before plugs are drilled or tests are initiated. – The surface casing must be pressure tested pressure to at least 1,000 psi and show a drop of less than 100 psi during a 30-minute test period. If the casing fails the test, it must be condemned until the leak is corrected. • The production casing or oil string must meet all of the following requirements: (16 TAC 3.13(c)(1)(C)) – The production casing or oil string must be new or reconditioned pipe with a mill test of at least 2,000 psi that has been tested to at least 2,000 psi. – After cementing, the production casing or oil string must be tested by pump pressure to at least 1,500 psi and show a drop of less than 150 psi during a 30-minute test period. If it fails the test, it must be condemned until the leak is corrected. – The production casing or oil string must be cemented by the pump and plug method using sufficient cement to fill the calculated annular space above the shoe to protect any prospective producing horizons and to a depth that isolates abnormal pressure from normal pressure (0.465 gradient). OILGASSD TEXAS Summary S-31 - 5/13
  • 26. – • • • • • The production casing or oil string must have a float collar or other means to stop the cement plug inserted in the casing string above the shoe. – The cement of the production casing or oil string must stand under pressure for a minimum of eight hours before the plug is drilled or tests are initiated. Before drilling occurs below the conductor casing, at least one remotely controlled blowout preventer must be installed with a mechanism for automatically diverting the drilling fluid to the mud system when the blowout preventer is activated. (16 TAC 3.13(c)(2)(A)) After setting and cementing the surface casing, the following requirements must be met: (16 TAC 3.13(c)(2)(B)) – A minimum of two remotely controlled hydraulic ram-type blowout preventers (one equipped with blind rams and one with pipe rams), valves, and manifolds for circulating drilling fluid must be installed to control the well at all times. – The ram-type blowout preventers, valves, and manifolds must be tested to 100% of rated working pressure. – The annular-type blowout preventer must be tested to 1,000 psi at the time of installation. – During drilling and completion operations, the ram-type blowout preventers must be tested by closing at least once each trip and the annular-type preventer must be tested by closing on drill pipe once each week. During drilling, the well must be fitted with the following: (16 TAC 3.13(c)(3)) – an upper kelly cock in proper working order that is able to close in the drill string below the hose and swivel when necessary for well control; – with a lower kelly safety valve installed so that it can be run through the blowout preventer. When needed for well control, at all times the rig floor must have the following: (16 TAC 3.13(c)(3)) – a full-opening safety valve of similar design as the lower kelly safety valves; and – an inside blowout preventer valve with sufficient wrenches, handling tools, and necessary subs for all drilling pipe sizes in use. Characteristics, use, and testing of drilling mud must meet the following requirements: (16 TAC 3.13(c)(4)) – The mud program and the manner in which drilling is conducted must be able to prevent the blowout of any well. – Adequate supplies of mud of sufficient weight and other acceptable characteristics must be maintained. – Frequent mud tests must be conducted. – Adequate mud testing equipment must be kept on the drilling platform at all times. – The hole must be kept full of mud at all times. – When pulling drill pipe, the mud volume required to fill the hole each time must be measured to ensure that it corresponds with the displacement of the pipe pulled. – One or more indicators must be installed on the derrick floor, recording mud pit levels at all times. – Workers must keep careful watch for swabbing action when pulling out of the hole. – Mud-gas separation equipment must be installed and operated. OILGASSD TEXAS Summary S-32 - 5/13
  • 27. • • • • • All wells must be equipped with casingheads that are of sufficient rated working pressure and that have adequate connections and valves available to permit pumping mud-laden fluid between any two strings of casing at the surface If leaking gas or oil is noted between the surface casing and the oil string, or if sustained pressure is noted on the casinghead that cannot be explained as other than a casing leak, the well must be killed with water or mud and pump pressure applied. If the pressure shown on the casinghead gauge reflects the pump-applied pressure, the casing must be condemned, corrective measures must be taken, and the casinghead must be retested. (16 TAC 3.13(c)(5)) All completed wells must be equipped with Christmas tree fittings and wellhead connections that meet the following requirements: (16 TAC 3.13(c)(6)) – Such fittings and connections must have a rated working pressure equal to or greater than the surface shut-in pressure of the well. – The tubing must be equipped with the following: ♦ a master valve if surface pressures are less than or equal to 5,000 PSI; or ♦ two master valves if surface pressures are > 5,000 psi; and – The fittings and connections must be assembled and tested by a fluid pressure equal to the test pressure of the fitting employed prior to installation. A storm choke or similar safety device must meet all of the following requirements: (16 TAC 3.13(c)(7)) – The storm choke or similar device must be installed in the tubing of all completed flowing wells to a minimum of 100 feet below the mud line. – The tubing-casing annulus must be sealed below the mud line. – A safety valve must be installed at the wellhead downstream of the wing valve. – Check valves must be installed at all connections to the wellhead from all oil, gas, and geothermal resource gathering lines. All gathering pipelines designed to transport oil, gas, condensate, or other oil or geothermal resource field fluids from a well or platform must be equipped with automatically controlled shut-off valves at critical points in the pipeline system. All other safety equipment must be in full working order as a safeguard against spillage from pipeline ruptures. (16 TAC 3.13(c)(8)) All tool pushers, drilling superintendents, and operators' representatives in control of the drilling on lands underlying fresh or marine waters must have a certification that is less than two years old demonstrating satisfactory completion of a USGS-approved school (or refresher course) on well control equipment and techniques. (16 TAC 3.13(c)(9)) General RRC Requirements for All Wells • All wells must be equipped with a Bradenhead. The following safeguard must be met: (16 TAC 3.17) – If pressure develops between any two strings of casing, the RRC district office must be notified immediately. No cement may be pumped between any two strings or pipe at the top of the hole, unless the RRC district office has granted permission. – Any well that is leaking gas, oil, or geothermal resources between the surface and the production or oil string or that is showing pressure on the Bradenhead must be tested in the following manner (unless the origin of the pressure can be determined in another manner): ♦ The well must be killed and pump pressure applied through the tubing head. OILGASSD TEXAS Summary S-33 - 5/13
  • 28. • • • • • • • • ♦ If the pressure gauge on the Bradenhead reflects the applied pressure, the casing must be condemned and a new production or oil string run and cemented. When coming out of the hole with the drill pipe, drilling fluid must be circulated until equalized, and a fill-up line must be turned into the casing to ensure a full load of fluid is on the bottom of the hole at all times. (16 TAC 3.18) Cable tool drilling must meet all of the following requirements: (16 TAC 3.19) – No operator may drill into a known oil, gas, or geothermal resource producing formation that has either of the following: ♦ water from a higher formation in the hole; or ♦ a sufficient head of water introduced into the hole to prevent gas blowing to the surface; – The well must be managed in either of the following manners: ♦ allowed to blow until it has been drilled-in (but in no case is gas allowed to blow for a more than three days after completion of the well); or ♦ drilled under a head of fluid whose weight averages at least 9 1/2 pounds per gallon; however, the fluid’s average weight should be 91 pounds per gallon if mud-laden fluid is used for protecting oil, gas, or geothermal resource bearing sands in upper formations while the oil, gas, or geothermal resource is being produced from deeper formations. Unless RRC has granted an exception, no oil, gas, or geothermal resource well may be drilled closer than the following distances: (16 TAC 3.37(a)) – 1,200 feet from any well completed in or drilling to the same horizon on the same tract or farm; or – 467 feet from any property line, lease line, or subdivision line. Wells drilled in violation of the minimum distances or in violation of an order by RRC are not permitted to produce oil, gas, or geothermal resources and must be plugged. (16 TAC 3.37(e)) Drilling of a well may not be commenced until RRC has approved the location. (16 TAC 3.37(f)) Permits to drill a well under a distance exception expire two years from the effective date of the permit unless drilling operations are commenced in good faith within the two-year permit period. (16 TAC 3.37(i)) Unless RRC has granted an exception, oil, gas, and or geothermal resource wells must meet the following spacing requirements: (16 TAC 3.38(b)) – The wells may not be drilled on substandard acreage (that is, less acreage than the smallest amount established for standard or optional drilling units). – The wells must be drilled on units in accordance with either special, country regular, or statewide spacing rules (see density requirements in 16 TAC 3.38(b)(2)). Permits to drill a well under a density exception expire two years from the effective date of the permit unless drilling operations are commenced in good faith within the two-year permit period. (16 TAC 3.37(i)) OILGASSD TEXAS Summary S-34 - 5/13
  • 29. Horizontal Drainhole Wells • A horizontal drainhole well is any well that is developed with one or more horizontal drainholes having a horizontal drainhole displacement of at least 100 feet (see 16 TAC 3.86(a)). • All wells developed with horizontal drainholes must comply with 16 TAC 3.37 (Spacing Rule), and no point on a horizontal drainhole may be drilled closer than the following distances: (16 TAC 3.86(b)) – 1,200 feet (horizontal displacement) to any point along any other horizontal drainhole in another well, or to any other well completed or drilling in the same field on the same lease, pooled unit, or unitized tract; or – 467 feet from any property line, lease line, or subdivision line. • All proration and drilling units must consist of continuous and contiguous acreage, and proration units must consist of acreage that can be reasonably considered to be productive of oil or gas. (16 TAC 3.86(d)(3)) • All points on the horizontal drainhole must be within the proration and drilling unit. (16 TAC 3.86(d)(4)) • The maximum daily allowable for a horizontal drainhole well must be determined by multiplying the following: – the applicable allowable for a vertical well in the field with a proration unit containing the maximum acreage authorized by the applicable rules for the field, exclusive of tolerance acreage; and – the fraction defined as follows: ♦ the numerator: the acreage assigned to the horizontal drainhole well for proration purposes; and ♦ the denominator: the maximum acreage authorized by the applicable field rules for proration purposes, exclusive of tolerance acreage. Note: The maximum daily allowable must be adjusted in accordance with 16 TAC 3.49(a) (GasOil Ratio), when applicable. (16 TAC 3.86(d)(5)) • The maximum diagonal for each proration unit containing a horizontal drainhole well must be the horizontal drainhole displacement of the longest horizontal drainhole for the well plus either of the following: (16 TAC 3.86(d)(6)) – 2,100 feet for fields that are regulated under statewide rules; or – the maximum diagonal allowed for fields where the special field rules specify a maximum diagonal. • A single well developed with more than one horizontal drainhole originating from a single vertical wellbore must be treated as a single well. The horizontal drainhole displacement used for calculating additional acreage assignment, however, must be the horizontal drainhole displacement of the longest horizontal drainhole plus the projection of any other horizontal drainhole on a line that extends in a 180 degree direction from the longest horizontal drainhole. (16 TAC 3.86(e)) • An allowable will not be assigned to any horizontal drainhole well unless the following items have been filed with and accepted by RRC: (16 TAC 3.86(f)(3) and 3.86(f)(4)) – a directional survey and survey plat; and – a proration unit plat. OILGASSD TEXAS Summary S-35 - 5/13
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