Control Measures

 What are Control Measures?

Metrics to measure an operator’s governance and risk management protocols relative to environmental risk.

Well Integrity

  1. Does the operator have wellhead design standards which determine material class, temperature, and pressure requirements
  2. Does the wellhead have dual master valves and/or a surface safety valve?
  3. Does the operator have a scheduled greasing program for preventative maintenance on all wellhead valves that does not exceed every two years?
  4. Does the operator grease wellhead valves as needed?
  5. Is all wellhead equipment appropriately inspected and tested using non-destructive testing (pressure/hydro)?
  6. Does the operator have a 2-barrier policy for operations/workovers at the wellhead?
  7. Are side outlet valves installed on annuli?
  8. Are protective barriers in place preventing collision with the wellhead/tree?
  9. Does manufactured wellhead equipment meet industry standards (API 6A) and quality control requirements?
  10. Were all wellhead/tree components tested upon installation?
  11. Are wing valves accessible and appear in working order?
  12.  
  1. Does the operator have a basis of design that incorporates surface casing stress check (triaxial adjustment & temperature gradients)?
  2. Does the operator have a basis of design that does NOT incorporate surface casing stress check (triaxial adjustment & temperature gradients)?
  3. If an operator does not have a basis of design, does the operator have a surface casing stress check evaluation including triaxial/biaxial stress check?
  4. Has the operator run a simple surface casing design (i.e. Excel) validating collapse/burst competency but did not incorporate triaxial stress or temperature gradients?
  5. Has a Pore Pressure (PP) vs Frac Gradient (FG) curve has been created for the basin (unconventional reservoir) or well (if other)?
  6. Is the surface casing string designed with >1.1 Burst Safety Factor
  7. Is the surface casing string designed with >1.125 Collapse Safety Factor?
  8. Is the surface casing strings designed with >1.6 Tension Safety Factor or 100,000 lbs overpull?
  9. If an operator does not have a basis of design that incorporates surface casing requirements, does the operator rely on regulations for wellbore construction practices?
  10. Was corrosion, H2S, CO2, and/or potential hazards considered in surface casing material selection within drilling program or basis of design?
  11. Was connection axial strength considered when selecting surface casing?
  12. Are MASP values calculated or established for the surface hole section?
  13. Was a FIT (formation integrity test) done for surface casing section?
  14. Are surface casing pressure tests greater than calculated MASPS or 70% of burst (if regulations prohibit tests to this value select yes)
  15. Are surface casing pressure tests done per regulatory standards
  16. Does the operator have a Basis of Design (BOD) that incorporates a procedure to determine the set depth of surface casing?
  17. Does the operator use offset wells/logs to determine the precise depth of aquifer depth for surface casing?
  18. If an opeator does not have a basis of design, does the operator rely on regulations for setting surface casing?
  19. Are make up torques specified for surface casing?
  20. Are mud properties/parameters specified for surface casing in drilling programs?
  21. Was additional circulation/conditioning done prior to running surface casing (short trips, circulation, etc.)?
  22. The operator relies on standard basin knowledge beyond regulation when selecting surface casing?
  23. Does the company obtain mill run reports or a QAQC requirement for surface casing?
  24. Does the company clean, drift, and inspect surface casing prior to running?
  1. Does the operator have a basis of design that incorporates intermediate casing stress check (triaxial adjustment & temperature gradients)?
  2. Does the operator have a basis of design that does NOT incorporate intermediate casing stress check (triaxial adjustment & temperature gradients)?
  3. If an operator does not have a basis of design, does the operator have a intermediate casing stress check evaluation including triaxial/biaxial stress check?
  4. Has the operator run a simple intermediate casing design (i.e. Excel) validating collapse/burst competency but did not incorporate triaxial stress or temperature gradients?
  5. Has a Pore Pressure (PP) vs Frac Gradient (FG) curve has been created for the basin (unconventional reservoir) or well (if other)?
  6. Is the intermediate casing string designed with >1.1 Burst Safety Factor?
  7. Is the intermediate casing string designed with >1.125 Collapse Safety Factor?
  8. Is the intermediate casing strings designed with >1.6 Tension Safety Factor or 100,000 lbs overpull?
  9. If an operator does not have a basis of design that incorporates intermediate casing requirements, does the operator rely on regulations for wellbore construction practices?
  10. Was corrosion, H2S, CO2, and/or potential hazards considered in intermediate casing material selection within drilling program?
  11. Are MASP values calculated for the intermediate hole section?
  12. Are intermediate casing pressure tests greater than calculated MASPS or 70% of burst (if regulations prohibit tests to this value select yes)?
  13. Are intermediate casing pressure tests done per regulatory standards?
  14. Are gas tight premium or semi-premium thread connections utilized on intermediate casing?
  15. Are intermediate casing connections measured/documented (torque monitoring) and provided to the company?
  16. Was connection strength considered when selecting intermediate casing?
  17. Are make up torques specified for intermediate casing?
  18. If an operator does not have a basis of design that incorporates intermediate casing requirements, does the operator rely on regulations for wellbore construction practices?
  19. The operator relies on standard basin knowledge beyond regulation when selecting intermediate casing?
  20. Does the operator have a Basis of Design (BOD) that incorporates a procedure to determine the set depth of intermediate casing?
  21. Are mud properties/parameters specified for intermediate casing in drilling programs?
  22. Were short-trips conducted prior to running intermediate casing?
  23. Was additional circulation time done prior to running intermediate casing?
  24. Does the company obtain mill run reports or a QAQC requirement for intermediate casing?
  25. Does the company clean, drift, and inspect intermediate casing prior to running?
  1. Does the operator have a basis of design that incorporates production casing stress check (triaxial adjustment & temperature gradients)?
  2. Are gas tight, premium thread connections utilized on production casing?
  3. Has the operator run a simple production casing design (i.e. Excel) validating collapse/burst competency but did not incorporate triaxial stress or temperature gradients?
  4. Has a Pore Pressure (PP) vs Frac Gradient (FG) curve has been created for the basin (unconventional reservoir) or well (if other)?
  5. Is the production casing string designed with >1.1 Burst Safety Factor?
  6. Is the production casing string designed with >1.125 Collapse Safety Factor?
  7. Is the production casing strings designed with >1.6 Tension Safety Factor or 100,000 lbs overpull?
  8. If an operator does not have a basis of design that incorporates production casing requirements, does the operator rely on regulations for wellbore construction practices?
  9. Does the operator have a basis of design that does NOT incorporate production casing stress check (triaxial adjustment & temperature gradients)?
  10. If an operator does not have a basis of design, does the operator have a production casing stress check evaluation including triaxial/biaxial stress check?
  11. Are MASP values calculated for the production hole section?
  12. Are production casing pressure tests greater than calculated MASPS or 70% of burst (if regulations prohibit tests to this value select yes)?
  13. Are production casing pressure tests done per regulatory standards?
  14. Was corrosion, H2S, CO2, and/or potential hazards considered in production casing material selection within drilling program?
  15. If production casing uses premium or semi-premium threaded connections measured/documented (torque monitoring) and provided to the company?
  16. Was connection strength considered when selecting production casing?
  17. Are make up torques specified in production casing for drilling programs?
  18. The operator relies on standard basin knowledge when selecting production casing?
  19. Are mud properties/parameters specified for production casing in drilling programs?
  20. Were short-trips conducted prior to running production casing?
  21. Was additional circulation time done prior to running production casing?
  22. Does the company obtain mill run reports or a QAQC requirement for production casing?
  23. Does the company clean, drift, and inspect production casing prior to running?
  1. Are centralizers run on each joint of surface casing?
  2. Are centralizers run on surface casing in accordance with regulatory standards?
  3. Does the operator use surface cement properties determined by parameters established in a Basis of Design?
  4. Was a standard surface cement design utilized for all wells in the area
  5. Is cement lab testing performed at bottom-hole temperatures obtained through temperature and pressure logs for surface casing design?
  6. Is cement lab testing performed at the anticipated bottom-hole temperature for surface casing design?
  7. Were bottomhole pressure and temperature considered in the surface casing design?
  8. Does the company leave at least 10 feet of rat-hole for surface casing?
  9. Was circulation done prior to beginning the surface cement job?
  10. Was a spacer pumped prior to pumping surface cement?
  11. Were surface cement strength and hardness requirements established for surface casing?
  12. Is a calculated wait on cement time based off cement properties utilized for surface casing?
  13. Is a standard wait on cement time utilized regardless of cement properties for surface casing?
  14. Was surface cement sampled while mixing and provided to the company representative for post job testing?
  15. For surface casing, is fluid loss or free water testing conducted during cement lab testing?
  16. Were two wiper plugs used during the surface cement job?
  17. Was one wiper plug used during the surface cement job?
  18. Is lift pressure recorded and monitored during the surface cement job?
  19. Was cement returned to surface during the surface casing cement job?
  20. Are operational indicators used to determine a successful surface cement job? (i.e. floats holding, returns, etc.)
  21. Does the company have contingency plans if surface casing cement is not seen at surface?
  22. Were surface cement post job reports provided to the operator by the cementing company?
  1. Is the intermediate casing centralization design created using standoff calculations or centralization modeling, and specified in the Basis of Design?
  2. Are centralizers run on each joint of intermediate casing?
  3. Does the centralization program for intermediate casing match industry standards?
  4. Are centralizers run on intermediate casing in accordance with regulatory standards?
  5. Is a viscous pill or spacer pumped prior to cementing intermediate casing?
  6. Does the company leave at least 10 feet of rat-hole for intermediate casing?
  7. Does the Basis of Design or Drilling Program outline potential trouble zones?
  8. Was consideration given to annulus monitoring when designing intermediate casing cement volumes?
  9. Was the intermediate top of cement based on regulatory requirements?
  10. Was an excess percent of intermediate casing cement planned for and specified in the drilling program?
  11. Was intermediate casing cement volume based on vendor recommendations or area experience?
  12. Does the operator use well specific intermediate casing cement programs?
  13. Were any additional logging runs conducted on the intermediate casing beyond a cement bond log?
  14. Does the operator have pre-determined criteria stipulating when and how intermediate cement remediation will take place?
  15. Has the operator outlined intermediate cement strength and hardness requirements?
  16. Was intermediate cement designed to cover the previous shoe or returned to surface?
  17. Was intermediate cement lab testing performed at anticipated bottom-hole temperature for intermediate casing?
  18. Was fluid loss or free water testing conducted during cement lab testing for intermediate casing?
  19. Were cement rheology properties, compressive strength, and thickening time tested on intermediate cement?
  20. Were cement reports from offset wells reviewed to validate trouble zones when designing the intermediate cement? (i.e., flow zones or gas influx must be outlined in the drilling program)
  21. Is intermediate cement lab testing performed at actual bottom-hole temperature and pressure obtained through measurements?
  22. Was the pipe rotated OR reciprocated during the intermediate cement job?
  23. Was the pipe only moved during circulation prior to the intermediate cement job?
  24. Were two wiper plugs used during the intermediate cement job?
  25. Was one wiper plug used during the intermediate cement job?
  26. Did the spacer contain any surfactant or chemical flush?
  27. Are cement bond logs run on intermediate casing?
  28. Are operational indicators used to determine a successful intermediate cement job? (i.e. floats holding, returns, etc.)
  29. Was the pipe rotated AND reciprocated during intermediate cement job?
  30. Is the operator prepared to execute remedial intermediate cementing as required?
  31. Were intermediate cement post job reports provided to the operator by the cementing company?
  1. Is the production casing centralization design created using standoff calculations or centralization modeling, and specified in the Basis of Design?
  2. Are centralizers run on each joint of production casing?
  3. Does the centralization program for production casing match industry standards?
  4. Are centralizers run on production casing in accordance with regulatory standards?
  5. Is a viscous pill or spacer pumped prior to cementing production casing?
  6. Does the company leave at least 10 feet of rat-hole for production casing?
  7. Does the operator use well specific production casing cement programs?
  8. Was consideration given to annulus monitoring when designing production casing cement volumes?
  9. Was production casing cement design based on regulatory requirements?
  10. Does the Basis of Design or Drilling Program outline potential trouble zones?
  11. Was an excess percent of production casing cement planned for and specified in the drilling program?
  12. Was production casing cement volume based on vendor recommendations or area experience?
  13. Were any additional logging runs conducted on the production casing beyond a cement bond log?
  14. Does the operator have pre-determined criteria stipulating when and how production cement remediation will take place?
  15. Has the operator outlined production cement strength and hardness requirements?
  16. Was production cement designed to cover the previous shoe or returned to surface?
  17. Was production cement lab testing performed at anticipated bottom-hole temperature for production casing?
  18. Was fluid loss or free water testing conducted during cement lab testing for production casing?
  19. Were cement rheology properties, compressive strength, and thickening time tested on production cement?
  20. Were cement reports from offset wells reviewed to validate trouble zones when designing the production cement? (i.e., flow zones or gas influx must be outlined in the drilling program)
  21. Is production cement lab testing performed at actual bottom-hole temperature and pressure obtained through measurements?
  22. Was the pipe rotated OR reciprocated during the production cement job?
  23. Was the pipe only moved during circulation prior to the production cement job?
  24. Were two wiper plugs used during the production cement job?
  25. Was one wiper plug used during the production cement job?
  26. Did the spacer contain any surfactant or chemical flush?
  27. Are cement bond logs run on production casing?
  28. Are operational indicators used to determine a successful production cement job? (i.e. floats holding, returns, lift pressures, weight/density, etc.)
  29. Was the pipe rotated AND reciprocated during production cement job?
  30. Is the operator prepared to execute remedial production cementing as required?
  31. Were production cement post job reports provided to the operator by the cementing company?
  1. Were multiple laters of impermeable containment utilized? (Does not include earthen berms or soil cementing.)
  2. Were all tanks, vessels, and rotating equipment ENTIRELY situated on impermeable containment?
  3. Were all tanks, vessels, and rotating equipment PARTIALLY situated on impermeable containment?
  4. Does the operator perform pre and post job water testing on water wells within the monitoring area?
  5. Does the operator perform pre and post job surface water testing?
  6. Does the operator have a response plan in place if offset well communication is observed?
  7. Does the operator meet with service companies at predetermined intervals to discuss lessons learned and process improvement?
  8. Does the operator activily interact with the service company to optimize frac equipment placement?
  9. Does the operator have a pad plot plan with frac equipment locations identified?
  10. Does the operator have documented contingency plans in place for wireline operational hazards?
  11. Does the operator rely on the experience of on-site representatives to overcome frac operational hazards?
  12. Is there a policy in place to test casing to maximum allowable surface pressure during toe prep?
  13. Has the operator incorporated measured reservoir parameters from pilot wells into the design?
  14. Does the operator utilize a permanent frac water transfer line?
  15. Does the operator utilize a temporary frac water transfer line?
  16. Does the operator truck in frac water?
  17. Does the operator have standardized operating procedures for pressure testing?
  18. Does the operator have documented evidence that they reached the maximum allowable pressure during the pressure test?
  19. Does the operator perform pressure tests prior to each frac stage?
  20. Does the operator perform pressure tests only after iron connections are broken?
  21. Does the operator utilize addressable switches/guns?
  22. Does the operator utilize a prewired modular gun system?
  23. Does the operator utilize traditional EB switches?
  24. Does the operator utilize riglock or other wellhead pressure management systems?
  25. Does the operator utilize a greaseless wireline system?
  26. Are offset wells continuously monitored with real time pressure plots and streamed to the data van or control center?
  27. Are offset wells continously monitored?
  28. Does the operator have a plan to notify external operators prior to the start of frac?
  29. Does the operator utilize Electric Frac Fleets?
  30. Does the operator implement wellhead technologies to reduce red zone entry?
  31. Does the operator utilize physical modeling technologies such as tracers, fiber optics, or microseismic to validate their frac design?
  32. Does the operator perform simulations to validate their frac design?
  33. Does the operator rely solely on basin experience to create their frac design?
  34. Does the completion program outline potential faults?
  35. Does the operator have documented contingency plans in place for frac operational hazards?
  36. Does the operator have a task matrix or equivalent outlined in the completion program?
  37. Are maximum pressures during frac operations established AND written in the completion program?
  38. Are maximum pressures during frac operations established?
  39. Does the operator have documented evidence of pre-job safety meetings?
  40. Are desired rates, volumes and concentrations established in the completion program?
  41. Does the operator require pre-frac fluid system testing such as pilot tests, chemical tests and water analysis?
  42. Is equipment such as chemical additive pumps, densitometers and accumulators calibrated prior to the frac?
  43. Is the testing parameters for equipment such as the chemical additive pumps, densitometers and accumulators listed and specified in the completion program?
  44. Is there a policy in place to pressure test frac equipment and iron to maximum allowable operating pressure?
  45. Are various areas of frac operations clearly defined and separated by physical barriers such as chains, cones, or cement blocks based on potential risk?
  46. Are various zones of frac operations defined but NOT separated by physical barriers such as chains, cones, or cement blocks?
  47. Is there a policy in place that prohibits red zone entry while pumping.
  48. Does the operator utilize electric wireline winches?
  49. Does the operator drain the lubricator prior to breaking connection from well?
  50. Is a monoline utilized instead of standard wing connections?
  51. Are safety valves, reliefs, and pop-offs set and tested prior to frac?
  52. Is the frac tree tested to maximum allowable operating pressure prior to frac?
  53. Does the post job frac report contain annuli pressures?
  54. Does the post job frac report contain actual treating pressures and rates?
  55. Does the post job frac report contain material balance, proppant, and additives used?
  56. Is a post job report provided to the operator after the frac?
  57. Does the operator utilize a remote valve actuation system?
  58. Does the operator exclusively utilize manual turn valves?
  59. Does the operator have a designated frac valve team that must be present whenever a valve is operated?
  60. Does the operator utilize frac valve sign off sheets?
  61. Are frac iron and valve arrangement confirmed prior to each frac stage?
  1. Are all wellhead pressures monitored via SCADA, including all anulli?
  2. Is full-time gas monitoring conducted at the wellhead to locate wellhead leaks, such as using site level continuous monitoring?
  3. Does the company trend SCADA pressure data to draw predictive analysis with regards to well performance and integrity?
  4. Does the company trend SCADA pressure data as needed only as part of an after action review or after a critical event?
  5. Does the operator have an annular management program to respond to annular communication, such as using a diagnostic flowchart?
  6. Are there abnormal pressure alarms or shutdowns on the wellhead annuli and is pressure continuously recorded in a SCADA historian?
  7. Are there abnormal pressure alarms or shutdowns on the wellhead and is pressure continuously recorded in a SCADA historian?
  8. Has the operator established both MAASP's and MAOP operating pressure for annuli?
  9. Does the operator have a well start-up procedure?
  10. Is cathodic protection in place on the wellhead or has the operator determined that cathodic protection is not necessary?
  11. If the company does not utilize SCADA, are pressures manually acquired and recorded per company/regulatory requirements?
  12. Is valve function and pressure testing regularly completed on the wellhead in accordance with regulatory requirements?
  13. Are pressure anamolies reported and mitigated per regulatory requirements?
  14. Does the operator have detailed wellbore schematics, such as including casing shoe depth, top of cement, packer locations, etc.?
  15. Does the operator have documented approved wellbore barrier diagrams/schematics and testing requirements for each phase of operations (drilling, completions, production, and workovers)?
  16. Does the operator have documented approved wellbore barriers and testing requirements for each phase of operations (drilling, completions, production, and workovers)?
  17. Does the company have remote-activated ESDs installed on location?
  18. Does the company have ESDs on location, but are not remote-activated? 

Environmental Performance

  1. Does the operator stack test engines per regulatory requirements?
  2. Is catalyst inlet temperature and differential pressure recorded?
  3. Is continuous monitoring conducted for catalyst inlet temperature and differential pressure?
  4. Are on-site/field compressors run off of the electric grid or has analysis been conducted to assess grid GHG emissions?
  5. Does the operator use electric drill rigs?
  6. Is onsite power tied to the local grid?
  7. Does the operator use electric frac fleets (e-fracs)?
  8. Does the operator utilize a combination of electric drilling engines in conjunction with diesel engines?
  9. Are natural gas powered generators used for onsite power generation?
  10. Does the operator utilizes compressed natural gas (CNG) for their frac operations?
  11. Does the company utilizes dual fuel or natural gas for drilling rigs?
  12. Does the company utilizes dual fuel or natural gas for frac fleets?
  13. Are all diesel engines (for drilling and completions) Tier 4 engines?
  14. Does the company have a policy in place to reduce vehicle idle time?
  15. Are on-site/field compressors run off natural gas?
  16. Is equipment/technology utilized to reduce emissions beyond regulatory requirements?
  17. Are deliberate efforts made to reduce trucking distances?
  18. Are all other combustion sources operated in compliance with regulatory requirements?
  1. 100% of water used for operations is recycled/reused water.
  2. Does the company develop/deploy innovative means by which fresh-water use is offset?
  3. Does the operator collaborate with NGO's, academia, communities, and agencies to ensure that long-term and large scale operations are sustainable and efficient?
  4. The operator conduct groundwater testing on nearby wells after completions and at predetermined intervals during production.
  5. Does the operator conduct water testing on nearby wells at predetermined intervals after completions for at least the first 3 years of production?
  6. Is greater than 75% of flowback water recycled or re-used?
  7. Is greater than 75% of produced water recycled or re-used?
  8. Does the operator makes efforts to source non-competitive water (TDS > 3000ppm) for use in operations?
  9. Has the company done any work or studies to understand the impact of operations on the local aquifer beyond regulatory requirement?
  10. Does the operator recycle or reuse between 25% - 75% of flowback water?
  11. Does the operator recycle or reuse between 25% - 75% of produced water?
  12. Does the operator work with with any regulatory agency to help mitigate operational impacts on local water infrastructure?
  13. Does the company minimize water use and consider local water uses and needs?
  14. Does the operator drill any ground water test wells for baseline analysis?
  15. Does the operator recycle or reuse less than 25% of produced water?
  16. Does the operator recycle or reuse less than 25% of flowback water?
  1. The company has eliminated flaring at the facility AND has clear shut-in procedures in the event of a release.
  2. Does the operator have a flaring SOP?
  3. Does the operator utilize a certified combustor or stack test to ensure destruction efficiency?
  4. Does the operator have a policy against flaring associated gas, except in the case of emergency?
  5. Are flared volumes metered and recorded?
  6. Are flared volumes estimated, instead of metered?
  7. Does the operator have a flaring SOP that addresses emissions reduction?
  8. Was a closed vent system analysis conducted to ensure combustor was sized appropriately?
  9. Do process flares include automated igniters?
  10. Is flaring equipment designed to be smokeless and achieve >98% methane destruction?
  11. Flaring issues are recorded, verbally communicated and corrected?
  12. Is there infrastructure in place for gas to go straight to sales at site initial production?
  13. Has there been a public commitment to the World Bank Flaring Initiative or an equivalent initiative (oil producers only)?
  14. Does the process flare/combustor include thermocouples to ensure the pilot is always on and an alarm if the flame is not detected (burner management system)?
  15. Is the telemetry configured to choke back or shut-in production to eliminate flaring?
  16. Are there no process flares on the pad/central processing facility, meaning no process gas flaring?
  1. Does the operator utilize continuous emissions monitoring technology, capable of quantifying total site emissions on a mass basis, as defined by USEPA?
  2. Does the operator utilize commercial, concentration-based continuous emissions monitoring technology for leak detection and repair (LDAR)?
  3. Are zero-bleed pneumatic controllers utilized at the site?
  4. Is there a basin-level pneumatic retrofit plan in place with the percentage of pneumatic retrofits documented?
  5. Are OGI surveys conducted on a monthly basis?
  6. The company has implemented a retrofit program to zero-bleed pneumatics on some, but not all existing facilities.
  7. Are OGI suveys conducted on a monthly or more frequent basis?
  8. Are OGI surveys conducted on a quarterly basis?
  9. Are OGI surveys conducted on a bimonthly basis?
  10. Are OGI surveys conducted on a semi-annual basis?
  11. Are OGI surveys conducted on an annual basis?
  12. Is aerial/drone monitoring technology being used?
  13. Is satellite monitoring technology being used?
  14. Does the operator have an established procedure for all vessel blowdowns or maintenance to minimize emissions?
  15. Is there a policy in place for liquid blowdowns, including no unmanned blowdowns?
  16. Are vapor recovery units (VRU's) installed and operational to control tank emissions at production facilities?
  17. Is associated (not annular) gas routed to a pipeline?
  18. Does the company have documented estimates of venting volumes (operational & fugitive)?
  19. Are low bleed pneumatic controllers utilized at the site?
  20. Are AVO inspections performed on sites that are not subject to OGI suvey requirements?
  21. Is compressor rod packing changed out every 26,000 hours, if applicable?
  22. Do all completions utilize reduced emissions completions or "green" completions?
  23. Have the NSPS control requirements (or equivalent) been met for oil, condensate, and produced water tanks at the site?
  24. Are there vapor recovery lines on all oil or condensate loadouts?
  1. Are doubled walled vessels utilized in conjunction with secondary containment?
  2. Is real time leak detection in place while utilizing temporary pipe?
  3. Are all tanks and vessels tied to SCADA with shut in capabilties?
  4. Does the operator witness (in person or through a digital command center) all fluid transfers in produciton operations?
  5. Are all fluids, solids, and processing equipment contained within impermeable secondary containment?
  6. Are historical spills and lessons learned documented and available for review?
  7. Does management personnel actively participate in training drills and exercises relating to spills?
  8. SCADA and level indicators are installed on uprights with the ability to shut-in the well?
  9. Does temporary pipe in production operations have shutdowns in place?
  10. Is permanent pipe inspected at regular intervals and documented?
  11. Are spill prevention protocols and lines of communication established?
  12. Is lightning protection in place with regular inspection and/or maintenance programs?
  13. Is permanent pipe designed to account for corrosion, leak detection, and pressure relief?
  14. Does temporary pipe have established pop-offs and inspections plans are in place?
  15. Is frac equipment stored in/on temporary secondary containment?
  16. Are contractors required to abide by the operator's secondary containment rules?
  17. Does the spill response plan contain spill mitigation methodology, clean-up techniques, critical areas and species?
  18. Are necessary personnel trained initially with annual follow-ups?
  19. Has management established spill KPI's?
  20. Are rules and regulations are strictly followed pertaining to hazardous chemicals and secondary containment?
  21. Are tank batteries suited for production volumes and pressures?
  22. Are timely visual inspections conducted on tank batteries and secondary containment?
  23. Is temporary pipe designed for required pressure and fluid types?
  24. Is temporary pipe tested to at least 10% above operating pressures?
  25. Is permanent pipe designed for required pressure and fluid types?
  26. Is permanent pipe tested to at least 10% above operating pressures?
  27. Does the operator comply with the more stringent of either their own or vendors policies pertaining to spills?
  28. Do load points have catch basins?
  29. Are provisions in place for load lines to traverse along secondary containment?
  30. Are fluid transportation companies are vetted by the operator?
  31. Does the company comply with all regulation pertaining to secondary containment?
  32. Are basic spill reporting requirements established for personnel?
  33. Has management set clear expectations to strictly adhere to regulations?
  1. Does operator provide 3rd party spill response training (SpillPro, Oil Spill Response, NewPig) for internal spill response personnel?
  2. Does the operator track trucking spills off site (can be third party contractor truck driver, etc.)?
  3. Does the operator have a provision in its emergency response plan for offsite transporter accidents?
  4. Does the operator utilize a small spill tracker system to record non-recordable spills?
  5. Does the operator have a policy in place for a spill remedy plan including spill notification and response radius?
  6. Is remediation success monitored throughout project lifecycle and are follow up studies extended beyond regulations?
  7. Are non-reportable spills captured and reported to management on a monthly basis?
  8. Are non-reportable spills captured and reported to management on a quarterly basis?
  9. Is the landowner notified about the spill and provided a spill notification report?
  10. Was a soil sample collected after remediation and compared against the soil composition baseline samples?
  11. Was a soil sample collected to establish a soil composition baseline?
  12. Does the operator have a policy to begin spill response within 24 hours?
  13. Does the operator have a policy to begin spill response within 48 hours?
  14. Was remediation success monitored throughout project life, for example, through groundwater testing after a spill occurrence? Was remediation completed to meet state regulations?
  15. Does the spill response plan contain spill mitigation methodology and clean-up techniques?
  16. Does the spill response plan outline waste management arrangements and hazardous waste strategies for remediation?
  17. Does the spill response plan match critical areas and land sensitivities (i.e. Farmland, Urban/Community Impacts, Wetlands) with the appropriate remediation effort?
  18. Does the spill response plan have a spill response notification and action flow chart or RACI chart?
  19. Does the spill response plan contain names and telephone numbers of individuals to be contacted in the event of a spill?
  20. Does the spill response plan include basic spill reporting requirements?
  21. Does the operator have spill response equipment housed onsite, for example a spill kit?
  22. Does the operator have spill response equipment available at a nearby field office or facility if not on site?
  23. Are KPIs in place for spill recovery success or spill frequency?
  24. Does the operator perform any spill response training or exercises, for example spill size estimating, notification dry-run, or small equipment deployments?
  25. Was waste properly disposed of in an operator-approved facility after a spill event?
  26. Are the SDS for chemicals available on site and do they list any recommended spill clean up methods?
  27. Are the SDS for chemicals available online?
  28. Are OSHA/HAZWOPER training standards met?
  29. Are novel and innovative methods designed to proactively detect spills on the tanks?
  1. Does the operator utilize a closed loop D&C system, where D&C pits are eliminated?
  2. Are all new facilities designed to be tankless facilities?
  3. Has the operator drilled groundwater test wells at strategic locations or engage in a pre-drill sampling program to ensure historical (closed) pits maintain integrity?
  4. Are fluids sent directly into transport lines to a central gathering facility?
  5. Do facilities with oil/condensate tanks use a blanket gas system and locking thief hatches?
  6. Are drilling pits utilized for surface casing only using freshwater?
  7. Are all pits lined?
  8. Are upright tanks monitored through SCADA?
  9. Do upright tanks have high liquid level shut-down control?
  10. Is secondary containment lined and built with a fixed wall?
  11. Does the company conduct inspections and maintenance on all pits, tanks, impoundments, and associated equipment such as secondary containment and liners?
  12. If closed loop system is not utilized, are pits utilized for all hole sections?
  13. Are pits unlined and rely on clay/soil base?
  14. Are pits designed in compliance with regulatory requirements?
  15. Are pits closed per regulations?
  16. Is secondary containment an earthen berm?

Safety

  1. Is executive leadership demonstrably engaged in the emergency response plan?
  2. Does the operator perform and document competency testing for emergency response training for VP level and above, annually?
  3. Does the operator perform and document competency testing for emergency response training for operational staff and EHS team, annually?
  4. Does the operator perform competency testing for emergency response training for operational staff and EHS team?
  5. Does the operator perform emergency response training program that includes frequency, scenario, and discipline requirements?
  6. Does the ERP address the full range of emergency situations and engage all stakeholders?
  7. Does the ERP address basic operational contingencies such as blowouts, spills and significant air releases?
  8. Does the operator have an incident termination and business resumption plan?
  9. Does the company have a plan or system in place to educate the public who may be affected by emergency operations?
  10. Do annual and live event reviews and updates include all stakeholders and are distributed for review and training, organization-wide?
  11. Does the ERP incorporate strategy, tactics, required capabilities, risk assessment and business impact analysis?
  12. Does the company have an established "Incident Command System" responsible for resource allocation and deployment?
  13. Is the ERP a single, integrated plan that addresses most all operational scenarios and outcomes?
  14. Is the ERP reviewed/critiqued after use in an emergency response event?
  15. Does the operator have no-notice emergency response drills, including internal stakeholders and external stakeholders such as local first responders?
  16. Does the operator have emergency response drills, including including internal stakeholders such as field staff and executive leadership?
  17. Are emergency response tabletop exercises held at least annually?
  18. Are all emergency response drills and exercises documented with corrective actions deployed to appropriate personnel to improve performance?
  19. Do all emergency response drills and exercises have an post-exercise analysis?
  20. Are journey management systems are in place for company personnel?
  21. Are roles and responsibilities defined in a RACI chart within the ERP?
  22. Does the company have programs for incident management, hazard identification, and document control in effect?
  23. Does the operator have an emergency record-keeping process in place?
  24. Does the operator have a situational assessment and incident management plan?
  1. Does the operator have a formal process in place for continuous public input and engagement?
  2. Does the operator offer any education & awareness of oil and gas operations to the general public?
  3. Does the operator have a formal complaint registry?
  4. Does the operator have open lines of communication to the public?
  5. Does the operator engage with community stakeholders prior to pad development?
  6. Did the operator consider effects on the local community when selecting pad placement?
  7. Did the operator consider the effects of light, noise, dust, odor, and physical appearance prior to pad development?
  8. Does the operator consider traffic patterns and access routes prior to pad development?
  9. Does the operator consider impacts on local resources and infrastructure such first responders, lodging and services prior to pad development?
  10. Does the operator consider the operational impacts on community water sources and volumes prior to pad development?
  11. Does the operator monitor surface waters, aquifers and local ecosystems throughout project life?
  12. Does the operator monitor surface waters, aquifers and local ecosystems during construction and heavy operations phases?
  13. Does the operator perform surveys and test surface waters, aquifers and local ecosystems?
  14. Does the operator conduct visual checks on surface waters and local ecosystems WITHOUT the use of a baseline study?
  15. Does the operator conduct biological, botanical and archaeological surveys beyond regulatory requirement?
  16. Does the operator implement additional measures beyond regulatory requirement such as voluntary fencing, etc. during pad development?
  17. Does the operator consider water crossings and topography prior to pad development?
  18. Does the operator take landowner requests into consideration prior to pad development?
  19. Does the operator have long term planning and execution commities which take into account overall community and stakeholder impact as part of the area development plan?
  20. Does the operator consult and engage local authorities, first responders, and community representatives as part of the area development plan?
  21. Does the operator place emphasis on facility centralization?
  22. Does the operator consider existing gathering systems, pipelines, pads and existing infrastructure prior to pad development?
  23. Does the operator offer to temporarily relocate residents as a result of increased noise?
  24. Does the operator implement voluntary operating hours?
  25. Does the operator voluntarily measure and set limits on noise during operations?
  26. Does the operator utilize noise abatement equipment such as sound walls?
  27. Does the operator measure and set limits on noise during operations ONLY if required by law?
  28. Does the operator voluntarily measure and set limits on light during operations?
  29. Does the operator utilize light abatement equipment such as walls?
  30. Does the operator measure and set limits on light during operations ONLY if required by law?
  31. Does the operator take measures to orient light sources away from the community?
  32. Does the operator voluntarily pave roads?
  33. Does the operator voluntarily perform dust control and mitigation at regular intervals?
  34. Does the operator alter traffic routes to avoid causing excessive dust?
  35. Does the operator voluntarily enhance the aesthetics of sites?
  36. Does the operator engage in activities or plan operations which reduced trucking loads?
  37. Does the operator engage with the DOT, local authorities and other stakeholders to ensure regulatory compliance?
  38. Do waste management practices ensure that hazardous materials are sent to proper waste disposal facilities rather than municipal facilities?
  1. Does the operator utilize rotary steerable Bottom Hole Assemblies (BHA)?
  2. Does the operator categorize separation factors into different levels of risk with increased communication and survey frequency requirements?
  3. Does the operator increase survey frequency in areas with low separation factors less than 1.0?
  4. Does the operator have pre-determined actions when separation factors fall below minimum requirements?
  5. Does the drilling program identify potential well collision risks?
  6. Does the operator complete anti-collision calculations/modelling prior to drilling?
  1. Does the operator conduct regular well control drills such as BOPE function test, lubricator function test, etc. during completions operations?
  2. Are non-wellsite completions personnel such as completion engineers and supervisors Well Control Certified?
  3. Does the operator have established equipment spec requirements for BOPE types such as wireline, coil tubing, etc?
  4. Does the operator have established frac tree design requirements?
  5. Does the operator have established flowback plumbing layouts?
  6. Are well control considerations documented in the completions programs?
  7. Does the operator outline flowback details, risks, and limitations in the completion plans?
  8. Does the operator have established proximity and pressure requirements regarding offset monitoring?
  9. Are well control issues during completions communicated to management?
  10. Are flow checks conducted during completion operations?
  11. Are gas readings/fluid-cut monitored during completions operations?
  12. Are completions BOPE tested in accordance with regulatory requirements and standards?
  13. Are completion fluid weights recorded in real time & documented?
  14. Are wellsite completions personnel such as company representatives and crew leads Well Control Certified?
  15. Does the BOPE pressure rating exceed the maximum allowable operating pressure?
  16. Does the operator have established pop off pressures below the maximum equipment rating?
  17. Does the operator have documented pressure barrier policies outlining how two pressure barriers are maintained during completions operations?
  18. Is there a policy in place to pressure test production casing and surface equipment to maximum allowable operating pressure?
  19. Has the operator outlined monitoring details/requirements in the completion plan? (i.e. what data points need to be monitored and at what frequency)
  20. Does the operator have schematics for both the BOPE and Frac Tree?
  21. Does the operator have established pressure limits or anomalies for offset wells which would trigger immediate action?
  1. Are some or all personnel with responsibility for wellsite activities receive specialized training beyond the requirements of standard well control certification? (Murchison drilling school, etc.)
  2. When testing BOP's are BOP control system times, recharge, and back-up power sources tested?
  3. Are non-wellsite drilling personnel (drilling engineers) well control certified?
  4. Has the company has established requirements for BOP ram type, sizes, and configuration? (i.e. policy for BOP equipment specs)
  5. Has the company has established requirements for BOP auxiliary equipment (choke & kill valve, line, and manifold)?
  6. Does the operator have LCM ready/available during active drilling operations?
  7. Does the operator have completed surge/swab modeling for tripping and/or running casing?
  8. Does the company monitor & record any deviations from anticipated well design pressures? (may include tracking unplanned weight ups or unexpected loss zones)
  9. Are wellsite leaders (e.g. company man, tool pusher, driller) well control certified?
  10. Does the operator require well control drills on a regular basis? Drills can include kick detection, BOP function test, accumlator function test, etc.
  11. Are BOP's (rams/annular) tested per regulatory requirements & standards?
  12. Are choke & kill valves/manifolds tested per regulatory requirements & standards?
  13. Does the operator complete trip sheets?
  14. Does the operator have kick sheets available on location?
  15. Are flow-checks and displacement volume checks conducted during drilling operations to monitor the hydrostatic column?
  16. Does the company monitor for flow after cementing? (i.e. check that floats are holding, measure flowback volume, etc.)
  17. Are slow circulating rates calculated hourly (every 12 hours)?
  18. Does the operator have barrier diagrams outlining how 2 barriers are maintained during operations? (nippling down, BOP repair, etc.)
  19. Does the operator has an audit program specific to well control equipment (BOP & Choke Manifold) for times when BOP function is in doubt? (i.e. stacked rigs & new builds)
  20. Does the operator has documented inspection criteria to be implemented on BOP equipment after use in a well control incident?
  21. Is well control auxiliary equipment (choke manifold, standpipe, etc.) tested on the same frequency and same duration as BOP testing?
  22. Does the operator have a predetermined method of well control to be implemented during a well control incident? (Driller's Method, Weight & Wait)
  23. Does the operator have both BOP & Choke Manifold schematics?
  24. Does the operator have predetermined responsibilities documented for personnel involved in well control incidents? (Drilling Supervisor, Drilling Engineer, Toolpusher, etc.)

Community

  1. Does the operator have an existing waste management plan outlining waste minimization and/or recycling with key performance indicators?
  2. Does the operator have a leadership endorsed commitment to minimize waste and recycle?
  3. Is the waste management plan reviewed and revised annually?
  4. Is each waste stream individually addressed within the waste management plan?
  5. Is each waste stream properly characterized and sorted?
  6. Does the operator audit waste and wastewater disposal facilities with trained company personnel or contractors?
  7. Does the operator require operations and HSE involvement for the inspection and use of approved water and waste facilities?
  8. Is the waste management plan monitored for compliance?
  9. Are all waste quantities from generation, transport and disposal tracked and recorded?
  10. Does the operator store both waste manifests and change of custody records?
  11. Are approved waste disposal facilities communicated to operaitons?
  12. Are personnel engaged in programs to limit the use of hazardous materials?
  13. Does the waste management identify responsible and accountable personnel and train them appropriately?
  14. Are exempt and non-hazardous waste facilities clearly identified in the waste management plan and communicated to operations?
  15. Are the operators approved waste facilities audited every two years at minimum?
  16. Is the operators waste characterization reviewed every two years at minimum?
  17. Are the operators approved wastewater disposal facilities audited every two years at minimum?
  18. Does the operator have a specific policy, plan, or procedure for disposal of waste containers?
  19. Are all wastewater quantities from generation, transport and disposal tracked and recorded?
  20. Are volume capacity and characterization considered when approving disposal facilities?
  21. Are all waste transporters approved by the Department of Transportation (DOT) and in good standing?
  1. Does the operator check on the site after reclamation is deemed complete?
  2. Does the operator conduct any interim reclamation post drilling/completion activities such as shrinking the pad, etc?
  3. Does the operator account for compaction alleviation in the reclamation plan?
  4. Does the operator monitor the progress of reclamation efforts?
  5. Does the operator inspect the pad prior to commencing reclamation activities?
  6. Does the operator perform an invasive or protected species study as part of the reclamation process?
  7. Does the operator budget for reclamation and asset retirement?
  8. Does the operator take landowner inputs into consideration during the reclamation process?
  9. Does the operator remove all equipment as part of the reclamation process?
  10. Does the operator perform revegetation upon asset retirement (plug and abandonment)?

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