DRILLING/WORKOVER INSPECTION REPORT(rev 8/10)

DNR/OFFICE OF CONSERVATION ENGINEERING DIVISION

PART I GENERAL INFORMATION
OC
Well Name / Number / Serial Number
Field Name / Field Code / Section / Township / Range
Parish / Parish Code
Latitude (DMS) / Longitude (DMS) / Location
Land / Inland Water / Offshore
Contractor Name/Rig Name/Number / Rig Phone Number / Rig Type
Conventional / Barge / Jack-up
PART II BOP EQUIPMENT & WELL CONTROL INFORMATION
Diverter System
Y / N / Diverter Pressure Test Date / Diverter Test Pressure (psi) / Diverter Function Test Date
BOP Components
(check all installed) / Size / Type / Manufacturer/Model / Pressure Rating (Kpsi)
Annular
Pipe RAM
Pipe RAM
Blind RAM
Shear RAM
No. of Control Stations / Control Station Locations / Drill-string safety valve(s)?
Y / N / Accumulator Capacity (gal)
Last BOP Pressure Test Date / More than 14 days since last PT?
Y / N / RAM Test Pressures (low/high psi) / Annular Test Pressures (low/high psi)
Last BOP Function Test Date / More than 7 days since last FT?
Y / N / Control Station Used / Last Well Control Drill Date
Comments:
PART III CURRENT OPERATION(S)
Operation Type
Drilling / Completion / Workov / Work Permit # / Current MD / Current TVD / Current PBTD
Description of current activity:
PART IV DRILLING/WORKOVER FLUIDS
Fluid Type / Fluid Weight (ppg) / Funnel Viscosity (seconds)
Storage Type
Reserve Pit Closed-Loop System / Fluid Level Indicators/Alarms
Y / N / System Volume (bbls)
IN COMPLIANCE YES NO
Name of operator’s representative / Signature / Date/Time
ampm
Conservation Enforcement Agent / Signature

THIS FORM IS TO BE COMPLETED BY THE CONSERVATION ENFORCEMENT SPECIALIST (CES). ALL INFORMATION CONTAINED HEREIN IS TO BE VERIFIED BY THE CES USING THE OFFICIAL DRILLING RECORD(S).

DNR/OFFICE OF CONSERVATION, ENGINEERING DIVISION, P.O. BOX 94275, BATON ROUGE, LA 70804-9275

DRILLING/WORKOVER INSPECTION REPORT – INSTRUCTIONS PAGE 1 OF 3

(rev 8/10)

PART I – GENERAL INFORMATION

  • Operator Name – Enter the current name of the operator reflected in DNR records.
  • OC – Enter the four digit operator code or organization id assigned by DNR for the operator.
  • Well Name – Enter the current name of the well reflected in DNR records.
  • Well Number – Enter the current number of the well reflected in DNR records.
  • Serial Number – Enter the six digit number issued by DNR.
  • Field Name – Enter the name of the field in which the well is located according to DNR records.
  • Field Code– Enter the four digit field code assigned by DNR for the field.
  • Section – Enter the number of the Section in which the well is located according to DNR records.
  • Township – Enter the number of the Township in which the well is located according to DNR records.
  • Range – Enter the number of the Range in which the well is located according to DNR records.
  • Parish – Enter the name of the parish in which the well is located according to DNR records.
  • Parish Code– Enter the two digit parish code assigned by DNR for the parish.
  • Latitude– Enter the geographic coordinate of the well surface location in relation to the equator expressed in units of Degrees, Minutes and Seconds. This is to be measured by CES using GPS at the well location.
  • Longitude– Enter the geographic coordinate of the well surface location in relation to the Prime Meridian expressed in units of Degrees, Minutes and Seconds. This is to be measured by CES using GPS at the well location.
  • Contractor Name/Rig Name/Number – Enter the name of drilling, workover, or completion contractor and the name and number of the rig.
  • Rig Phone Number – Enter the telephone number of the rig.
  • Rig Type – Check the appropriate box to indicate the type of rig on location.

PART II – BOP EQUIPMENT & WELL CONTROL INFORMATION

  • Diverter System – Check the appropriate box to indicate whether a diverter system is installed for use on location. Section 111.A of Statewide Order No. 29-B (LAC 43:XIX.111.A) requires the use of diverter systems when drilling surface hole in areas where drilling hazards are known or anticipated to exist. The District Manager may require the use of a diverter system on any well.
  • Diverter Pressure Test Date – If a diverter system is installed on location, enter the date of the last diverter system pressure test. If there is no diverter system installed, leave this box blank. Section 111.B.3 of Statewide Order No. 29-B (LAC 43:XIX.111.B.3) requires that pressure tests be conducted at least once every seven (7) days.
  • Diverter Test Pressure – If a diverter system is installed on location, enter the test pressure that equipment was subjected to, in pounds per square inch (psi), during the last diverter system pressure test. If there is no diverter system installed, leave this box blank. Section 111.B.3 of Statewide Order No. 29-B (LAC 43:XIX.111.B.3) requires that pressure tests are to be conducted to a minimum test pressure of 200 psig.
  • Diverter Function Test Date – If a diverter system is installed on location, enter the date of the last diverter system function test. If there is no diverter system installed, leave this box blank. Section 111.B.2 of Statewide Order No. 29-B (LAC 43:XIX.111.B.2) requires that function tests be conducted at least once every twenty-four (24) hours.
  • BOP Components - Check the appropriate boxes to indicate each type of BOP component installed on the well. Section 111.C of Statewide Order No. 29-B (LAC 43:XIX.111.C) requires an appropriate number of RAMtype BOP components to control the well under all potential conditions which may occur during the operations being conducted. See TABLE 1 on Page 3 of these instructions for components required on water locations pursuant to Emergency Order 29-B.

-Annular – an annular-type blowout preventer is typically installed on the top of the stack and has a rubber sealing element that, when activated, can seal the annulus between the kelly, the drill pipe, the drill collar, or the open hole.

-Pipe Ram– a ram-type blowout preventer component that can seal the annular space between a particular size of pipe and the blowout preventer or wellhead.

-Blind Ram – a ram-type blowout preventer component which serves as the closing element on an open hole. Its ends do not fit around the drill pipe but seal against each other.

-Shear Ram-a ram-type blowout preventer component that cuts, or shears, through drill pipe or any other tubular in the hole to seal the well.

DRILLING/WORKOVER INSPECTION REPORT – INSTRUCTIONS PAGE 2 OF 3

(rev 8/10)

  • Size – For each installed component, enter the size of the BOP sealing element (if applicable). Typically, the size refers to the outer diameter (OD) of the tubulars which the equipment is designed to seal around.
  • Type – For each installed component, enter the type of component installed. Typically, this indicates the bore size of the component and whether equipment is a single ram or double ram unit.
  • Manufacturer/Model – For each installed component, enter the manufacturer and/or model of the BOP component (if applicable).
  • Pressure Rating – For each installed component, enter the working pressure rating of the BOP component in thousands of pounds per square inch (Kpsi).
  • No. of Control Stations – Enter the number of BOP control stations available for use. Section 111.E.4 of Statewide Order No. 29-B (LAC 43:XIX.111.E.4) requires at least one operable remote BOP control station located in a readily accessible location in addition to the one on the drilling floor.
  • Control Station Locations – Enter the location of each available BOP control station. Section 111.E.4 of Statewide Order No. 29-B (LAC 43:XIX.111.E.4) requires at least one operable remote BOP control station located in a readily accessible location in addition to the one on the drilling floor.
  • Drill-string safety valve(s)?– Enter yes if the appropriate drill string safety valves are installed and available for use on the drill floor. Sections 111.E.7-9 of Statewide Order No. 29-B (LAC 43:XIX.111.E.7-9) requires full opening safety valves installed below the swivel (upper kelly cock) and at the bottom of the kelly (lower kelly cock). A drill-string safety valve in the open position shall also be available at all times on the rig floor while drilling operations are being conducted. This valve shall be maintained on the rig floor to fit all connections that are in the drill string. When running casing, a safety valve shall be available on the rig floor assembled with the proper connection to fit the casing string being run in the hole.
  • Accumulator Capacity – Enter the hydraulic capacity in gallons of the accumulator system used to actuate the BOP components.
  • Last BOP Pressure Test Date – Enter the date of the last BOP pressure test. Section 111.F.2 of Statewide Order No. 29-B (LAC 43:XIX.111.F.2) requires that BOP pressure tests are to be conducted at the following times and intervals: 1) immediately following installation of the BOP; 2) within 14 days of the previous test; 3) before drilling out each casing string or liner; and 4) not more than 48 hours prior to drilling within 1000 feet of a hydrogen sulfide (H2S) zone. If tests are postponed due to well control problems, the BOP must be tested on the first trip out of the hole.
  • More than 14 days since last PT? – Check ‘yes’ box if more that 14 days has elapsed since the last BOP pressure test. Check ‘no’ box if the last pressure test was conducted within the last 14 days. If an exception has been granted by the District Manger, note this in the ‘Comments’ box. Section 111.F.2.c of Statewide Order No. 29-B (LAC 43:XIX.111.F.2.c) requires that BOP pressure tests be conducted at least once every fourteen (14) days. Exceptions may be granted by the District Manager if a trip is scheduled to occur within two (2) days of the 14 day testing deadline.
  • RAM Test Pressures – Enter the low and high test pressures of the RAM BOP components in pounds per square inch (psi). Section 111.F.3 of Statewide Order No. 29-B (LAC 43:XIX.111.F.3) requires low test pressures between 200 and 300 psig. Section 111.F.4.b of Statewide Order No. 29-B (LAC 43:XIX.111.F.4.b) requires high test pressures of the rated working pressure of the equipment or 500 psi greater than the Maximum Anticipated Surface Pressure (MASP) for the applicable hole section.
  • Annular Test Pressures– Enter the low and high test pressures of the Annular BOP component (if applicable) in pounds per square inch (psi). If there is no annular preventer installed, leave this box blank. Section 111.F.3 of Statewide Order No. 29-B (LAC 43:XIX.111.F.3) requireslow test pressures between 200 and 300 psig. Section 111.F.4.c of Statewide Order No. 29-B (LAC 43:XIX.111.F.4.c) requireshigh test pressures of 70% of the rated working pressure of the equipment.
  • Last BOP Function Test Date – Enter the date of the last BOP function test. Section 111.F.5 of Statewide Order No. 29-B (LAC 43:XIX.111.F.5) requires that BOP function tests be conducted every seven (7) days between pressure tests.
  • More than 7 days since last FT? – Check ‘yes’ box if more that 7 days has elapsed since the last BOP function test. Check ‘no’ box if the last function test was conducted within the last 7 days. Section 111.F.5 of Statewide Order No. 29-B (LAC 43:XIX.111.F.5) requires that BOP function tests be conducted every seven (7) days between pressure tests.
  • Control Station Used – Enter the location of the control station used during the last function test.
  • Last Well Control Drill – Enter the date of the last well control drill. Section 111.H of Statewide Order No. 29-B (LAC 43:XIX.111.H) requires that well control drills be conducted on a weeklybasis (every seven (7) days).
  • Comments – Enter comments related to the BOP/well control inspection.

DRILLING/WORKOVER INSPECTION REPORT – INSTRUCTIONS PAGE 3 OF 3

(rev 8/10)

PART III – CURRENT OPERATION(S)

  • Operation Type – Check the appropriate box to indicate the type of operation in progress.
  • Work Permit # – If the operation type is a Completion or a Workover, enter the work permit number. If it is a drilling operation leave this box blank.
  • Current MD – Enter the current measured depth of the well in feet (ft).
  • Current TVD – Enter the current true vertical depth of the well in feet (ft).
  • Current PBTD – Enter the current plug back total depth in feet (ft).
  • Description of current activity – Enter a description of the current activity being performed at the time of inspection.

PART IV – DRILLING/WORKOVER FLUIDS

  • Fluid Type – Enter the type of drilling/workover fluid in use.
  • Fluid Weight – Enter the weight of the drilling/workover fluid in pounds per gallon (ppg).
  • Funnel Viscosity – Enter the funnel viscosity of the drilling/workover fluid in seconds.
  • Storage Type – Check the appropriate box to indicate the type of storage for the drilling/workover fluids.
  • Fluid Level Indicators/Alarms – Check ‘yes’ box if fluid level indicators/alarms are installed. Check ‘no’ box if these devices are not installed.
  • System Volume – Enter the total volume of drilling/workover fluid in barrels (bbls) contained in the rig circulating system (pits/tanks/well etc.).

THIS FORM IS TO BE COMPLETED BY THE CONSERVATION ENFORCEMENT SPECIALIST (CES). ALL INFORMATION REPORTED ON THE FORM IS TO BE VERIFIED BY THE CES USING THE OFFICIAL DRILLING RECORD(S).

IF NO VIOLATIONS ARE NOTED ON THE REPORT CHECK ‘YES’ TO INDICATE THE SITE IS IN COMPLIANCE.

IF ANY VIOLATIONS ARE NOTED ON THE REPORT, CHECK ‘NO’.

IF THERE IS ANY UNCERTAINTY ABOUT WHETHER A CONDITION CONSTITUTES A VIOLATION, IMMEDIATELY CONTACT YOUR SUPERVISOR OR THE DISTRICT MANAGER FOR GUIDANCE.

Table 1 – Minimum BOP Component Requirements

Component / Land
(Drilling & Workover) / Water (Drilling) / Water (Workover)
MASP ≤5000 psi / Water (Workover)
MASP
>5000 psi
Annular / Recommended / Required / Required / Required
Pipe RAM / Required / Required / Required / Required
Pipe RAM / Required / Required
Blind RAM / Required* / Required* / Required*
Shear RAM / Required* / Required*+ / Required*+

* A single combination RAM may be used in place of separate blind and shear RAMs.

+ Shear RAM component is required for workover operations initiated on or after January 1, 2011