[xls]drilling performance review - rushmore...

Changes to DPR Workbook for 2014

This sheet describes the differences between the 2014 workbook and the 2013 workbook.

Changes from 2013 to 2014:

Unique ID Column Title

n/a n/a

D009/94 Column 18 "Other" code added for wells that do not fit the definitions for N, S, or G.

D021/91 Column 36

Columns 40, 41 & 42 Codes revised to allow reporting of wells drilled through Pre-salt, Sub-salt, or both.

D029/98 Column 70 Codes revised to allow reporting of Mud Cap Drilling (MCD).

D043/89 Column 92 Clarification added that BOP testing for GOM wells should be included in dry hole days.

Wells not required Clarification that CO2 injection wells do not need to be submitted to the DPR.

Hole Type

MTD of Final Wellbore Clarification that this should reflect MTD of final wellbore reached during the dry hole period.

D077/99, D078/00, D079/00 Salt

Pressure Balance

Dry Hole Days

Return to Instructions page

Drilling Performance Review 2014 of 54

© Rushmore Associates Limited 2014

Drilling Performance Review

Instructions for DPR data input : 2014 38DPR 2014 workbook. Rev 0.2 30-May-2014

This sheet contains the instructions for completing the Drilling Performance Review workbook.

Clicking on any of the column headings in the Data Input sheet will take to you a detailed definition of what to enter in that column.

Which wells should you submit?

Wells that are mandatory:

Wells that are optional:

Wells that you do not need to submit data for:

***

For wells that are highly confidential, please fill in the Tight data workbook, which you can download using the link below:

This workbook is revised every year and there have been changes made since last year's workbook. For a summary of these changes, please follow the link below.New in 2014

However, if anything is unclear or you have any problems completing the workbook, please contact a member of the team, who will be happy to assist you.

When you have completed the workbook, please return it, along with any other relevant documents, to the Rushmore analyst who deals with your data, or to:[email protected]

Include all offshore and land wells, drilled by your company that reached Total Depth (TD) (or finished TD logging or reaming / under-reaming after TD) during the year 2014.

You must submit data whether or not each well reached its planned target depth, provided it reached an actual TD and is not expected to be extended.

• Hydrocarbon Exploration and Production wells (including shale oil or gas wells)• Exploration and Appraisal wells (except for US and Canada land wells)• Injector wells• Wells that were drilled on your behalf under a turnkey or management contract, or similar arrangement• Technical or Mechanical sidetracks 9 These are included in the data of their parent well

• US land and Canada land exploration and appraisal wells• Coal bed methane / Coal seam gas & Geothermal wells

• Water production and water disposal wells (unless the water is being re-injected into a reservoir to improve production)• Any well with a length of less than 30 metres• Blow out relief wells• CO2 Injection wells

DPR Tight workbook

mailto:[email protected]

http://www.rushmorereviews.org/wbook/dpr/2014/DPR-2014-tight-workbook.xls


Time-Depth Data

You may optionally provide Time-depth data for wells with 10 dry hole days or less.

Time-Depth Charts

Well Path Diagrams

Overhead Cost Table

Quarterly Confirmations

Please include Time-depth data for all wells on the 'Time-depth data' worksheet provided. This should include at least one reading per day and should include hole sizes for all readings.

If the well was suspended, time spent on making the well safe before the rig moved off and time spent on re-entering the well back to this point should be included, however time during which the rig was off location should not be included.

Please submit a Time-depth chart for each of your wells showing both the 'actual' and 'planned' curves. It is not necessary to submit a Time-depth chart for a well with 5 dry hole days or less.• Include text boxes showing details of drilling operations and any major problems. These are more useful to participants..than just plain lines• Only include one well per chart, except that sidetracks and branches may be shown with their parent well• If possible, please provide these charts in Excel• Do not include any time when the well was suspended• Do not include any confidential information on the Time-depth chart

Please submit a well path diagram for:• Multilateral wells• Wells that you consider to have complex geometry

Once a year we will send the Overhead Costs Table for you to fill in.This table contains tick boxes where you indicate which types of overheads your Company includes in the cost values you submit.

When we have processed your quarterly data submission we will send a Quarterly Confirmation form to be completed by the Drilling Manager. This is to ensure that we have received all your well data for that Quarter.


Column Title

D001/93

2 D002/89

D003/00

4 D004/95

For wells in Australia / New Zealand, use this column to enter the basin number.

For wells in the Gulf of Mexico, use this column to enter the area code.

D005/00

6 D006/00

7 - 14 D007/99

D008/99

15 D111/08

16 D070/04

17 D080/01

Definitions and Instructions(Click on the column title to go to the data input column)

Uniquedata ID

1 Country Give the name of the country in which the well is located.

If the well is in a shared 'zone' between two or more countries such as Australia / Timor, Nigeria / Sao Tome, Kuwait / Saudi Arabia etc. please note this in column 1.

Official or Formal Well NameEnter the official name of the well, as used by regulatory bodies.Please do not give abbreviated names - they can be shown in column 3.If this well was re-named after it was drilled please give its previous well name in further details (column 120).

3 In House or Common Well Name (GoM Prospect Name)If the well is known by a different name or an abbreviated name in your company, please enter it in this column.

For Gulf of Mexico wells, enter the prospect name here if it is different from its official name.

Field or Basin Name (GoM Area Code)Enter the field or basin name, as relevant.

List of Australian basin numbers

List of GoM area codes

For US land wells please enter the state as well as the field name, e.g. TX / Spindletop.For Canadian land wells please include the province with the field name.

5 Block Number Enter the block number where relevant.

Platform Name (or Land Well Pad Number)If the well was drilled from (or over) a platform, please enter the platform name.If this was a land well drilled from a pad, please enter the pad number.

Geographical Latitude / LongitudeEnter the latitude and longitude of the well in degrees, minutes and seconds. Use the N/S column (column 10) to show whether north or south of the equator.Use the E/W column (column 14) to show whether east or west of the Greenwich meridian.

This should be the location of the well head rather than the location of TD.If the location of the well is very confidential, you may give an approximate indication of the location.

If you are entering many wells within the same field you may enter a single set of coordinates at the centre of the field for all wells.

Drilling Contractor Enter the name of the drilling contractor / rig contractor. If more than one contractor was used, please give all the names, separated by commas.

Rig Name Enter the name of the rig used to drill the well. If more than one rig was used, please enter the names of all the rigs separated by commas.

If the rig is a platform, please give the rig name as 'Platform rig' and enter the platform name in column 6.

Owner Drilled Enter one of the following codes to show who drilled this well:

1: Your company designed and drilled this well (employing a drilling contractor) on its own behalf2: The well was designed and drilled for you by a drilling or management contractor, under a turnkey contract, or similar3: The well was designed and drilled for you by a drilling or management contractor under a non-turnkey contract4: The well was designed and drilled for you by another operator5: The well was designed by you but drilled by another operator on your behalf6: Your company designed and drilled this well for another operator7: Your company drilled this well for another operator, to their design8: The well was designed by you but drilled by a drilling or management contractor under a non-turnkey contract

If you have entered any of the codes from 4 - 8, please give the name of the other operator in Further details (column 120)


18

A New well (N) is a well planned and drilled from a spud point at the seabed or the cellar floor.

If you are unsure how to classify your well, please click below for a guide.

19 D081/01

20 D082/01

21 D092/04

For further information on TAML classification see:

22 D010/00

Hole Type Please enter one of the following codes to indicate the hole type:N: New wellG: Geological sidetrack wellS: Slot Recovery well / Slot Enhancement wellO: Other: Please give an explanation in Further details (column 120)

D009/94Changed

Please click here for help with New wells

A Geological sidetrack (G) is a well planned and drilled from the bore of another well in order to achieve a geological target.A planned Geological sidetrack is one that is planned and engineered prior to spud, and will often have a separate AFE to its parent well.Click below for more information on which wells are treated as Geological sidetracks.Please click here for help with Geological sidetrack wells

A Slot Recovery well or Slot Enhancement well (S) is a new well that kicks off from some point in the bore of a previously used Producing or Injecting well.This may be:• A well drilled from a subsea template slot / casing used previously by a Production / Injection well that is now abandoned• A deepening of a Production / Injection well• An exploratory branch is drilled from a Production / Injection wellPlease click here for help with Slot Recovery wells

Other: 'O' may be used if your well fits none of these hole types, with an explanation given in Further details (column 120).This may be:• A re-entry of a previously abandoned well to sidetrack / extend the wellbore to the same geological target

A guide to sidetracks

Locator Well Enter 'Y' if this well was planned and drilled as a Locator well, otherwise enter 'N'. Do not leave this field blank.

A Locator well is a well designed to penetrate the reservoir in order to accurately locate its position or carry out other geological investigation, and then to be sidetracked for production purposes.Click here for help with Locator wells

Multilateral Enter 'Y' if this well is a Multilateral well, otherwise enter 'N'.Do not leave this field blank.

A Multilateral well is one with two or more Producing or Injecting bores connected together down hole and produced via a single wellhead.Click here for help with Multilateral wells

Multilateral Junction TypeFor Multilateral wells enter a code to show the Multilateral junction type (as defined by TAML: Technology Advancement for Multilaterals)

1. Open / unsupported junction2. Mother-bore cased and cemented, lateral open3. Mother-bore cased and cemented, lateral cased but not cemented4. Mother-bore and lateral cased and cemented5. Pressure integrity at junction with packer elements6. Pressure integrity at junction-casing seal or Down hole splitter-large main bore with 2 smaller wellbores of equal size

If your well has more than one junction type, please enter them all separated by commas.

http://www.taml-intl.org

Number of LateralsFor Multilateral wells please enter the number of laterals that are producing, or capable of producing.Examples:• For a Multilateral well with a producing 'parent hole' and one producing lateral, enter '2' • Where the 'parent hole' is not capable of producing but there are four producing laterals, enter '4'

http://www.taml-intl.org/


23 D096/05

24 Enter the number of Mechanical sidetracks in this well, or zero if there are no Mechanical sidetracks.

25 D011/00

26 D012/00

27

28 D120/10

D014/92

30 D015/00

31 D016/92

Land rigs:

Shallow barge rigs:

Offshore rigs:

Number of Contingency Geological SidetracksEnter the number of Contingency Geological sidetracks drilled in this well, or zero if there are no Contingency Geological sidetracks.

A Contingency Geological sidetrack is a sidetrack that is planned prior to spud, but only as a contingency. It is drilled in order to regain the reservoir, in a thin or highly faulted reservoir. It is normally part of the parent AFE.

Please click here for help with Contingency Geological sidetracks

Number of Mechanical Sidetracks D116/09

A Mechanical sidetrack (also known as a Technical sidetrack or Bypass) is an unplanned sidetrack drilled to pass an obstruction or to improve the well path.Please click here for help with Mechanical sidetracks

Re-Spud Due to Original Well Failure to Reach ObjectiveEnter 'R' if this is the second attempt to drill this well. The first attempt did not reach its objective because of a fault or failure of the drilling group and was entirely abandoned.All time spent drilling the original well should be reported as Non-Productive Time (NPT) (columns 113-119) in the re-spudded well.Please click here for help on re-spudded wells

Original (Failed) Well Name (Re-Spud Well Only)If this is a re-spudded well (marked 'R' in previous column), please enter the name of the well that failed to reach its geological objective and was abandoned.

Well Type Please enter one of the codes below to indicate what type of well this is: D013/89Clarified

E: ExplorationA: Appraisal or Delineation (includes Steam-Assisted Gravity Drainage (SAGD) core hole wells)D: Development or Production

If a development well is drilled beyond its development TD in order to explore further target zones (but this work is carried out within 1 AFE) the data may be entered as 1 row with well type 'development'. In this situation, please give an explanation in Further details (column 120).

Please note that CO2 Injection wells do not fall under the scope of the DPR.

Play Type Please enter one of the codes below to describe the well:

H: Conventional Hydrocarbon (Production and Injection wells)C: Coal Bed Methane / Coal Seam GasD: Steam-Assisted Gravity Drainage (SAGD)GA: Geothermal - Hot Sedimentary AquifersGE: Geothermal - Enhanced Geothermal SystemsGV: Geothermal - VolcanicS: Shale Oil or Shale Gas

O : Other - Please give details in Further details (column 120)

29 High Pressure WellEnter 'HP' for wells drilled into formations with actual or expected pore pressures of 10,000 psi or greater.

High Temperature WellEnter 'HT' for wells drilled into formations with actual or expected static temperature at TD of 300 degrees fahrenheit (150 degrees celsius).

Rig Type Please enter the appropriate code. If more than one type of rig was used in drilling this well, enter all the appropriate codes separated by commas, in the order that the rigs were used.

LA: Land rig (rental)LO: Land rig (owned by Operator)HR: Heli-rigOL: Other type of land rig - Please give details in Further details (column 120)

SU: Submersible (a barge type vessel that floats into place, but sits on bottom during drilling)BA: Barge (a barge type vessel that is floating during drilling)

JK: Jack-up JP: Jack-up positioned over, and drilling through, a platformHP: Hydraulic workover unit on, and drilling through, a platform rig PL: Platform - rigid legPT: Platform - tethered leg (TLP)PS: Spar platform rigSP: Permanently moored vessel for production with integrated drilling facilities (e.g. FDPSO)TB: Platform tender-assisted barge type vessel TS: Platform tender-assisted semi-sub type vesselTJ: Platform tender-assisted jack-up type vessel SS: Semi-Submersible DS: DrillshipOO: Other type of offshore rig - Please give details in Further details (column 120)

If the rig is a dual activity rig, optionally show (2), including the brackets, after the rig type code.9 e.g. SS (2) for a dual activity semi-submersible rig.


32 D017/99

For Down-hole Motor Casing Drilling, please use these codes:

33 D018/99

34 D019/00

D107/07

35 D020/91

36

• The length of any shallow gas / water hazard well, if it is not part of the final wellbore

Drilling Method Please enter one or more of the codes below to indicate the methods used to drill this well.For example, for a well that was drilled using a top drive to reservoir, and the reservoir drilled using coil tubing, you would enter 'TC'.

(As most drilling of new wells will use either rotary kelly drive or rotary top drive we would expect to see 'R' or 'T' given in the list of codes.)

R: Rotary kelly drivenT: Rotary top drive drivenA: Rotary steerableM: Non-rotary steerable (mud motor)C: Coil tubingH: Hammer drillingP: Percussion drilling

Y: Through-tubing rotary drillingB: Through-tubing coil tubing drillingO: Other method - please give details in Further details (column 120)

For Rotary Casing Drilling, please use these codes:DX: If used to install 1 or more casings, but not the casing in the final hole sectionDZ: If used to install the casing string in the final hole section (i.e. there was no further drilling after this casing was installed)

EX: If used to install 1 or more casings, but not the casing in the final hole sectionEZ: If used to install the casing string in the final hole section (i.e. there was no further drilling after this casing was installed) Units of Measurement If your data has been reported in metres please enter ‘M’, or if you have used feet please enter ‘F’.Please ensure the Time-depth data and Time-depth charts are entered in the same units of measurement.

Water Depth / Land Well Drill Floor ElevationFor offshore wells:• Please enter the water depth

For land wells:• Optionally, enter the drill floor elevation above sea level9 This will be shown in a separate field on the website

Spud Depth Please enter the depth of the spud point, measured from the Rotary Kelly Bushing (RKB) on the rotary table. Spud depths are defined below:

For new offshore wells:• The spud point is at the seabed - not at the bottom of any pre-set or batch-set casings

For new land wells:• The spud point it is at the bottom of the cellar - not at the bottom of any casing pre-set during site preparation.

For Geological sidetrack / Slot Recovery wells:• Spud is taken as the first new hole section drilled • In a cased hole this will be the start of drilling outside the milled-out window by the drilling assembly

For Shared / Split conductors or Side by Side wells:• If this is the second of 2 new wells drilled through a shared conductor please click below for helpPlease click here for help on shared conductors

MTD of Final WellboreFor all wells except Locator or Multilateral wells:• Please enter the measured depth from the rotary table to the end of the well (TD) along the final wellbore (including any sump or rat hole) reached during the dry hole period

D021/91clarified

Please click here for help with sidetracks

For Locator wells:• The measured total depth (MTD) is measured along the final wellbore, from the rotary table to the TD of the sidetrack through the reservoirPlease click here for help with Locator wells

For Multilateral wells:• The MTD is measured along the wellbore from the rotary table to the end of the parent hole, plus the combined distances from the junction point to the TD of each lateralPlease click here for help with Multilateral wells

Do not include:• The length of any sidetrack drilled due to completions problemsPlease click here for help with sidetracks

Please click here for help on shallow gas / water hazards


D097/05

38 D098/05

39 D022/92

41

42

43 D084/01

44 D024/92

45 D025/95

46

37 Unused Lengths Due to Contingency Geological SidetracksThis only applies to wells with Contingency Geological sidetracks.Please enter the total unused footage that occurred due to contingency geological sidetracks (not technical sidetracks).Please click here for help with Contingency Geological Sidetracks

Locator Unused LengthThis only applies to Locator wells (parent hole).Please enter the footage from the kick-off point of the sidetrack to the TD of the pilot hole.This is the 'unused' or abandoned footage, which is not part of the final wellbore.Please click here to see how the Locator unused length is measured

TVD Please enter the vertical depth from the rotary table to the end of the well (TD).

For Locator wells:• The vertical depth is measured to the TD of the sidetrack, not to the TD of the parent hole

For wells with Contingency Geological sidetracks:• This is measured to the end of the final wellbore

For Multilateral wells:• The vertical depth is measured to the TD of the deepest lateral drilled

40 Salt Please enter a code to indicate if the well was:

S: Drilled through a Sub-salt formationP: Drilled through a Pre-salt formationB: Drilled through both Pre-salt and Sub-salt formationsN: Not drilled through salt

D077/99Changed

Geological sidetracks or Slot Recovery wells kicked off below salt formation and not drilled through salt are not defined as 'Sub-salt' or 'Pre-salt' for the purposes of the DPR.

Click here for help on Sub-salt and Pre-salt wells

TVD at Start of SaltPlease enter the vertical depth from the rotary table to the start of first drilling into salt. D078/00Changed

For wells drilled through both Sub-salt and Pre-salt:• Enter the vertical depth from the rotary table to the start of first drilling into Pre-salt

TVD at End of Salt Please enter the vertical depth from the rotary table to the point where you finally drilled out of salt. D079/00Changed

For wells drilled through both Sub-salt and Pre-salt:• Enter the vertical depth from the rotary table to the point where you finally drilled out of Pre-salt

For wells drilled through two or more Sub-salt or two or more Pre-salt formations:• Give the number of salt zones and the total vertical length of non-salt sections in Further details (column 120)

Complex GeometryIf, in your opinion, this well has complex geometry please enter 'Y', or enter 'N' if not. If you enter 'Y', please provide a well path diagram when you submit this well.

Maximum Angle in DegreesPlease enter the maximum angle of any hole section drilled in the final wellbore (e.g. not in an abandoned section).The maximum angle may be outside the reservoir section - for instance in an S shaped well.

Total Length of Horizontal Sections Please enter the total combined length of any sections of the final wellbore that were drilled at an angle of 85 degrees or greater.This may include sections both within and outside the reservoir.

For Multilateral wells:• Give the total horizontal length for all laterals drilled

For Geological sidetracks or Slot Recovery wells:• Only count horizontal sections below the kick-off point

Final Drill Bit Size/Hole Size (inches)Please enter the size (in inches) of the final drill bit used across the reservoir or final formation drilled. If this well was drilled with a bi-centred bit please give the final (larger) hole size.

D026/99

Please do not include ' or " (feet or inches symbols) when reporting the final drill bit size.


47 - 57 Geological sidetrack and Slot Recovery wells:

58 New and batch-set wells only:


59 D101/07

60 - 69 D028/93

Pre-Existing Casing Strings - For 'G' And 'S' Type Wells Only D027/93Please enter, in decimal inches, the sizes of conductor and casing strings that were in place prior to drilling the new hole for the Slot Recovery well or Geological sidetrack.Give each string size in a new column.


For Combination strings:• Please enter the sizes in one column using a forward slash (/) to indicate the larger and smaller sizes, (e.g. 10.25/9.625)

For Expandable casings:• Please enter the expanded size followed by the letter 'e' (e.g. 9.625e)

For Shared / Split conductors or Side by Side wells:

• If this is a Geological sidetrack or Slot Recovery well drilled from a well with a Split conductor please note this in the comments column• If this is the second of 2 new wells drilled through a Shared conductor please click below for helpPlease click here for help on entering the data.

New Conductor Casing D094/04Please enter the size of the conductor casing (also known as Drive pipe / Stove pipe / Structural casing / Conductor pipe).

You should give this size even though the conductor may have been installed by the civil engineering or platform construction contractor during site preparation or platform installation.

For Shared / Split conductors or Side by Side wells:• If this conductor is a Splitter conductor, where two or more wells drilled from surface share the same conductor casing, please add the letter 's' after the conductor size

Please click here for help on entering the data.

Conductor Installed By Drilling Rig?New and batch-set wells only:Please enter 'Y' if the conductor casing was installed by a drilling rig, or 'N' if not.

New Casing Strings And Liners (Suffix 'E' Where Expandable Casing is Used)Please enter, in decimal inches, the sizes of all casings that were installed during the drilling of this well.

Do not include:• Any casing or liner that was run after the well reached TD• The conductor casing, as this is entered in column 58

For combination strings:• Please enter the sizes in one column using a forward slash (/) to indicate the larger and smaller sizes(e.g. 10.25/9.625)

For expandable casings:• Please enter the expanded size followed by the letter 'e', (e.g. '9.625e')

For Shared / Split conductors or 'Side by Side' wells:

Please click here for help on entering the data.


70

For Example:

Mud Cap Drilling:

71 D030/98

Pressure Balance Please enter one of the codes below to indicate how this well was drilled with respect to pressure differential. D029/98Changed

N: if well drilled wholly over-balancedM: if well drilled wholly using Managed-Pressure Drilling (MPD), or in combination with Over-balanced drilling/Under-balanced drillingC: if well drilled either wholly using Mud Cap Drilling (MCD), or in combination with MPD/Over-balanced/Under-balanced drillingU: if well drilled wholly or partly under-balanced, not using MPD or MCD

If a well was drilled wholly Over-balanced, you would enter 'N'. However, if it was drilled partly Over-balanced and Under-balanced, you would enter 'U'.

Similarly, if the well was drilled wholly Under-balanced, you would enter 'U'. However, if it was drilled partly Under-balanced and using Managed-Pressure drilling, you would enter 'M'.

Managed-Pressure Drilling:Managed Pressure Drilling is an adaptive drilling process used to precisely control the annular pressure profile

throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly.

Under-balanced Drilling:Under-balanced Drilling is when the pressure of the fluid column is designed to be less than that of the expected formation pressure, allowing the well to flow during drilling.

This is sometimes called 'drilling for kicks' and requires special equipment at the well site for control and safety purposes.

Over-balanced Drilling:Over-balanced Drilling is a drilling condition where the drilling fluid selected provides a pressure gradient greater than the anticipated formation pressure.

In Mud Cap Drilling, a heavy, viscous mud is pumped down the backside in the annular space to some height. This “mud cap” serves as an annular barrier, while the driller uses a lighter, less damaging and less expensive fluid to drill into the weak zone.

Drilling Fluid Type Please enter one or more codes to describe the drilling fluid(s) used in this well. W: Water Based Mud O: Oil Based MudS: Synthetic Mud E: Ester MudM: MistF: Foam A: AirB: Brine


72 D112/08

73 D031/95

74 D032/95

75 D033/98

Coring, logging and under-reaming: The times given in columns 76 to 80, must also be counted in the dry hole days.

76 D034/92

77 D035/93

78 D036/99

79

Mud Weight Units Please enter one of the codes below to indicate the units that you use for reporting mud weights:

sg: specific gravity (sg)gcm3: grams per cubic centimetre (gm / cm3)kgL: kilograms per litre (kg / L)gL: grams per litre (gm / L)kgm3: kilograms per cubic metre (Kg / m3) kpam: kilopascal per metre (kPa / m)ppg: pounds per gallon (ppg)pbbl: pounds per barrel (lb / bbl)pf3: pounds per cubic foot (lb / ft3)psif: pounds per square inch per foot (psi / ft)psi100f: pounds per square inch per 100 ft (psi / 100ft)

o: other (specify in Further details - column 120)

Mud Weight at TD If mud has been used as the circulation fluid, please enter the mud weight at TD.

Maximum Mud WeightIf mud has been used as the circulation fluid, please enter the maximum mud weight in any section of the wellbore.

Please do not give 'pad' (pump and dump) mud weight.

Cuttings Disposal Please enter the methods used for cuttings disposal:

R: Re-injection S: Ship to shore / transport to landfillD: Discharge at site

Coring Days Please enter the number of days spent using a core barrel to drill out, or trying to drill out, core samples before TD was reached. If no coring was carried out, please enter '0'.

Coring time starts with circulation prior to POOH to core, and ends just after drilling out the core rat hole.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time during coring activities

Do not include:• Time spent on sidewall coring• Coring sidetracks that were drilled after TD

Coring Interval Please enter the total length of wellbore cored.

Logging Days Not At TDPlease enter the number of days spent on logging, or trying to log, before TD was reached. If no logging was carried out please enter '0'.

Logging time starts with circulation prior to POOH to log, and ends when the logging equipment is rigged down.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time during logging activities• Time spent sidewall coring before TD

Do not include:• Logging Whilst Drilling (LWD) / Formation Evaluation Whilst Drilling (FEWD) time

Logging Days at TDPlease enter the number of days spent on logging, or trying to log, after TD was reached. If no logging was carried out at TD, please enter '0'.

D037/99

Logging time starts when the bit is returned to the drill floor after TD and ends when the logging equipment is rigged down.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time during logging activities• Time spent sidewall coring at TD

Do not include:• Time spent depth logging for running guns• Cased hole logging / evaluation at TD


80 D087/02

81 D088/02

82 D038/00

83 D039/00

84 D089/02

Under Reaming DaysReaming / under-reaming (hole opening or widening) days

Enter the number of days spent reaming / under-reaming in any section in order to enlarge or open up the hole, where this is a separate operation, carried out before the start of completion operations.

This time includes making up the reaming / under-reaming bit, RIH, and carrying out the reaming / under-reaming operation.

The time ends when the reaming / under-reaming bit is returned to surface.

If no under reaming was carried out, please enter '0'.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time

Do not include:• Time spent solely on hole conditioning• Days spent reaming / under-reaming if this is done concurrently with drilling

Reamed / Under-Reamed Interval(s)Please enter the total length of wellbore that was opened up or enlarged by reaming / under-reaming, where this was done as a separate operation to hole-making. Do not include:• Length reamed / under-reamed if this is done concurrently with drilling• Operations that were carried out purely for hole conditioning• Do not count any hole section more than once

FEWD Enter 'Y' if Formation Evaluation While Drilling (FEWD) was employed, or 'N' if not.

FEWD includes:• Logging while drilling (LWD)• Resistivity and Gamma-ray

FEWD excludes:• Measurement while drilling for positional / geometrical information

Age of Deepest Formation AccessedPlease enter the one of the codes below to indicate the deepest formation accessed. This may not be the same as the target formation.This data must be given for all development wells. For exploration and appraisal wells you may enter 'N/A' if this data is very confidential.

Cam: Cambrian Carb: CarboniferousClow: Cretaceous Lower CUpp: Cretaceous Upper Dev: Devonian Jlow: Jurassic Lower JMid: Jurassic Middle JUpp: Jurassic Upper Ordo: Ordovician Pcam: Pre-Cambrian Plow: Permian Lower

PUpp: Permian Upper QHol: Quaternary Holocene QPlei: Quaternary Pleistocene Sil: Silurian TEoc: Tertiary Eocene

TMio: Tertiary Miocene TOli: Tertiary Oligocene TPal: Tertiary Palaeocene TPlio: Tertiary Pliocene Tri: Triassic Other: Please specify in Further details (column 120)

New Techniques Please enter codes to indicate which of the following new techniques were used in drilling this well.

L: Low rheology mudR: Onshore operation centres for control of drilling processesS: Slimhole well (as defined by operator)W: Wired drill pipe / intelligent drill pipeX: Expandable casing usedO: Other - please specify in Further details (column 120)

This is an optional field.


Pre-spud times: The times given in columns 85 - 88 are not included in the dry hole days.

85 D113/08

This is often the time between rig release on the previous well and rig arrival on the current well.For land wells, "rig arrival" is defined as "Rig move is 100% achieved" - i.e. more than just the derrick rigged up.

86 D114/08

87 D099/05

88 D040/95

89 D090/02

Rig Move Time(Optional)Land wells only:Enter the rig move time, in days.

It can also be operator-defined, provided the definition is given in Further details (column 120).

This time is not counted in the dry hole days.


Rig Move Within Field?(Optional)Land wells only:If the rig move time is given in previous column, please enter 'Y' if the rig move took place within the field, or 'N' if the rig was moved from outside the field.

This value is only required if you have entered the rig move time in the previous column.


Geological Sidetrack Pre-Spud & Whipstock DaysGeological sidetrack wells only:Please enter the number of pre-spud days spent setting a whipstock and / or drilling a ledge, and preparing to drill the Geological sidetrack.

This starts with picking up the whipstock to run in hole, or picking up the directional drilling assembly, and ends when drilling begins on the first new hole outside the milled window.

Include:• All operations after the original hole has been plugged back • Non-Productive Time (NPT) and Waiting On Weather (WOW) time

Do not include:• Time spent on setting a whipstock on a Slot Recovery well• Time spent on whipstock setting or ledge drilling time during the drilling of Locator wells, Multilateral wells..or wells with Contingency / Mechanical sidetracks

Slot Recovery / Slot Enhancement Pre-Spud DaysSlot Recovery / Slot Enhancement wells only:Please enter the time in days from the start of rig operations to recover the well, up until the spud of the new hole. This is also known as 'decompletion' time.

This may include operations such as killing the well, cutting and pulling the tubing, and setting the whipstock. Time spent to plug and abandon the original hole using the rig should also be included here.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time

Do not include:• Days spent on pre-spud operations without the rig (see next column)

Offline Slot Recovery OperationsSlot Recovery / Slot Enhancement wells only:If all or part of slot recovery pre-spud operations were carried out off-line (i.e. without the rig being present) please enter 'Y', otherwise enter 'N'.


The Dry Hole Period

90 D091/03

Drilling and casing is then continued to TD at a later time, either with a different rig or with the same rig.

Campaign drilled:

91 D042/93

Batch-Set / Campaign DrilledPlease use the following codes to describe your well:

B: The well was 'batch-set / pre-set' by your companyT: The well was 'batch-set / pre-set' under a turnkey or similar contractC: This well was 'campaign drilled' by your company D: This well was 'campaign drilled' under a turnkey or similar contractN: None of the above

Batch-setting:Batch-setting, or pre-setting, applies to wells that are pre-planned to have one or more hole sections drilled and cased, then before TD is reached, the drilling rig that did this work moves off location.

However, when conductor casings and subsequent casings are installed by a civil engineering or platform construction contractor during site preparation or platform installation, this is not defined as batch-setting.

This applies to a group of new wells, where the drilling rig will drill and case the top section of each well one-by-one, then drill and case the second section of each well, and so on until all the wells have reached TD in a continuous operation.At least 2 hole sections are drilled in this way.

Please note that a drilling campaign does not mean that a well is 'Campaign drilled'. Do not use this field just to indicate that a well was part of a drilling campaign.

Spud Date Please enter the date that drilling started on the well (dd-Mmm-yy)

New wells (including Locator wells and batch-set / campaign drilled wells):• Spud date is the date of spud at the seabed or cellar

New wells where conductor casing was installed by a drilling rig before the start of drilling:(e.g. by pile driving or other similar method)• Spud date is the date when the conductor penetrated the seabed or bottom of cellar

New wells where conductor casing was not installed by a drilling rig:• Spud date is the date drilling began out of the pre-installed casing

Geological sidetrack and Slot Recovery wells:• Spud date is the date that the first new hole was drilled out of the pre-existing casing ..(with a drilling assembly, not a milling assembly)

For Shared / Split conductors or Side by Side wells:• If this is the second of 2 new wells drilled through a shared conductor please click below for helpPlease click here for help on shared conductors

Please click here for further information on spud date


92

Do not include:

Dry Hole Days Please enter the number of days spent on drilling operations. This begins at spud, and ends either when the bit is returned to the drill floor after TD, or at the end of logging / under-reaming at TD, if these operations were carried out (see below).

D043/89Clarified

If logging was carried out at TD:• The dry hole days end when the logging tools are returned to the drill floor after TD

If hole opening was carried out after TD:• The dry hole days end when the under-reaming equipment has been rigged down

Include:• Days spent batch-setting, pre-installing or pre-setting casings, when carried out by a drilling rig

• Non-Productive Time (NPT) and Waiting On Weather (WOW) time during the dry hole period

• Time spent in hole opening (but not hole conditioning) after TD is reached

• Time spent drilling a narrow gauge hole to check for shallow gas or shallow water hazards, (but only ..if the shallow gas / water hole and the main well were drilled by the same rig)

• Time spent Technical / Mechanical sidetracking (Bypassing) for any reason, including as a result of ..problems experienced in the completions phase that were caused in the dry hole period ..9 e.g. hole geometry from high dogleg / hole instability

• Time spent running riser, BOP nipple up / nipple down, BHA running / tripping where these occur as ..part of planned batch-setting or campaign drilling or at any other time during the dry hole period

• Time spent in Multilateral wells to set a whipstock or to create a ledge in order to drill ahead in a ..new direction

• Time spent retrieving a whipstock, where this occurs before the dry hole end date 9 However, in a Multilateral well, if the whipstock is also used to install a liner or screens in a lateral, ..the time is not counted in the DPR

• For re-spudded wells, include the time spent drilling and abandoning the original (failed) well ..9 All the time spent drilling and abandoning the original (failed) well should be reported as NPT (cols 113-119)

• For Locator wells and wells with Contingency Geological sidetracks include all the time from spud to the ..end of TD logging on the final wellbore, except for the exclusions listed below

• For Gulf of Mexico wells, BOP testing operations should be included in the dry hole period ..(do not report as a suspension of dry hole operations)

• Time spent running the riser and installing the BOP before the start of drilling a new well

• Time spent setting the conductor if this operation was carried out by the civil engineering or ..platform construction contractor during site preparation or platform installation

• Time spent on hole conditioning after TD is reached

• Time spent running and cementing a production liner after TD

• Time during which the well was on suspension

• Time spent on suspension and re-entry operations for an unplanned suspension

• Time spent on plug and abandonment operations after TD is reached

• Time spent on completion operations

• Time for suspensions due to extreme weather conditions (e.g. hurricanes / cyclones) during which the..rig is shutdown

• Time to drill a narrow gauge hole to check for shallow gas, where this is not drilled by the rig that..drilled the main wellPlease click here for help on shallow gas / water hazards

• Time spent on a drill stem test (DST) except where this occurs out of the reservoir 9 e.g. checking for shallow gas

• For Multilateral wells, any operational time spent on 'completion activities' ..(such as running a production liner) after a branch or lateral has reached TD

• Time spent on wiper trips prior to running a completion assembly

• Time spent on the installation of a horizontal / spool tree during the drilling phase

• For re-spudded wells, time spent moving the rig from the original (failed) well in order to spud the new well

• Time spent moving the rig between shallow water / gas hazard well and main well


92

93 D044/99

94

95 D046/00

Dry Hole Days D043/89Clarified

For Shared / Split conductors or Side by Side wells:• If this is the second of 2 new wells drilled through a shared conductor please click below for help on ..how to allocate the timePlease click here for help on shared conductors

Reporting for 12hr / shift workWhen work is carried out in 12 hour shifts, as may be the case in Coal bed methane / Coal seam gas wells, only the active working time should be reported in the Dry hole days. Please note any difference between the reported Dry hole days and the Spud date (column 91) and Date of end of dry hole period (column 93) in Further details (column 120).

Date of End of Dry Hole PeriodPlease enter the date that drilling operations ended, in the following format: dd-Mmm-yyThis will either be when the bit is returned to the drill floor after TD, or at the end of logging / under-reaming at TD, if these operations were carried out (see below)

If logging was carried out at TD:• The dry hole period ends when the logging tools are returned to the drill floor after TD

If hole opening (under-reaming) was carried out after TD:• The dry hole period ends when the under-reaming equipment has been rigged down

The time given in column 95 is not included in the dry hole days.

Number of Well SuspensionsPlease enter the number of times that the well was suspended within the dry hole period (i.e. between spud and TD). If no suspensions took place, please enter '0'.

D045/00Clarified

Count as a suspension if:• A plug is set (or the well is made safe) and the rig moves off location / skids to another well• Drilling operations are stopped to allow for planned rig upgrade / maintenance• The rig moves to a safe location to avoid extreme weather conditions, e.g. hurricanes

Do not count as a suspension if:• The suspension relates to a land well after batch-setting or pre-setting surface casing by the ..civils / site preparation contractor

Days Spent on Suspension / Re-Entry OperationsPlease enter the number of days that were spent on operations of suspending and re-entering this well, for suspensions that occurred during the dry hole period.

Include:• Any Non-Productive Time (NPT) and Waiting On Weather (WOW) time that occurred during suspension..and re-entry• If the well was suspended more than once give the total number of days for suspension and re-entry operations

Do not include:• The number of days during which the well was suspended (the elapsed time)• Times for suspensions that occurred before the spud date or after the dry hole end date

For planned suspensions:• The suspension operation starts when the first additional operation takes place in order to suspend ..the well and stops when the rig starts moving off location• The re-entry operation starts at rig arrival on location and stops when operations are back where they ..were prior to the start of suspension• Exclude the time spent running riser, BOP nipple up / nipple down, BHA running / tripping ..(because it is counted in the dry hole days)

For unplanned suspensions:• The suspension operation starts at the first unplanned additional operation that took place in order to ..suspend the well, and stops when the rig starts moving off location• The re-entry operation starts at rig arrival on location and stops when operations are back where they ..were prior to the start of suspension• Include time spent on riser, BOP and BHA operations• Give the reason for the unplanned suspension in Further details (column 120)


96 D047/99

What to do if you cannot provide the data as defined, for one of the reasons given below:

Total Well Site DaysPlease enter the total number of days from rig arrival on location on this well until rig released from location. If more than one rig was used in the construction of this well, give the total days for all rigs used on the well.

Include:• Rig time spent on completions operations, suspension / re-entry operations or plug and abandonment ..operations, as reported in column 103• Geological sidetrack or Slot Recovery well pre-spud days, as reported in columns 87-88• Time spent on suspension and re-entry operations, as reported in column 95• Mooring / de-mooring time, as reported in columns 108 - 109• Rig time spent on well testing or other operations covered by column 104• Time spent drilling a well to check for shallow gas or water hazards, even though drilled from a location..some distance from the main well

Do not include:• Rig move time• Any rig time for construction, production or accommodation duties• Time when the well was suspended• Any time spent on well operations when the rig was not on location e.g. completion operations carried out after ..the rig was released.

• The well construction is not finished when you submit the drilling data 9 Leave this field blank and we will ask for the data at a later date• You do not have times for batch-setting or other operations carried out a long time ago, or by a different• operator 9 Give what you have and explain what is missing in Further details (column 120)• You have a completed well with one or more associated Geological sidetracks on separate rows of ..data, and you are unable to allocate 'total well site' time to individual sidetracks 9 Enter the 'total well site days' of the well and sidetracks on the row of the completed wellbore

For the other wellbores / sidetrack(s) ‘total well site days' and ‘dry hole days’ can hold the same value.


97 D048/91

For a general guide of how you might allocate your costs please download this file:

98 D049/00

99 D050/00

Dry Hole Cost (millions)Please enter, in millions, the cost of operations that occurred during the 'dry hole days' period.Report this value in the currency that your company uses.If you do not have the final costs please give provisional / preliminary costs.

Include:• General overheads, base operations, staff overheads, incentive payments, logging, transport, ..materials, materials supply, marine vessel support, marine supply base, port facility and warehousing..as indicated in your overhead costs sheet

• Costs incurred during the batch-set, pre-install or pre-set period, provided this is done by the drilling rig

• The cost of rig rental for the dry hole period, including supply boats and diesel fuel costs

• The cost of wellheads - except in re-entries, where the original wellhead is re-used

• The cost of drilling a narrow gauge hole as part of this well, to check for shallow gas or shallow water hazards

• The cost of drilling a narrow gauge hole some distance from this well, to check for shallow gas or shallow water• hazards, provided it is drilled by the same rig that drilled this well

• The cost of Technical and Mechanical sidetracks

• The costs incurred on any Contingency Geological sidetracks, or the sidetrack within a Locator well

• The cost for any riser / BOP / BHA operations that are included in the dry hole days

• The cost, up to the end of drilling, of installing casing / liner in the final hole section if it is installed by casing drilling

• The rental cost of equipment held on the rig during drilling of exploration wells, as a contingency..in the event of a commercial discovery, may be included

Do not include:• Costs for well design and programming

• Costs for site survey and preparation / re-instatement

• Costs for rig mobilisation and demobilisation

• The cost of setting a conductor if this operation was carried out under a 'civils' (site preparation) contract

• The cost of drilling a narrow gauge hole some distance from this well, to check for shallow gas or shallow water• hazards, if this was drilled by a different rig to the one that drilled this well

• Completion and well test costs, including production strings / liners installed after TD, Xmas trees ..and completion equipment

• The costs of long term daily rental of completions equipment held at the well site during the dry hole period

• The costs of installing of a horizontal / spool tree

• Costs for well suspension and re-entry, or plug and abandonment

For Shared / Split conductors or Side by Side wells:• If this is the second of 2 new wells drilled through a shared conductor please click below for help on..how to allocate the costsPlease click here for help on shared conductors.

Cost allocation guidelines.zip

Preliminary or Final Dry Hole CostEnter 'P' if the dry hole cost is preliminary and you expect to revise it at a later date, otherwise enter 'F' if the cost is final.

If you give preliminary costs we will contact you at a later date to ask for the final costs.

If final field costs are within +/-10% of the final ledger costs (also called booked accounting costs) they may be used as final costs for the purposes of this review.

Completeness of Dry Hole CostIf you have entered a complete dry hole cost figure as defined in column 98 enter 'Y'.

If you have entered a complete dry hole cost figure as defined in column 98, except that you cannot give the batch-set or pre-set costs, enter 'B'.

If some other costs are missing from the dry hole cost (other than the batch-setting costs) please enter 'N' and provide a list of the missing costs in Further details (column 120)

This column should not be used to indicate that costs are still preliminary, but to show that you are unable to get some costs.

http://www.rushmorereviews.org/wbook/cprdpr/Cost-allocation-guidelines.zip


100 D051/99

Do not include:

For a general guide of how you might allocate your costs please download this file:

101 D052/95

102 D053/02

Total Well Cost (millions)Please enter, in millions, the total costs associated with this well, including the items excluded from the dry hole cost.

Report this value in the currency that your company uses.

Include:• All the costs included in the dry hole cost• Costs for well design and programming• Costs for site survey and preparation / reinstatement• Rig move costs and civil works costs • Costs for rig mobilisation and demobilisation

• Costs of a narrow gauge hole drilled by a separate rig some distance away from the main well before..the main• Completion and well testing costs, including production strings and liners installed after TD logging, trees ..and completion equipment• Costs for well suspension, re-entry and plug and abandonment

• Costs relating to any contingent wells that were not drilled, or contingencies on an individual well ..e.g. additional casing that was available but not used

If the well is completed but the completion cost is not available at the time that you submit the drilling data we will not publish the total cost. We will ask for the completion cost at a later date.

If a well has Geological sidetracks, but total well costs cannot be spread across the individual sidetracks, the total cost may be allocated to the bore that was completed. Other bores can show the total cost as equal to the dry hole cost.

If you are unable to provide the data exactly as defined, please enter what you have available and note any differences / omissions in the Further details (column 120).

Cost allocation guidelines.zip

Currency Enter the currency you have used for reporting your well costs, e.g.USD: US DollarsGBP: British Pounds EUR: EurosNOK: Norwegian Kroner

DKK: Danish KronerAUD: Australian DollarsNZD: New Zealand DollarsNGN: Nigerian NairaBND: Brunei Dollarsetc.

For publication on the website we will convert all costs into US Dollars using the exchange rate average for the month in which the dry hole period ended.

We will use the Olsen and Associates website (www.oanda.com) to obtain these rates.

Current Well Status Enter one of the following codes to show the status of the well at the time this data is submitted.

CO: Permanently completed or in process of being permanently completed CS: Permanently completed and subsequently suspendedWT: Well test (DST) or temporary completion run or in progress, final well status unknown at this timeWC: Well test (DST) or temporary completion run or in progress, well will be permanently completed laterSUC: Unplanned suspension or temporary abandonment: expect to complete wellSUP: Unplanned suspension or temporary abandonment: expect to P&A wellSUU: Unplanned suspension or temporary abandonment: final well status uncertainSPC: Planned suspension or temporary abandonment: expect to complete wellSPP: Planned suspension or temporary abandonment: expect to P&A wellSPU: Planned suspension or temporary abandonment: final well status uncertainPP: Planned plug and abandonment PU: Unplanned plug and abandonment but re-spud not necessaryPS: Plugged back down hole to allow Geological sidetrack to be spudded RS: Well completely abandoned back to its spud point with a re-spud necessary to achieve the ……...objective of this well due to a fault of drilling group during drilling of this wellRG: Well completely abandoned back to its spud point with a re-spud necessary to achieve the objective ……..of this well due to geological reasons and not fault of drilling groupO: Other - please specify in Further details (column 120)

http://www.rushmorereviews.org/wbook/cprdpr/Cost-allocation-guidelines.zip


The times given in columns 103 - 111 are not included in the dry hole days.

103

104 D115/08

PA, SU or Completion DaysPlug and Abandonment days (for well status PP, PU, PS, RS or RG):If the well was plugged and abandoned after reaching TD enter the number of days spent on this operation, including circulation and clean-up time.

D109/07

9 Where a well and sidetrack(s) are drilled as part of one AFE the operator may choose whether to allocate the time for abandoning the upper section of the hole, above the sidetrack kick-off point, to the first well or the last

Suspension days (for well status SUC, SUP, SUU, SPC, SPP or SPU):If the well was suspended or temporarily abandoned after reaching TD, enter the number of days spent on this operation.

Completion rig days after TD (for well status CO or CS):If the completion operations have finished, enter the total rig days spent on completion operations after the end of the dry hole period including Non-Productive Time (NPT) and Waiting On Weather (WOW).

Completion operations include:• Running production liner or casing after TD• Wellbore preparation / clean-up• Installing sand control equipment • Running completion tubing and hanger

• Installing Xmas tree• Stimulating; perforating• Move-off operations (subsea completions)

If the completion operations are still in progress leave this field blank. We will ask you for the completion time at a later date.

In all cases, include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time

Do not include:• De-mooring or de-mobilisation time• Time when the well was suspended• Time for running a temporary completion or DST (well status WT or WC)• Well testing (well status WT or WC)

Other Operations Days (After TD)Please enter the number of days spent on other operations, between the end of the dry hole period and rig release, which have not been included in the previous columns.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time • Time spent installing a temporary completion / DST• Rig time spent well testing• Time spent on running a liner in a well with final status of 'suspended'9 i.e. where the production liner was run.after TD and then the well was suspended, include the time to..run the liner here• Any de-mooring (or mooring) time after the end of the dry hole period• Any time spent tidying up the sea bed

Do not Include:• Any dry hole operations including open hole logging operations at final TD• Plug and Abandonment days, Suspension days, or Completion days

Please provide details of any operations that you have included here in Further details (column 120).


105 D117/09

106 D118/09

107 D071/00

108 D072/00

109 D073/00

110 D074/00

111 D075/00

Mooring details: Columns 105 to 111 only apply to offshore wells drilled by floating rigs.This data must be provided for all mobile offshore rigs that utilise a mooring system.

Date of End of Well Operations(Floating Rigs Only)Enter the date operations on this well were finished and the rig was ready to be released. (dd-Mmm-yy)

If well operations are still in progress when the DPR data was submitted, leave this field blank, and we will ask for the date at a later time.

This field applies to offshore wells only, and is only required if the rig will be de-mooring / moving away at the end of this well.

WOW Before De-Mooring / Move-Off(Floating Rigs Only)If the start of rig de-mooring or rig move-off was delayed by poor weather conditions (WOW), please enter the number of days of Waiting On Weather (WOW). This is Waiting On Weather (WOW) after the end of well operations, (i.e. after the date given in the previous column).

Do not include here any WOW that you have included elsewhere in the workbook, or WOW during the de-mooring operation itself, as this is given in column 111.

If well operations are not yet finished leave this field blank and we will collect the data later.

This field applies to offshore wells only, and is only required if the rig will be de-mooring / moving away at the end of this well.

Rig Mooring SystemPlease enter the appropriate code to indicate how the rig was moored.

DP: Dynamic positioningC: Conventional

PM: Pre-moored 9 Previously moored to drill an earlier well in the same or an adjacent location - no need to move anchorsTL: Taut-leg 9 Only requires hook-up to pre-set anchorsO: Other

This is not required for jack-up or platform rigs.

Days Spent MooringEnter the total number of days spent mooring.Leave this field blank for pre-moored rigs, rigs with dynamic positioning, and for platform or jack-up rigs.

Mooring begins at start to drop first anchor and ends when the rig is fully moored.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time • Time spent hooking up a rig with a taut-leg mooring system

Do not include:• Time spent preparing to moor before the start of actual mooring• Time spent positioning a rig that was previously moored in order to drill an earlier well

Please give cumulative time spent mooring (from rig arrival on location until rig release) even where more than one rig was used.

Days Spent De-MooringEnter the total number of days spent de-mooring.Leave this field blank for rigs with dynamic positioning, and for platform or jack-up rigs.

De-mooring begins at start to raise first anchor and ends when rig fully de-moored and ready to move away.

Include:• Non-Productive Time (NPT) and Waiting On Weather (WOW) time • Time spent un-hooking a rig with a taut-leg mooring system

Do not include:• Time for pulling the riser

Please give cumulative time spent de-mooring (from rig arrival on location until rig release) even where more than one rig was used.

When a well and sidetrack(s) are drilled in a single program or AFE the final de-mooring should be reported against the last sidetrack drilled.

WOW During MooringEnter the number of days spent Waiting On Weather (WOW) during mooring operations.Include time spent waiting on sea conditions (including GoM Loop Current).

WOW During De-MooringEnter the number of days spent Waiting On Weather (WOW) during de-mooring operations.Include time spent waiting on sea conditions (including GoM Loop Current).


Non-Productive Time (NPT) is time spent on un-planned or un-scheduled events, except Waiting On Weather (WOW), as defined by your company.

112 D061/94

113 D062/97

114 D102/07

115 D103/07

116 D104/07

117 D105/07

118 D106/07

119 D095/04

For Example:

All wells : Non-Productive Time (NPT) and Waiting On Weather (WOW) time during the dry hole period.The times given in columns 112 - 113 must also be included in dry hole days.

Time spent on Technical / Mechanical sidetracking operations is considered to be NPT until the bit arrives at the equivalent point it was at before the problem occurred.

Waiting On Weather (WOW) During Dry Hole DaysEnter the total days spent Waiting On Weather (WOW) during the dry hole period.

Include:• Time spent waiting on sea conditions (including GoM Loop Current) during the dry hole period

Do not include:• Extreme weather conditions (e.g. hurricanes / cyclones etc.) that result in rig shutdown These are counted as unplanned suspensions

Non-Productive Time (Excluding WOW) During Dry Hole DaysEnter the total days of Non-Productive Time, however your company defines it, during the dry hole period. This may also be called trouble time / down time / interruption time etc.

Include:• Non-Productive Time (NPT) during batch-setting / pre-setting, coring and logging operations

• For re-spudded wells, all the time spent drilling and abandoning the original (failed) well should be reported as NPT (cols 113-119)

Do not include:• Waiting On Weather (WOW) time, or 'waiting on sea conditions', or time lost due to the GoM Loop Current

The Non-Productive Time (NPT) given in the previous column should also be reported in the following categories,(i.e. The values in columns 114 - 118 should add up to the total NPT given in column 113).

NPT Due to Rig ContractorEnter the number of Non-Productive days due to rig contractor equipment, personnel or procedures, during the dry hole period.

Please click here for guidelines on types of NPT that might be included in this section

NPT Due to Service CompanyEnter the number of Non-Productive days due to service company equipment, personnel or procedures during the dry hole period.


NPT Due to Operator ProblemsEnter the number of Non-Productive days due to the operating company equipment, personnel or procedures during the dry hole period.


NPT Due to External ProblemsEnter the number of Non-Productive days due to external factors, outside the direct control of Operator, Rig or Service Company, during the dry hole period.


NPT Due to Down Hole ProblemsEnter the number of Non-Productive days due to down hole operational, mechanical or geological problems during the dry hole period.


Main NPT Event(S) During The Dry Hole Period - Codes And TimesPlease enter details of any Non-Productive Time (NPT) events during the dry hole period that caused Non-Productive Time (NPT) of one day or more.

Please use the standard codes, followed by the time reported in days and parts of days. Please click here for the list of Standard IT / NPT codes

If several shorter NPT events of the same type result in one or more days of NPT these should be reported with one code.If a number of different problems result from one initial cause, all the NPT should be put against the code corresponding to the initial problem.

A well has problems with measurement while drilling tools (MWD) on 2 occasions, one instance lasting 18 hours and one lasting 12 hours. On the same well stuck pipe results in a twist-off, fishing and a technical sidetrack, amounting to 3 days of NPT.9 The NPT on this well is reported as MW:1.25D, SP:3.00D


120 D085/01

121 D069/92

122 D086/01

123 D076/00

124 D121/12

Australia and New Zealand basin numbers

Gulf of Mexico Area codes


Further Details Enter further details which are required to explain data given in any of the preceding columns. 9 e.g. if you entered 'other' in a previous field, explain here what the 'other' is

Please give the column number(s) of the field(s) to which your explanations apply.Use this field to give the previous well name, if the well has been re-named. For example, this may happen when an exploration well is re-designated as a development well.

Also use this field to give the reason for, and duration of, any unplanned suspension.

Comments Note any other significant features or aspects to the drilling of the well that will help other participants understand the data.

Please make comments as self-explanatory as possible.

Comments 2 Additional comments

API Well Number Enter the API well number(This data field is only required for US wells and will be ignored for other wells.)

Unique Well ID (Optional)Enter the unique well ID as assigned by your company.


1: Bonaparte Basin including Timor Sea and Zone of Co-operation2: Browse3: Canning4: Carnarvon5: Perth6: Duntroon7: Otway8: Bass9: Gippsland10: Taranaki (NZ)11: Any other Australian / NZ offshore location not given above12: Australian land wells not located in any of the basins noted above 13: New Zealand land wells not located in any of the basins noted above

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AC: Alaminos CanyonAT: Atwater ValleyDD: Destin DomeDC: DeSoto CanyonEB: East BreaksEW: Ewing BankGB: Garden BanksGC: Green CanyonKC: Keathley CanyonLL: LloydLU: LundMC:Mississippi CanyonPI: Port IsabelVK: Viosca KnollWR:Walker Ridge

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Drilling Performance Review DPR 2014 workbook. Rev 0.2 30-May-2014

Data input spreadsheet: 2014

Click on a column heading to see the definition of the field.Some cells provide drop down boxes to aid data entry. A warning message may be displayed where invalid data is entered.

Click column heading to see definition D001/93 D002/89 D003/00 D004/95 D005/00 D006/00 D007/99 D008/99 D111/08 D070/04 D080/01

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17Well identification

N/S E/W

Very Important: Please first read the instructions and data definitions. Some definitions have changed since last year.

Geographical latitude Geographical longitude

Country Official or Formal Well NameIn-House or Common Well Name (GoM Prospect Name)Field or Basin Name (GoM Area Code)Block NumberPlatform Name (or Land Well Pad Number)Lat Deg

Lat Min

Lat Sec

Long Deg

Long Min

Long Sec Drilling Contractor Rig Name Owner Drilled

If you have questions email us at [email protected] or

call us on + 44 (0) 1224 251042

G13

Degrees

H13

Minutes

I13

Seconds

J13

North/South

K13

Degrees

L13

Minutes

M13

Seconds

N13

East/West

D009/94 D081/01 D082/01 D092/04 D010/00 D096/05 D116/09 D011/00 D012/00 D013/89 D120/10 D014/92 D015/00 D016/92 D017/9918 19 20 21 22 23 24 25 26 27 28 29 30 31 32

Hole Type Locator WellMultilateral Multilateral Junction TypeNumber of LateralsNumber of Contingency Geological SidetracksNumber of Mechan'l S/tracksRe-Spud Due to Original Well Failure to Reach ObjectiveOriginal (Failed) Well Name (Re-Spud Well Only)Well Type Play TypeHigh Pressure WellHigh Tempera-ture WellRig Type Drilling Method

D019/00D018/99 D107/07 D020/91 D021/91 D097/05 D098/05 D022/92 D077/99 D078/00 D079/00 D084/01 D024/92 D025/95 D026/99

33 34 35 36 37 38 39 40 41 42 43 44 45 46Hole size and shape

Units of MeasurementWater Depth / Land Well Drill Floor ElevationSpud Depth MTD Final WellboreUnused Lengths Due to Conting'y Geol S/TracksLocator Unused LengthTVD Salt TVD at Start of SaltTVD at End of SaltComplex GeometryMaximum Angle in DegreesTotal Length of Horizontal Sections Final Drilling Bit Size/Hole Size (inches)

AH9

Water depth: D019/00

AH10

Land well drill floor elevation: D107/07

D027/93 D094/04 D101/07 D028/9347 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69

Pre-existing casing strings - for 'G' and 'S' type wells only New casing strings & liners (suffix 'e' where expandable casing is used)

Pre-Existing Casing 1









Pre-Existing Casing

10

Pre-Existing Casing

11 New Conductor CasingConductor Installed By Drilling Rig?New

Casing 2New

Casing 3New

Casing 4New

Casing 5New

Casing 6New

Casing 7New

Casing 8New

Casing 9

New Casing

10

New Casing

11

D029/98 D030/98 D112/08 D031/95 D032/95 D033/98 D034/92 D035/93 D036/99 D037/99 D087/02 D088/02 D038/00 D039/00 D089/02 D113/08 D114/08 D099/05 D040/95 D090/0270 71 72 73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89

Drilling fluid data Coring, logging and under-reaming Land wells Pre-spud timings

Pressure BalanceDrilling Fluid TypeMud Weight UnitsMud Weight at TDMax. Mud WeightCuttings DisposalCoring DaysCoring Interval Logging Days Not at TDLogging Days at TDUnder Reaming DaysReamed / Under-Reamed Interval(s)FEWD? Age of Deepest Formation AccessedNewTechniquesRig Move Time (Land Wells Only) - OptionalRig Move Within Field? (Land Wells Only) - OptionalGeological Sidetrack Pre-Spud & Whipstock DaysSlot Recovery/Enhance-ment Pre-Spud DaysOffline Slot Recovery Operations

CD13

Formation Evaluation While Drilling

D091/03 D042/93 D043/89 D044/99 D045/00 D046/00 D047/99 D048/91 D049/00 D050/00 D051/99 D052/95 D053/02 D115/0890 91 92 93 94 95 96 97 98 99 100 101 102 103 104

Timings up to the end of the dry hole period Costs After end of dry hole period

Batch-Set / Campaign DrilledSpud Date Dry Hole DaysDate of End of Dry Hole PeriodNumberof Well Suspen-sionsDays Spent on Suspen-sion / Re-Entry OpsTotal Well Site DaysDry Hole Cost (millions)Prelim or Final Dry Hole Cost?Complete Dry Hole Cost?Total Well Cost (millions)Currency Current Well Status PA, SU or Completion DaysOther Operations Days (After TD)

NPT in cols 114 to 118 should add up to the total NPT in col 113D117/09 D118/09 D071/00 D072/00 D073/00 D074/00 D075/00 D061/94 D062/97 D102/07 D103/07 D104/07 D105/07 D106/07 D095/04

105 106 107 108 109 110 111 112 113 114 115 116 117 118 119Mooring and de-mooring - Floating rigs only. Non-Productive Time (NPT) during the dry hole period

Date of End of Well Ops(Floating Rigs Only)WOW Before De-Mooring / Move-Off (Floating Rigs Only)Rig Mooring SystemDays Spent MooringDays Spent De-MooringWOW During MooringWOW During De-MooringWaiting On Weather (WOW) During Dry Hole Days Total NPT (Excl WOW) During Dry Hole Days NPT Due to Rig ContractorNPT Due to Service CompanyNPT Due to Operator ProblemsNPT Due to External ProblemsNPT Due to Downhole ProblemsMajor NPT Events During the Dry Hole Period - Codes And Times

D085/01 D069/92 D086/01 D076/00 D121/12120 121 122 123 124

US wells only

Further Details Comments Comments 2 API Well Number Unique Well ID (Optional)

Drilling Performance Review DPR 2014 workbook. Rev 0.2 30-May-2014

Time-depth data tables : 2014

You may show more than 1 depth and hole size reading in a day.

Units (M/F)Well name

Day Day Day Hole size Day Day Hole size Day Day Hole size Day

Please give the actual depth along the well bore (MTD) and the hole size for each day.

Actual depth

Hole size

Actual depth

Hole size

Actual depth

Actual depth

Hole size

Actual depth

Actual depth

Hole size

Actual depth

Remember to enter Hole Sizes, not casing sizes

A8

Are the data in metres (M) or feet (F)?

B9

Enter well name in this cell - the name should correspond to the name given in the data input sheet.

E9


H9


K9


N9


Q9


T9


Actual depth

Hole size

W9


How should I enter my sidetrack well?

Description of my well Type of well Hole type

√ G

√ S

√ G

√ S

X -

X -

√ G

X -

X This data is not collected -

? -

? ?

A guideline to help decide:

Click for more information

A well planned and drilled from the bore of another well to a different geological target

Geological sidetrack- a separate row of data Geological Sidetracks

A well planned and drilled from the bore of another well that has been in production

Slot Recovery well- separate row of data Slot Recovery wells

A sidetrack requested by the sub-surface group during drilling of a planned well

Geological sidetrack- even though it is not "planned" a separate row of data

Geological Sidetracks

A well drilled to extend a producing well bore further into the reservoir

Slot enhancement well- separate row of data Slot Recovery wells

A sidetrack drilled to overcome a mechanical or technical problem (e.g. a stuck drillpipe or casing)

Mechanical sidetrack- included in parent well data Mechanical / technical sidetracks

Sidetracks only to be drilled if the well bore goes out of the reservoir

Contingency Geological sidetracks - included in parent well data

Contingency Geological sidetracks

Planned sidetracks only to be drilled if certain geological conditions are met

Probably Geological sidetrack- a separate row of data

Geological sidetracks

A sidetrack is drilled for purely coring purposes, before the main well reaches TD

Include with parent well data (similar to Contingency sidetrack)

New wells

A sidetrack is drilled for purely coring purposes, after the main well reaches TD

A well designed to sidetrack through the reservoir from a pilot hole

Check definitions to see whether this is a Locator well Locator wells

An unplanned sidetrack drilled to avoid unexpected geological problems encountered while drilling original hole

Operator may decide how to report it. See below

Sidetracking as a result of failure to be able to drill ahead, for reasons such as hole instability, squeezing formation, lost circulation, depleted zone, hard stringers, over-pressured formation and similar circumstances

Mechanical sidetrack

Drilling into an unexpected formation causes the sub-surface group to decide that sidetracking to a new well path would be preferable

Geological sidetrack

Back to instructions

* For land wells, the spud point is at the bottom of the cellar

A guide to sidetracksReturn to Instructions

True vertical depth (TVD) Rotary table to TD

New well

Target Depth (TD)

Rotary table

Spud depth Rotary table to spud point

Measured Total Depth (MTD) = The distance from rotary table to TD along the well bore

Spud point *

Water depth = mean sea level

True vertical depth (TVD) Rotary table to TD

The well from which a Geological sidetrack is made will not have been previously used for producing or injecting.

A planned Geological sidetrack (Hole type G) is one that is planned and engineered prior to spud. It will often have a separate AFE to its parent well. However some unplanned sidetracks may also be designated as Geological sidetracks.

If an exploration or appraisal sidetrack is drilled part way through the drilling of a development well this will normally be entered as a Geological sidetrack.

Do not use hole type 'G' for "Contingency sidetracks" drilled as a result of unexpected or unpredictable formation or reservoir characteristics. Contingency sidetracks are entered as part of their parent well.

Do not use hole type 'G' for by-pass coring "sidetracks". These are treated like "Contingency sidetracks" and entered as part of their parent well (if drilled before TD is reached).


Geological Sidetracks

New TD

Rotary table

True vertical depth (TVD) Rotary table to new TD

Spud depth Rotary table to spud point(kick-off point) along hole

Spud point is kick-off point Old hole is plugged

MTD = rotary table to new TD along the well bore


* Before drilling can start some or all of the following activities will be necessary* > Kill the well* > Pull the old completion tubing, tubing hanger and packers* > Set a cement plug to abandon the old hole* > Repair existing casing* > Set a whipstock or drill a ledge to set direction for drilling the new hole* > Mill through any existing casing, using milling assembly* > Run in drilling assembly ready to start drilling the new hole.**

* Slot recovery well - Sidetrack from a wellbore which was previously producing or injecting

* Slot enhancement - Extension of a wellbore which was previously producing or injecting

This is sometimes referred to as "de-completion".


Slot Recovery Wells

New TD

Rotary table

True vertical depth (TVD) Rotary table to new TD

Spud depth Rotary table to spud point(kick-off point) along hole

Spud point is kick-off point Old hole is plugged

MTD = rotary table to new TD along the well bore


A Multilateral well is a well with 2 or more producing (or injecting) bores connected together downhole and produced via a single wellhead.

A Multilateral well must be entered as a single row of the data entry worksheet with the footage, costs and times for all the laterals added up.

When you give the number of laterals you should count the number of producing (or injecting) bores in the well, including the motherbore if it is producing (injecting).

If an additional lateral(s) is drilled in a well that already has producing (or injecting) bores, only give the footage, time and costs relating to the additional lateral(s).

Please include a diagram with measurements to show the size, shape and configuration of Multilateral wells.


Spud depthRotary table to spud point

New Multilateral well

Rotary table

Spud point

MTD = Rotary Table to TD1 + Junction point to TD2

TVD Vertical depth fromrotary table to TD of deepest lateral

TD1

TD 2

Junction point

The length of every lateral, measured from its junction to its TD, should be included in the MTD.


In this example enter the sidetrack data on a separate row as a Geological sidetrack.

A Locator well is a well designed to penetrate the reservoir in order to accurately locate its position or carry out other geological investigation, and then to be sidetracked for production purposes - see diagram.

This is effectively designed as a single well. The sidetrack is considered to be an integral part of the single well design, not a separate Geological sidetrack.

The parent hole may be drilled from the seabed or bottom of cellar (hole type 'N'); or it may be drilled from a previously producing well-bore (hole type 'S' - Slot Recovery); or from a Geological sidetrack (hole type 'G' ).

In a Locator well the portion of the parent hole that extends below the junction with the sidetrack is not intended to produce. However, the well as a whole is normally a development well.

If the parent hole below the junction with the sidetrack is planned to be a producer or injector the well is classified as a multi-lateral.

It is not a Locator well if in the planning phase there was any uncertainty about drilling the sidetrack.

For example, if the parent hole is an appraisal well and the sidetrack is only drilled because certain conditions were found, this is not a Locator well.


New Locator well

Final TD

TD of parent (pilot hole)

Rotary table

MTD = Rotary table to final TD along well bore

Kick-offpoint Unused length

= Kick-off point to TD of parent

TVD Vertical depth from rotary table to final TD

Spud depth

A Locator well is designed to locate the reservoir then

sidetrack through it.

We expect these sidetracks to be drilled for the purpose of getting back into the reservoir.

A Contingency Geological sidetrack is a well which has been planned prior to spud, but only as a contingency. It will normally be part of its parent well AFE.

If you drill an appraisal well, and then decide to drill a sidetrack as result of what is found - that is not counted as a Contingency Geological sidetrack. It is normally entered as a Geological sidetrack.

If you are not sure how to enter the data please contact us to discuss it.


New well with Contingency

Geological sidetracksRotary table

TVD Vertical depth fromrotary table to final TD

Spud depth

Final TDK1

K2

TD1

TD2

Unused lengths due to Contingency sidetracks= (K1 to TD1) + (K2 to TD2)

MTD = Rotary Table to Final TD along hole

Water depth = msl

A Mechanical sidetrack is also called a technical sidetrack or bypass.

The dry hole days and dry hole cost of the main well include all times and costs of technical / Mechanical sidetracks.

Usually this Mechanical sidetrack will be entered as non-productive time in the Completions Performance Review.

It is an unplanned sidetrack drilled for to pass an obstruction (e.g. lost tools, stuck pipe, hole collapse etc) or to improve the wellpath (e.g. re-drilling "lost holes", "key seats", "crooked holes" etc).

All the time spent drilling a Mechanical sidetrack is counted as non-productive time until the bit arrives at the equivalent point it was at before the problem occurred.

Exceptions:Sometimes a Mechanical sidetrack is necessary after the start of completion operations. For example, the liner or screens may get stuck when they are installed.

It is only necessary to enter it in the DPR, as non-productive time in the drilling of the well, if the problem resulted from the way the well was drilled.


New well with

drilling Mechanical sidetrack

TD

Rotary table

Spud depth

MTD = rotary table to TD along hole.Abandoned section is not included.

Spud point

Section abandoned due to drilling problem

Mechanical sidetrack round fish (drilling)


Water depth = msl

New well with

completions Mechanical sidetrack

TD

Rotary table

Spud depth

MTD = rotary table to TD along hole.Abandoned section is included.Completions sidetrack section is not included.

Spud point

Section abandoned due to completions problem

Mechanical sidetrack round fish (completions)

TVD Vertical depth fromrotary table to final dry hole TD

Water depth = msl

A pilot hole is a narrow gauge hole drilled from surface to a predetermined shallow depth in order to investigate the possibility of shallow water or gas hazards at minimum risk.

Shallow Gas or Water Pilot Hole

Final TD

Rotary table

MTD = Rotary table to final TD along well bore

Unused length= Spud to TD of pilot hole, not recorded when the pilot hole is abandoned!

Reamed/Under-reamed interval= length of pilot hole enlarged and used as the conductor and/or surface hole section of the main well


Spud depth

A Pilot Hole is a narrow gauge surface hole

intended to determine the presence of shallow gas

or water hazards.

New wells with shared conductor

Two (or 3) wells are drilled from surface sharing a single conductor and splitter well head.Dual strings protrude a few metres below the conductor and the two well bores kick off below these strings.Each well is produced through its own Xmas tree

"Side by side" wells

Two wells are drilled from surface sharing a single conductor and splitter well head.A large surface hole is drilled below the conductor and 2 strings of surface casing are run and cemented.Individual well bores are drilled from the surface casing.Each well is produced through its own Xmas tree

How to enter the data

Field name Col no. Data to be entered for the first well drilled Data to be entered for the 2nd well drilled

Hole type 18 New New

Spud depth 35 At sea bed (or bottom of the cellar)

Pre-existing casings 47 - 57 None

New Conductor casing 58 Size of conductor followed by (s) Blank (as it is shown as pre-existing)

New casings 59 - 69 All the casings run within the conductor All casings run below the shared hole section.

Spud date 91 Date of spud at the seabed or cellar.

Dry hole days 92

Dry hole cost 97

Comments 121 Give the names of the wells which share the conductor Give the names of the wells which share the conductor

Return to Instructions

At the depth of the casing shoe in the deepest shared hole section.

Give size of shared conductor and casings run in the shared hole section.Insert suffix "s" after the conductor size, to show that it is shared.

Date of drilling out of shoe of the casing in the deepest shared hole section

Include all the time for installing the conductor, drilling the shared hole section, running and cementing both casings

Do not include any time for installing the conductor, nor the time for drilling the shared hole section, running and cementing both casings

Include the cost of installing the conductor andthe cost of running and cementing both casings

Do not include the cost of installing the conductor, nor the cost of drilling the shared hole section and running both casings into it.

Split / shared conductors

Side by side wells

Sub-salt Return to InstructionsSub-salt

Pre-salt

A sub-salt well is drilled to a geological target beneath a salt sheet found in a place other than where it is formed, due to salt migration.

This salt sheet overlies stratigraphically younger rock.

A sub-salt well will go through a salt sheet and stop below.

A pre-salt well will go through mother salt and stop below.

TD is often far deeper than a sub-salt well. Architecture is often more complex

This ‘mother’ salt overlies stratigraphically older rock.

The mother salt bed (pre-salt layer).

The Pre-salt layer is a geological formation found on the continental shelves off the coast of Africa and Brazil.

The mother salt (pre-salt layer)

Non-Productive Time - guidelines

Non-Productive Time (NPT) shall be reported as the Operator defines it for their own internal purposes within the following categories.

Here are some general guidelines as to what each NPT category may cover.

Code Description of non-productive time category

114 Rig Contractor equipment, personnel or procedures

BH BHA rotary equipment (DP, DC, HWDP, stabs, Jars, X-overs etc.) but not drill bits

BO BOP (surface or subsea) and other pressure control equipment, including standpipe manifold, choke manifold, IBOPs, risers.

DW Draw works

MP Mud pump / mud system

TD Top drive

RO Other rig contractor equipment, personnel or procedures

115 Service Company equipment, personnel or procedures.

CT Coiled Tubing

CR Coring

DE

BT Drill bits including hole openers.

LW Logging while drilling: unplanned pulling / running and repair of LWD equipment.

LE Logging: unplanned pulling / running and repair of electrical logging equipment.

MM Mud Motor

MW MWD tools

PR Pressure integrity components and pressure testing equipment.

RV ROV

SV Surveying: directional surveying, excluding MWD.

SX

WL Wireline: slick-line wireline unit and equipment.

SO Other service company equipment, personnel or procedures.

116 Operating Company equipment, personnel or procedures.

LH Liner Hanger equipment or procedures

TU Tubular: Operator owned casing including connections, pipe body, float collars, DV collars etc.

OO Other operating company equipment, personnel or procedures.

117 External, outside the direct control of Operator, Rig or Service Company.

AI

FM

LD Labour industrial dispute

CP Local community problems leading to interruption of operations.

LG Logistics and supply. Unavailability of trucks, boats, helicopters and materials not being available in time.

PD

SI

WO Waiting on other external factors

118 Downhole operational, mechanical or geological problems

CS

CM Cementing: including flash-set or no set cement plugs and squeezes.

DD

FS Fishing for junk / debris accidentally left in the hole. Includes circulating for hole cleaning, e.g. with junk sub.

LP

LC Lost Circulation: curing losses that are formation related. Includes tripping time, spotting and pumping LCM and cement pills.

HC

SP Stuck pipe: freeing stuck pipe until pipe is free or backed off. Includes pumping of spotting fluid and waiting for pill to work.

ST Technical / mechanical sidetrack: drilling a sidetrack to pass an obstruction.

WC

FP

DO Other downhole operational, mechanical or geological problems


Column no.

Directional drilling: repairs; unplanned pulling / running of directional drilling equipment including rotary steerable but excluding MWD and mud motors.

Wellhead: repairs; unplanned pulling / running of surface or subsea well heads, including wear bushing, seal assemblies and mud line suspension equipment - casing hangers

Accident or Injury: interruptions of operations due to incidents or accidents. Includes post-accident investigations that require shutting down operations.Force Majeure: abnormal circumstances such that the consequences could not have been avoided through the exercise of all due care.

Platform delays: location issues on the platform, such as unavailability of cranes or other services. Excludes simultaneous or concurrent operational delays.Simultaneous / Concurrent Ops, e.g. safety drills, helicopter operations, waiting on production facilities to be available, where there has been a conscious decision to prioritise activities and stop well work.

Casing running: remedial work due to problems with running the casing / non-production liner to the planned depth. Pulling casing / liner, wiper trips, washing down, crossed threads, stabbing. Use of unplanned scab liners or tie-back strings.

Directional drilling: solving directional services, such as steering problems not due to equipment, fishing jobs due to doglegs, or trips to change BHA components in order to reach drilling target.

Logging: wireline evaluation / logging tool mis-runs, fishing jobs due to parted or stuck electric wireline tools, wiper trips for conditioning hole for logging, clean-out trips due to mis-runs and re-running of tools.

Mechanical borehole: hole collapse / instability; differential sticking due to overbalance in depleted zones, stuck pipe due to low mud weight, problems due to ledges, key seats, under gauge hole, squeezing formations and inadequate hole cleaning.

Well Control: containing unexpected entry of formation fluids (gas, oil, water) into the well, requiring weigh up and kill operations or excessive circulating and conditioning of the mud.Wellbore fluids: mud-related problems except lost circulation, e.g. clay ball / gumbo problems, stuck casing / pipe due to mud-induced borehole cleaning problems, differential sticking, excessive time circulating and conditioning mud.

The unique data identifierThe format of the ID number is Dnnn/yy where D indicates a DPR data item, nnn is the number related to the data item, and yy indicates the year that this item of data was first collected.

Some data items have changed over the years. For example new codes may have been added.Only where an item has changed significantly will this be reflected in the "yy" part of the code.Examples:

Column 90 asks whether a well was batch-set and/or campaign drilled, and whether there were turnkey operations.In the years 2000 to 2002 we asked only whether the well was batch-set.The code for this item when it appears in data from 2003 - 2007 will be D091/03For the older data the code will be D091/00

Multi-lateral wells were originally identified by a hole type of "M". It was only in 2001 that a separate "multi-lateral" field was used for this item.The code for this item is therefore D082/01, even though information on multi-lateral wells is available prior to 2001.

Wells that require re-spudding

The time and cost of moving the rig from the failed well in order to spud the new well is excluded from the dry hole days and dry hole cost.

This well should be marked 'RG' in the well status column (column 102).

Working out the spud date - some examples

New well (which may or may not be batch set) ** Spud date is

New hole is drilled, then the conductor casing is set When the drill bit penetrates the seabed or bottom of cellar

The conductor casing is installed (e.g. by pile driving) by the drilling rig When the conductor casing penetrates the seabed or bottom of cellar


A well that did not reach its geological objective, was completely abandoned back to its spud point and requires to be re-spudded because of a fault or failure of the drilling group will be considered as non-productive time in the re-spudded well.

The spud date of the re-spudded well will be taken as the spud date of the original well. The time and cost of drilling the original well will be included in the time and cost of the re-spudded well. All the time spent drilling the original well should be reported as NPT (cols 113-119) in the re-spudded well.

If no decision has yet been made on when the well will be re-spudded, enter the incomplete well as a separate row of data, with the status 'RS' in the well status column (column 102).

A well that did not reach its geological objective, was completely abandoned back to its spud point and requires to be re-spudded because of geological considerations (not a fault or failure of the drilling group) is treated as a normal well.

Return to instructions


The conductor is installed (e.g. by pile driving) but not by the drilling rig The start of drilling out of the shoe of the conductor

The start of drilling from seabed or bottom of cellar

** The above rules apply also to the first new well drilled from a split or shared conductorbut there are different rules for the second (or third) new well drilled from a shared conductor.

The well is drilled to top of reservoir and suspended. Later (could be a year or more) it is re-entered to drill to TD.

- Click here for help on shared conductors.

Some data items have changed over the years. For example new codes may have been added.

Column 90 asks whether a well was batch-set and/or campaign drilled, and whether there were turnkey operations.

The code for this item is therefore D082/01, even though information on multi-lateral wells is available prior to 2001.

Wells that require re-spudding

The time and cost of moving the rig from the failed well in order to spud the new well is excluded from the dry hole days and dry hole cost.

This well should be marked 'RG' in the well status column (column 102).

When the drill bit penetrates the seabed or bottom of cellar

When the conductor casing penetrates the seabed or bottom of cellar

back to its spud point and requires to be re-spudded because of a fault or failure of the drilling

The spud date of the re-spudded well will be taken as the spud date of the original well. The time and cost of drilling the original well will be included in the time and cost of the re-spudded well. All the time spent drilling the original well should be reported as NPT (cols 113-119) in the re-spudded well.

If no decision has yet been made on when the well will be re-spudded, enter the incomplete well as a separate row of data, with the status 'RS' in the well status column (column

A well that did not reach its geological objective, was completely abandoned back to its spud point and requires to be re-spudded because of geological considerations (not a


The start of drilling out of the shoe of the conductor

The start of drilling from seabed or bottom of cellar0

Record of revisions to this workbook

Revision number Date Column number Unique ID Column name

0.1 12th March 2014 92 D043/89 Dry Hole Days

0.2 30th May 2014 96 D047/99 Total Well Site Days

Change

Details of BOP timings to be included in the Dry Hole Days period were amended to remove the word "verification", as there has not yet been agreement of the Review Participants of how BOP verification operation timings should be reported.

Clarification not to include any time spent on well operations when the rig was not on location e.g. completion operations carried out after the rig was released.

[xls]drilling performance review - rushmore...

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