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Diseno de Pozos y Bha

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© Kingdom drilling service Ltd. Table of contents Table of contents........................................................................................................................ 1 Summary .................................................................................................................................... 2 1.1 General summary ........................................................................................................ 2 Geological Evaluation & Summaries.......................................................................................... 7 1.2 Structural Setting and Prognosis ................................................................................. 7 1.3 Mud programme ........................................................................................................ 10 1.4 Casing Scheme ......................................................................................................... 10 1.5 Health, safety and environment ................................................................................. 16 1.6 Wellbore stability........................................................................................................ 17 1.7 Directional control and surveying .............................................................................. 18 1.8 Drillstring & BHA design considerations. ................................................................... 20 1.9 Hole cleaning hydraulics............................................................................................ 30 1.10 Kick tolerances .......................................................................................................... 34 1.11 Stuck pipe and hole problem prevention ................................................................... 35 1.12 Ways to Minimise Torque and Drag .......................................................................... 45 1.13 Mud gas definitions.................................................................................................... 49 1.14 Riserless drilling......................................................................................................... 50 References. BP toolkit. (kick tolerance.) BP’s drilling toolkit (casing setting depths, directional plan, hydraulics and hole cleaning.) Kingdom drilling spreadsheets. (weight on bit, stabiliser placement, critical rotary speed (vertical hole) Modern well design (Bernt Aadnoy.) BP ERD manual. Kingdom drilling, drillstring design manual. Kingdom drilling. well planner guides to hydraulics and hole cleaning. Kingdom drilling General Drilling guidelines, stuck pipe procedures etc..
Transcript
Page 1: Diseno de Pozos y Bha

© Kingdom drilling service Ltd.

Table of contents

Table of contents........................................................................................................................1

Summary....................................................................................................................................2

1.1 General summary ........................................................................................................2

Geological Evaluation & Summaries..........................................................................................7

1.2 Structural Setting and Prognosis .................................................................................7

1.3 Mud programme ........................................................................................................10

1.4 Casing Scheme .........................................................................................................10

1.5 Health, safety and environment.................................................................................16

1.6 Wellbore stability........................................................................................................17

1.7 Directional control and surveying ..............................................................................18

1.8 Drillstring & BHA design considerations. ...................................................................20

1.9 Hole cleaning hydraulics............................................................................................30

1.10 Kick tolerances ..........................................................................................................34

1.11 Stuck pipe and hole problem prevention ...................................................................35

1.12 Ways to Minimise Torque and Drag ..........................................................................45

1.13 Mud gas definitions....................................................................................................49

1.14 Riserless drilling.........................................................................................................50

References.Ø BP toolkit. (kick tolerance.)Ø BP’s drilling toolkit (casing setting depths, directional plan, hydraulics and hole cleaning.)Ø Kingdom drilling spreadsheets. (weight on bit, stabiliser placement, critical rotary speed

(vertical hole)Ø Modern well design (Bernt Aadnoy.)Ø BP ERD manual.Ø Kingdom drilling, drillstring design manual.Ø Kingdom drilling. well planner guides to hydraulics and hole cleaning.Ø Kingdom drilling General Drilling guidelines, stuck pipe procedures etc..

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© Kingdom drilling service Ltd.

Ø Summary

1.1 General summary

The object of this exercise was to analyse and discuss three different wellbore profilesprovided. Select best profile based on selected casing setting shoe depths and recommendpreferred wellbore profile taking into account all factors concerned. I.e.

Ø Wellbore stability,

Ø directional control and surveying,

Ø drillstring mechanics,

Ø BHA and drillstring considerations

Ø hole cleaning, hydraulics and cementing.

1.1.1 Profile SelectionFrom the perspectives, the consensus based on technical merit was that is option A withsome modification due to casing setting depths would be the preferred wellbore profile aslong as no anti collision constraint was presented.

This is on the basis that no directional work is required in the trouble some top, surface holeand intermediate casing sections. The objectives of these sections must be therefore to drill atcase them off as quickly, easily, and effectively as possible. In that as long as directionalrequirements can be met later in the well. The least hazards and risk are present in thiswellbore design.

Due to all the accumulating risk and difficulties anticipated in the first three sections. It canalso be readily concluded that running simple straight hole assemblies would reduce rig, BHA,drilling casing and cementing times considerably.

All directional work required in profile A can also be accommodated below the casing shoessetting depths selected. The profile would offers lowest torque and drag, reduced casing wearof three profiles, and although tangent section is at high angles. The formations are bestsuited to allow sliding in this section and the tangent angle should not prohibit 7” liner orcompletions from being slid to bottom. Buckling calculations would have to be done to ensurethis.

Casing shoes for the section, have been selected on the premis to:

Ø provide sufficient leak off and well integrity to drill the next sectionØ Provide adequate kick tolerance to drill next sectionØ Achieve good cementation around casing shoeØ Isolate troublesome formationsØ Allow all directional drilling to be accommodated with minimal doglegs.Ø Provide best mud weight selection to maximise stability of the wellboreØ Afford best BHA, drillstring and “run what you need” design.

A more detailed summary of each of the individual profiles presented and subject areas toconsider are now reviewed. Details of analysis and discussions are therefore included whereappropriate in the accompanying reports within this document.

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1.1.2 Option summaries.

Option A, B & C.

Based on the Daisy field lithology column, the casing setting depths established, hazardspresented in each section and the requirements needed to drill the next preceding section i.e.well integrity, kick tolerance, wellbore stability considerations etc.

The wellbore A profile can best be accommodated based on casing seats as illustrated.

Option A avoids any directional work through formations that will exhibit poor assemblyreponse or that are fragile and unstable. I.e. Top and surface hole formations. In that this is whyoptions B and C are most unsuitable.

Having a hole angle of approximately 50degrees max. is also preferred at the bottom of the17 ½” section. I.e. Affords better hole cleaning, will not require mud weight increase forwellbore stability concerns and is less likely to present difficulties running and cementingcasing. Options B & C have higher hole angle that present a greater hazard and risk of holeproblems and difficulties occurring.

Kicking off deeper in option A also will results in less overall drag and torque in the 12 ¼” and8 ½” sections. Options B and C will most likely result in higher torque and drag (and casingwear) in these wellbore sections.

With adequate flowrates affordable (see hydraulic calculations) and the fact that formationsare more cemented and competent (less likely to give hole difficulties.) The build is bestpresented in option A in these section for these reasons.

For 2 degree builds proposed however in option A, due to casing seats selected. The wellwould have to be kicked off at approximately 689m (see directional section.) As the 20” shoeis planned into the Halite at approximately 830m. A slightly higher dogleg severity wouldtherefore have to be accommodated in the well plan. This magnitude of the dogleg increase isnot foreseen as a difficulty.

Finally running 7” liner and completion must also be accounted for in the final max tangentangle permissible. This may require further build once entering the reservoir or slight changeon wellbore profile through the reservoir if this indeed can be accomodated from a producingperspective.

Once again option A is seen as the best initially viewed profile for running 7” liner and finalcompletion.

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1.1.3 Profile summary and discussion

Section Hazards Option A Option B Option C36” Top hole & 30”conductor

Ø UnconsolidatedØ Glacial drift, boulders.Ø Difficult to build angle,Ø Cementing to seabed

Proposed straight hole that can bereadily drilled, cased, efficiently & costeffectively.

Formations very soft making kickoff time consuming with risk ofencountering boulders that maymake achieving directionalrequirements even more difficult.

Formations very soft making kickoff time consuming with risk ofencountering boulders that maymake achieving directionalrequirements even more difficult.

26” Surface hole &20” surface casing

Needs to be deepenough to have leakoff to drill next sectionI,e, set in halite.

Ø Soft & stickyformationsØ Likely to wash outØ Fractured formationsØ Lost circulationØ Cementing/ loss zoneØ Cementing to seabed

Proposed straight hole that can bereadily drilled, cased, efficiently & costeffectively.

Maintaining inclination throughfractured formations could provedifficult and increase liklinees offurther and accumulated drillingproblerms occuring. Doglegs in thissection can lead to >casing weartorque & drag problems later inwell.

Bulding inclination through soft andstick formations, and throughfractured formations could provedifficult and increase liklinees offurther accumulated drillingproblerms occuring. Doglegs in thissection can lead to >casing weartorque & drag problems later inwell.

17 ½” Intermediatehole & Intermediate13 3/8” casing.

Casing shoe set priorto drilling into potentialupper reservoir,

Ø Swelling halite.Ø Brittle reactive shales.Ø Exposure timeØ Kick tolerance

Proposed to start building in halite thatshould not present a problem..Maximum inclination at section TD.This is also acceptable due to mud wt,instability, hole cleaning that couldcreate difficulties at higher angles. Lessconstraints mean section can be drilled& cased quickly.

Higher inclinations e.g. 60degreeundesirable in this section due torequirement for >mud weight tostabilise claystones. This will<ROP, hydraulics, hole cleaningcapabilities. Higher risk of holedifficulties. Longer hole exposure.More likely difficult trips.

Higher inclinations e.g. 60degreeundesirable in this section due torequirement for >mud weight tostabilise claystones. This will<ROP, hydraulics, hole cleaningcapabilities. Higher risk of holedifficulties. Longer hole exposure.More likely difficult trips.

12 ¼” hole and9 5/8”productioncasing

casing shoe prior todrilling into reservoir.Mud wt can bereduced to have morewell integrity.

Ø High angleØ Hole cleaningØ Open hole “open time”Ø Kick toleranceØ Cementing

High angle build, and tangent suited tothis section where formations aregenerally less troublesome, & generallymore competent. Formations wellsuited for good directional control. Nodifficulties perceived. Higher doglegscan be accommodated if required. Bestsection for final directional work.Disadvantage is high tangent angle

High angle build, and tangentsuited to this section whereformations are generally lesstroublesome, & generally morecompetent. Formations well suitedfor good directional control.. Nodifficulties perceived. Higherdoglegs can be accommodated ifrequired. Best section for finaldirectional work.

High angle build, and tangentsuited to this section whereformations are generally lesstroublesome, & generally morecompetent.Formations well suited for gooddirectional control. No difficultiesperceived. Higher doglegs can beaccommodated if required. Bestsection for final directional work.

8 ½” hole sectionand 7” productionliner.

Ø Differential stickingØ Formation damageØ Sliding (torque/drag.)Ø Unconsolidated sandsØ Hole washout.

Very little directional work required.Can therefore concentrate onoptimising geo/steering and drillingaccurately through reservoir section.

Requirement to do more buildingand turning in the section thandesired. Minimal directional controlsought so section can be drilledquickly to minimise formationdamage

Requirement to do more buildingand turning in the section thandesired. Minimal directional controlsought so section can be drilledquickly to minimise formationdamage

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© Kingdom drilling service Ltd.

1.1.4 Additional directional planning recommendations for the well.

1.) Low build up rates result in lower contact forces, i.e. reduced casing wear. Longer measure depth however may result in similar total drag and torque ascompared to higher build up rates. Therefore torque and drag simulations should be conducted to confirm lower build rates are most preferred.

2.) Lower tortuosity is achievable with lower build up rates.3.) Torque and drag should be considered for top and bottom of each hole interval as a minimum requirement using realistic friction factors for maximum

weight on bit required (roller cone and PDC bits.) in both sliding and rotary drilling modes.4.) Trajectory design will finally depend on realistic drilling assembly responses. In that it is felt that all required can be met with BHA’s selected and wellbore

profile warranted.5.) Wellbore design should comply with both proposed and contingency casing points. In that again profile A meets requirements well.6.) If formation walk tendencies are known, consider leading the target azimuth in the tangent section to avoid deeper steering requirements.7.) Avoid planned steering in troublesome formations. Again profile A is best suited for this.8.) To minimise steering, the trajectory in each hole section should be designed to be compatible with the rotary mode directional behaviour of the BHA,9.) Build section of well should be designed around the rotary build performance of the steerable assembly.10.) Tangent section should accommodate the walk characteristics of the assembly and bit combination.11.) Steerable assemblies should be designed so that build can be achieved with 70-80% rotation. This affords better quality hole, smoother wellbore profile,

(less torque and drag) hole cleaning efficiency and overall better drilling/tripping performance and generally speaking, less hole problems.

BHA’s1.) Configure BHA’s to be as short and light as possible. Minimise non magnetic equipment, without sacrificing survey accuracy.2.) Maximise rotary mode drilling and minimise sliding in build and tangent sections. (bit choice can influence this significantly.)3.) Steerable drilling assemblies in 12 ¼” and 8 ½” sections allow 3D course corrections.4.) Select bent housing on motors to produce adequate dog leg severity (DLS) without minimising housing fatigue in rotary mode. A good compromise for

this well would be 0.75degree.5.) Consider PDM rotor/stator interface to maximising life.6.) Use variable gauge stabiliser to control rotary mode directional tendencies and improve hole cleaning.7.) Optimise flow rates for PDM, MWD and bits while meeting bit/bottom hole cleaning and hole cleaning needs.8.) Optimise jarring system and placements. Get jar manufacturer to run optimisation programme and advise for BHA’s proposed.9.) Run smallest amount of stabiliser commensurate with directional stability to ensure optimal performance while sliding.10.) If a BHA does not perform in directional mode do not hesitate to trip it as this could lead to a poor hole quality and unnecessary high torque and drags.11.) Change bit designs incrementally and ensure they are compatible with BHA.12.) Treat the bit as an integral part of the assembly.13.) Ensure drillstring design accommodates WOB for all types of bit to prevent buckling of the drillstring.14.) Consider sag of collars BHA design and vibration on MWD/lWD tools. Stabilise these sections if possible. Run downhole vibration tool to monitor tool

vibrations that can aid greatly in maximising tool, bit and drillstring component life and overall performance.

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Geological Evaluation & Summaries

1.2 Structural Setting and PrognosisTWFH structural settings and prognosis has been described in the lithological column anddirectional drilling considerations in the introductions of this document. A summary withuncertainties are provided below. Formation Depth Uncertainty Principal lithologyGroup/Stage (mbdf) (+/- m)Seabed 200 2 Silty clays with sand grains

Nordland Gp 600 20 Sandy to silty clays Hordaland Gp. 800 30 Limestones, chalks fractured.Towards base

Tertiary 1100 40 Halite

Top Shetland 1400 40 Claystones

Lower Shetland 1600 40 Silty claystone

Upper cretaceous 1900 50 Claystones

Reservoir 2100 100 Sandstone with stringers of silt and cClaystone

Lower Cretaceous 2200 120 Claystones

1.2.1 Objective ReservoirThe well is drilled to test the hydrocarbon potential of the Middle Cretaceous formation in theABC prospect at 1900-2100m TVD. The reservoir is interpreted as a 200 metres thick shallowmarine sandstone of cretaceous age. This formation has been penetrated in several wells inthe ABC platform area. The reservoir is expected to be in fluid communication withsandstones below the Hydrocarbon Water Contact.

1.2.2 Pore Pressure PredictionBased on existing wells and data from Platform, the Middle cretaceous reservoir section isexpected to be hydrostatically pressured. However, slight overpressures are likely to occur inthe basal Tertiary section and throughout the Upper Cretaceous section, mainly due to undercompaction of shales during burial. The overpressures are then expected to drop off tohydrostatic pressure in the shales immediately above the top of the reservoir.

Based on the current information, the expected reservoir pressure at 1900 mbdf is estimatedto be approximately 2,800psi or 192 bar (based on tentative HC-water contact)

1.2.3 Formation IntegrityPore fracture gradient enclosure, displays leak off pressure measurements performed inoffset wells. For leak-off tests the local gradient can be used.

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1.2.4 Temperature GradientGeothermal gradients were calculated for other wells based on corrected bottom holetemperature data from logs and production tests. This gave a range for the gradient of 3.5-4.0degC/100m based on a seafloor temperature of 4degC. Using these data and the prognosisdepths, the temperature at top reservoir level formation is estimated to be 59 +/- 4 degC(1900 mbdf). The temperature at TD is estimated to be 79degC.

1.2.5 Formation EvaluationThe formation evaluation requirements will depend upon 1) whether hydrocarbons are foundand 2) what type and quantity of hydrocarbons are found.

Regardless of the other evaluation requirements, an experienced well site geologist will be onsite during the drilling of the cretaceous section and to witness the wire-line logging and otherpossible data acquisition at TD.

1.2.6 Ditch Cutting SamplesCuttings sample are to be taken at 10 metre intervals over the Tertiary section, from 9 5/8”casing shoe at 3240 mbdf. If penetration rate allows this.Thereafter, samples should be taken every 3 meters down to TD.

The following bags of samples are required at each depth:1) 3 large bags (1 to 1.5 kg each) of wet cuttings2) 1 large bag (1 to 1.5 kg each) of wet cuttings for biostratigraphy3) 1 small bag of (100 grams each) of dry cuttings for lithostratigraphy

Final confirmation of the number of bags of cuttings required and details on sample handlingprocedures will be advised (pending partner requirements).

A geological, engineering monitoring and data analysis service will be used to provideconstant monitoring and recording of all drilling parameters.

Data transmittal of the following data will be advised:

Depth - ROP - WOB - C1-C2-C3-C4 - Total Gas - Lithology percentages

Details on format, frequency and transmission requirements of reports and ASCII data will beadvised.

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© Kingdom drilling service Ltd.

1.2.7 MWD / Wire-line LoggingMWD logs are to be run in this well from the 20”ccasing onwards for directional surveyingpurposes. As a PWD sub is being run CDR (gamma ray and resistivity will also be obtained.)The wire-line logging programme is dependent on well results and has been defined asfollows:

Dry Well1) PEX + DSI2) VSP (standard)3) CST

Oil Discovery1) PEX + DSI2) MDT (samples + pressures)3) VSP (standard)4) CSTIf Net oil pay more then 15 meters AND reservoir connectivity and/or permeability is perceivedto be a problem, then prepare for “bypass” coring.

Gas Discovery1) PEX + DSI2) MDT (sample + pressures)3) VSP (standard)4) CST

The PEX (Platform Express) logs are: GPIT – HNGS – HALS – TLD – MCFL

(Inclination – gamma ray/neutron – high-resolution azimuthal laterolog – density –microcylindrically focussed log).

DSI – dipole shear sonic imaging tool for both shear and compressional sonic data.

FMI – formation micro-imaging tool provides a high-resolution resistivity image of the reservoirfor determining dip angles, presence of faults/fractures and improved sedimentologicalunderstanding.

MDT – modular formation dynamics tester for measuring formation pressure and obtainingfluid samples.

VSP – vertical seismic profiler.

CST – core sample taker.

Logs to be recorded from TD to 100m above top reservoir.Down logs, run at 5-6000 ft/hr, should be recorded when running in the hole.

VSP to be recorded at 15m intervals from TD to the casing shoe and then every 100m tosurface (programme to be advised by EPXO/1 and EPXG/25).

Details on format, quantity and transmittal procedure of wire-line data and handling ofsamples will be advised (pending partner requirements).

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© Kingdom drilling service Ltd.

1.3 Mud programme

Hole Size Mud Type Mud Weight Remarks

36” & 26” Sea water + Hi-vispills

1.03 sg Displace to 1.2 sg. Hi-visc spud mudbefore POOH.

17 ½” Na/Cl polymer(saturated)

1.20 – 1.45sg Pump fresh water pill if stuck in halite

12 ¼” Na/Cl polymer

(saturated)

1.20 – 1.25sg Mud weight based on offset wells,maximum expected to enable

stabilisation in over-pressured shalesfrom 1300-1500.

8-1/2” Na/Cl flo-proNon damaging, high

low shear, no saturated

1.10 – 1.15sg Reservoir section hydrostaticallypressured, FL < 4 to reduce differential

sticking risk.

6” contingency As above 1.10 – 1.15sg As above

A more detailed mud programme with operational guidelines prepared by mud company.

1.4 Casing SchemeThe figure on the following page presents the casing scheme for well TWFH-13. This designis based on the following assumptions:

1. The target depth of the well is 2000 mbdf (TVD);2. Hole size at TD will be 8-1/2”3. A production test is planned.4. The well is for information purposes and will be abandoned after evaluation;

The casing design has minimal uncertainty due to a large amount of offset data in the neararea, however it does include one contingency casing string (5 ½” liner)

30" @ 330 m Conductor

Iinter casing13 3/8" @ 1450m AHD 1380m TVD

RKB30m Wellhead

200m Mud Line

8.1/2" TD 4250m AHD2000m TVD.

20" @ 850m TVD Surface casing

Production casing9 5/8" @ 3242m AHD 1900m TVD

Well total depth

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© Kingdom drilling service Ltd.

1.4.1 Casing Setting Depth Criteria

1.4.1.1 30” Conductor Setting Depth

From offset data and confirmed with data from the site survey an optimum conductor length of7 joints has been designed to:

Ø Isolate unconsolidated and glacial drift formations

Ø Supports tie back from seabed to platform.

Ø Strong enough to handle a gas kick if for any reason 20” had to be tied back to platformand a diverter system used.

Boulders and marine-glacio sediments are prognosed from 250m to 300m below seabed,these can contain small boulders and pebble beds that have caused operational problems ifleft exposed for the next section. The stiff and rigid assembly as described in precedingsection has been shown to drill section at maximum ROP’s, using low RPM’s and light weightthrough hazard zones. ( Lessons learned, Conoco Heidrun platform.)

Note: Based on time, cost and quality of the hole, a mud motor, and the high peripheralspeeds exposed to soft formation, roller bearing cutters, lack of rotational control etc does notwarrant a motor based on such technicalities.

With a water depth of 200 m and an air gap of 50 m, the setting depth for the conductor willbe approximately 330 m (80 m below seabed +1-2 m stick-up).

1.4.1.2 26” Casing Setting Depth

The setting depth for the 26” casing is based on getting past and isolating the soft stickyformations and the fractured limestone where hydrostatic losses may occur.

Ø Isolate exposed formations

Ø Set deep enough so formation integrity can handle gas kick at potential 17 ½” section TD

Ø Support wellhead, blow-out preventer and subsequent casing strings.

Ø Afford a adequate hole size for kicking off directional assembly

Setting the casing shoe in the halite will provide adequate shoe strength to drill the nextsection base on pore and fracture pressures prognosed in the halite and over-pressuredshales. From offset wells it has been concluded that drilling 30-50m into the halite provides agood seat to be able to readily drill the next section within the kick tolerances required.Therefore casing shoe is planned at +/- 850m TVD.

Finally kick tolerances have confirmed casing setting depth based on the unliklihood of drillinginto potential secondary reservoir and taking a kick at circa. 1380m.

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1.4.1.3 13 3/8” Casing Setting Depth

The 13 3/8” casing shoe depth has been set prior to drilling into the secondary reservoir. As ifin the likely event that this proved commercial. Well design must be able to accommodate asecondary production string. I.e. side-track, multilateral at this point. If no reservoir wasestablished intermediate log and option to drill to next Td could be evaluated and decidedupon.

Ø Isolate all formation of the surface casing so next hole section can be drilled safely andefficiently through potential secondary pay zone.

Ø Requirement to set this string prior to drilling into main reservoir, with requirement toisolate reactive claystones.

Ø Provide sufficient wellbore integrity to drill into main reservoir.

Ø Fulfill production casing requirements. I.e. if a production string has to be run below the13 3/8” shoe to complete the secondary reservoir.

Gradual shale overpressures are expected to start from around 1000 m, no permeableformations have been prognosed between 800 and 1300 meters.

Secondary reservoir is potentially at 1400m +/- 30m. If reservoir is penetrated, casing will beset 50m above. ( Contingent measure for side-tracking into reservoir at a future date.)

Therefore casing shoe is planned at 1380m TVD, estimate leak off expected at 1.50sg(estimate from fracture/pore pressure data.)

1.4.1.4 9 5/8” Casing Setting DepthThe 9 5/8” casing shoe is to be set above top reservoir +/- 3242m AHD, 1900m TVD,toprimarily to isolate the long open hole section so formations mud weight can be reduced andchanged to a non damaging mud prior to drilling into the reservoir. The objective of this is toensure maximum wellbore performance and productivity.

The 75degree inclination is so that 7” production liner and completion can be safely runwithout buckling or damaging the production string components.

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1.4.2 Cement programme

1.4.2.1 30” ConductorThe 30” conductor will be cemented back to seabed with a 1.90 sg conventional acceleratedslurry. A 200% excess over the open hole volume will be used. 15 m³ freshwater spacer willbe used to separate the cement from the viscous mud remaining in the hole.

The 30” conductor will be cemented using a stinger, the tail of which should be 10 m abovethe Shoe and the cement displaced to within 5 m of the shoe.

The thickening time is designed for 3-4 hrs.

If no returns observed by ROV during cement job at seabed. A top up cementation will berequired.

1.4.2.2 26" Surface CasingThe 20” casing will be cemented to surface with a 1.56 sg Lead and 150m 1.9 sg Tail cementslurry. No prognosed hydrocarbon bearing zones are indicated from previous wells so there isno need to make the cement can be made gas

Top plug only used.

A 75 % excess over open hole volume is proposed.

The thickening time is designed for 5 hrs.

If no returns observed by ROV during cement job at seabed. A top up cementation will berequired.

1.4.2.3 13 3/8" Intermediate CasingThe 13 3/8” casing will be cemented to 150m above the 20” casing shoe with a 1.56 sg Leadand 150m 1.9 sg Tail cement slurry. No prognosed hydrocarbon bearing zones are indicatedfrom previous wells so there is no need to make the cement can be made gas

A 10 % excess over open hole volume is proposed.

Top and bottom plug system will be used. 50bbl spacer pre-flush will be pumped.

Plugs bumped and casing tested to 2500psi.

The thickening time is designed for 5 hrs.

1.4.2.4 9 5/8" Intermediate CasingThe 9 5/8” ” casing will be cemented to 150m below the 13 3/8” casing shoe ( to allowsidetrack and or multilateral liner to as required. A 1.56 sg Lead and 150m 1.9 sg Tail cementslurry. Hydrocarbon bearing zones are indicated from previous wells, therefore the cementshould be made gas tight. A 10 % excess over caliper open hole volume is proposed. Thethickening time is designed for 5 hrs.

1.4.2.5 7" Production Liner (Contingency)The 7” liner will be cemented with the same slurry type as the 9 5/8” casing.The 7” liner will be cemented using the Nodeco liner hanger running equipment. Aprogramme amendment will be issued if the 7” Liner option is required.

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1.4.3 Borehole Surveying and Logging while Drilling Programme

Hole/Casing Size Survey & LoggingInstrument type

Survey Frequency Note

36” hole Anderdrift Every single or morefrequent if boulders areencountered

Contingency: Have MSS kit onboard forback-up contingency, Include NMDC inBHA

26” hole opener Anderdrift Check Inclination. Verify with MSS if it is suspected that akick-off has occurred.

17 ½ ” hole MWD/PWD+ (CDR)

Directional surveysevery stand, reducingthe frequency asapplicable.

Contingency: Multishot at TD or on tripsinclude NMDC/totco ring.

Continuous PWD

12-1/4” hole Gyro In 13 3/8”casing.

MWD/PWD+ (CDR)

Directional surveysevery stand, reducingthe frequency asapplicable.

Contingency: Multishot at TD or on tripsinclude NMDC/totco ring.

Continuous PWD

8-1/2” hole MWD/PWD+ (CDR)

Directional surveysevery stand, reducingthe frequency asapplicable.Continuous PWD

Contingency: Multishot at TD or on tripsInclude NMDC/totco ring.

Continuous PWD

Main justification for using MWD/CDR is for the use of the Pressure Measurement whileDrilling sub (PWD).

All MWD directional data to be corrected with company requirements. The CDR toolsmentioned above consist of a GR and Resistivity and are not a requirement but a ‘bonus’ fromusing the PWD.

Gyro to tie in for accuracy prior to drilling into potential reservoir targets.

MWD IHR shots to be taken on every trip in hole to ensure accuracy of data.

Gyro may be run in 9 5/8” casing if inaccuracies felt to exist.

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1.4.4 OPERATIONAL hazards

1.4.4.1 Shallow GasShallow gas investigation on 3D seismic was performed in August 1998. Results indicated noshallow gas accumulations at the proposed well locations.

The 3D evaluation was used to optimise the 2D site survey which confirmed the risk ofencountering shallow gas at the well location to be negligible.

1.4.4.2 Boulders, glacial driftBoulders have been encountered in offset wells, down to 68 m sub seabed. (Contingencyconductor will be onboard in the event that boulders are encountered, giving the option to setthe conductor deeper with the aim of covering the trouble zone.

Precautions should be made as per hole section guidelines.

1.4.4.3 Halite.Readily dealt with by pumping a 50-100bl freshwater pill immediately tight hole or pipesticking occurs. Ensure sufficient drill water is on board and that chlorides are measured toensure full effectiveness of pumping a freshwater pill if required.

1.4.4.4 Reactive Shale'sShale's can be time dependant and rely on ensuring wellbore is maintained at optimal in situstress conditions. Mud weight selection and rheology is therefore critical.

Drilling and tripping guideline’s should be applied as described in stuck pipe preventionsection of this document.

1.4.4.5 LossesAlthough losses may be experienced in the limestone fractures in the 26” section. This shouldnot prove to be a problem as the section is drilled riserless.

If cement return are not observed during 20” casing job a top up cementation may be requiredto ensure well integrity.

1.4.5 H2SNo H2S has been recorded in the offset wells, and thus it is not expected to occur in this well.

1.4.5.1 Over PressuresOver pressured shales are expected from around 1000 m to 1400 m. Pressure increasegradual to an expected maximum range from 1.05- 1.15sg EMW at Apr. 1400 m.Pressures estimated on offset wells based on drilling data, range between hydrostatic and1.15sg.

The reservoir section is expected to be hydrostatically pressured 1.03sg.

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1.5 Health, safety and environment

1.5.1 HSE Programme/ScheduleA programme for regular HSE visits and inspections will be established. A projectplan/schedule is established for this well to cover the planning and execution of the variousHSE activities.

1.5.2 Risk Assessment and AnalysisFollowing the internal screening of potential hazard using ABC and Production developed riskanalysis programme; specific risk analysis meetings/work shops have been conducted. Theresult from the risk analysis will be communicated to personnel on the rig.

1.5.3 EnvironmentAn environmental risk analysis, including drilling activities was carried out for the ABC field in1994. The oil drift analysis for ABC oil is also applicable to the well. The oil spill contingencypreparedness already established for ABC will be adequate for the well.

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1.6 Wellbore stability.

1.6.1 Well bore objectives for sections.

• Select a non interactive mud• Determine min/max weight to combat hoop stresses on the wellbore wall to avoid lost

circulation.• Assess problems associated with high inclinations in the 12 ¼” hole.• Assess problems associated with high inclinations in the 8 ½” production section.• Rank various well profile options with respect to risk associated with hole instability.

1.6.2 Results.Analysis suggests that suitable mud weights can be selected for all wellbore profiles.

Option A is considered the most favourable with respect to wellbore stability.

a.) Provides the profile to drill aggressively through the halite and fractured sections in avertical direction to ensure troubles are minimised and sections are cased off as quickly aspossible.

b.) Lower deviation profile throughout the reactive claystone sections (i.e. the most criticalsections with respect to instability.) would provide most effective & minimal risks option that ineffect if unsuccessful, could result in an unscheduled setting of the 13 3/8” casing..

If unfavourable hole conditions did exist in the 17 ½” hole, and early setting on the otherprofiles occurred, it would then be much more difficult to reach the 12 ¼” hole TD withoutsuffering further hole difficulties, stuck pipe, possible wellbore collapse and more importantlythe reservoir section could not be drilled and completed with the preferred completion design.

c.) Setting casing shoe above potential secondary and main reservoir is also seen aspreferntial should both section sbe produced. In that especially for main reservoir mud weightand properties can be best selected to afford maximum wellbore productivity and minimalwellbore damage.

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1.7 Directional control and surveying

Profile A.

From data attached is can be seen that a kick off depth to achieve the desired wellbore profilewas 689.24m.

If angle could be built by the 20” shoe therefore simply by running a slight building assemblythis would make things ideal.

In reality however what would have to be conducted is that slight higher doglegs wouldhave to be achieved and a slightly higher tangent angle to meet wellbore objectives.

i.e. a sufficiently low inclination to ensure production liner and completion can be run withoutdifficulties (buckling etc.) and that logging & wireline tools could be run without difficulties.

Assuming sufficient angle was obtained by 880m (200ft below the 20” shoe.) it can be seenthat well could be built at 2degrees+ per 30m to a inclination of 74.5 degrees at a along holedepth of 1818m (TVD 1519m)

Tangent section could then be held at 74.5 until reservoir penetrated at 1900m TVD 3242mAHD.

Inclination at 13 3/8” casing shoe would be approximately 50degrees and this should notpresent to much overall difficulties with regards to hole cleaning, running casing etc.

A final projection was then established to the preferred target and dogleg (4deg/30m)requirements.

After a small build from 3243 – 3319m AHD, inclination would be met and a further tangentheld of 84.675degrees until well total depth requirements at 4248m AHD, i.e. 2000m TVD.

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1.7.1 Surveying and MWD

The following surveying programme will be adopted in each well section.

Anti-collision is not seen as a problem.

Accuracy prior to drilling into potential secondary reservoir and main reservoir is seen as thecritical issues for surveying requirements. ( e.g. to ensure accuracy should a relief well needto be drilled.)

Hole/Casing Size Survey & LoggingInstrument type

Survey Frequency Note

36” hole Anderdrift Every single or morefrequent if boulders areencountered

Contingency: Have MSS kit onboard forback-up contingency, Include NMDC inBHA

26” hole opener Anderdrift Check Inclination. Verify with MSS if it is suspected that akick-off has occurred.

17 ½ ” hole MWD/PWD+ (CDR)

Directional surveysevery stand, reducingthe frequency asapplicable.

Contingency: Multishot at TD or on tripsinclude NMDC/totco ring.

Continuous PWD

12-1/4” hole Gyro In 13 3/8”casing.

MWD/PWD+ (CDR)

Directional surveysevery stand, reducingthe frequency asapplicable.

Contingency: Multishot at TD or on tripsinclude NMDC/totco ring.

Continuous PWD

8-1/2” hole MWD/PWD+ (CDR)

Directional surveysevery stand, reducingthe frequency asapplicable.Continuous PWD

Contingency: Multishot at TD or on tripsInclude NMDC/totco ring.

Continuous PWD

Main justification for using MWD/CDR is for the use of the Pressure Measurement whileDrilling sub (PWD).

All MWD directional data to be corrected with company requirements. The CDR toolsmentioned above consist of a GR and Resistivity and are not a requirement but a ‘bonus’ fromusing the PWD.

Gyro to tie in for accuracy prior to drilling into potential reservoir targets.

MWD IHR shots to be taken on every trip in hole to ensure accuracy of data.

Gyro may be run in 9 5/8” casing if inaccuracies felt to exist.

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1.8 Drillstring & BHA design considerations.

1.8.1 General design requirements

1. Design BHA on a run what is needed to meet the wellbore objectives.

2. Design BHA’s to prevent axial buckling of the drilling assembly for drilling loads imposed.

3. Design to stay within a vertical cylinder, radius of 50m centred at the target locations.

4. With above statements in mind, BHA Philosophy will be to run a 18m pendulumassemblies to the 20” casing shoe. Then afford stability and more durability to the Insertbit or PDC Motor assemblies for the 17 ½”, 12 ¼” and 8 ½” section. The object would beto achieving maximum performance, drilling the section(s) in one run. Pulling and/orpumping out of the hole and running casing and/or logging without difficulties.

5. All stabilisers shall be gauged prior to use and on trips. Undergauge stabilisers shall bechanged out except when required for directional purposes. When utilising undergaugestabilisers, ensure sufficient carbide dressing thickness remains on the stabiliser to protectthe stabiliser from excessive wear.

6. The dimensions of any item run in the BHA are to be recorded (including lengths, ID's, OD'sand fishing necks). These details are to be recorded on BHA sheets which shall be made upin a timely manner. The master sheet shall be kept on the drill floor and copies distributed toDrilling Supervisor, Rig Toolpusher, Mud Engineer and Mud Loggers. In addition, a diagramshall be made of any tools which do not have a constant OD or ID. These diagrams shall bekept on the drill floor.

7. All BHA components should have a bore back box, stress relief pin and cold rolled threads.

8. Incompatible ID’s and OD’s of mating components, should not be run as they present anarea of high stress concentration that are more likely to incur fatigue failure.

9. Subs with lengths less than twice the hole diameter shall not be run in the BHA.

10. The Drilling Contractor and service companies shall maintain records of equipment usage,inspection and maintenance on the rig e.g. drill collar rotating hours, jar rotating hours,downhole motor circulating hours.

11. The number of drill collars in the BHA will be determined by the W.O.B. utilised on offsetwells, maximum W.O.B. rating for bit type and anticipated mud weight. The minimumnumber of collars shall be run at all times.

12. Drilling jars and crossovers shall not be run in the neutral position.

13. ID's in the BHA shall be larger than the OD of any tools that may be required to passthrough that part of the BHA.

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1.8.2 BHA Guidelines

1. To prevent the stabilisers hanging up, all stabilisers should be well tapered both top andbottom.

2. 9½" drill collars should will be used in 17½" hole sizes and larger.

3. Check trips will only be made if required between or after logging runs.Assembles will be kept as simple as possible.

4. The soft torque device will be set up and utilised in the 12 ¼” & 8 ½” sections.

5. All MWD deviation data will be quality checked using approved software.

6. 8” & 6 ½” jars will be run in the (17 ½”, 12 ¼”) & 8 ½” assembly.

7. All BHA connections should be cleaned, inspected and re-doped prior to making up.

8. Dog collars will be utilised until sufficient BHA weight is present.

1.8.3 Drilling parameters used for designBased on performance on the offset ABC wells, the following operating ranges are seen asbest suited to achieve optimal, durable and desired performance.

Bit size Type WOB RPM ROP Hyd TFA

26”/36” 26” Bit36”h/opener

10/20 40/60** Controlled <30m/hr

250ft/sec Balancedfor flow

26” Rock bit 10/30 80/120 10 - 60 m/hr >350ft/sec 0.8 – 1.0

17 ½” Insert bit 10/30 Motor 10 – 50 m/hr 3 – 4HHP/ins2

0.7 – 0.9

12 ¼” Insert bit orPDC

10-30K Motor 40 – 60 m/hr 4 – 6HHP/ins2

0.9 – 1.2

8 ½” PDC 5-25K Motor 20 – 40 m/hr 6 – 10HHP/ins2

0.4 – 0.6

Note: BHA’s in following sections are thus designed to accommodate such premise.

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1.8.4 Tubular handling procedures

1. All tools must be transported with protectors fitted.

2. When laying out tools all appropriate connections should be sufficiently broken.

3. A different service break should be whenever practically possible.

4. All connections should be visually inspected prior to make up.

5. All tubular’s should be clean, drifted and inspected prior to being picked up.

6. Ensure correct make torque are utilised at all times.

7. All new connections must be soft, half and fully made up and broken out as required.

8. Ezy torque should be used when required on high torque connections.

9. All tongs, elevators, slips, bails, slings, etc should be inspected maintained and in fullworking order prior to use.

10. Different drill string grades or range should be tallied in a separate tally book.

11. Total drill pipe on board, in the derrick, and in the hole must be checked daily andrecorded in Driller’s handover.

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1.8.5 36" Section assembly design.

A 26" bit, short drill collar and 26”/ 36” bit/hole opening assembly will be used to drill the tophole section in one run.

A re-run milled tooth bit with an IADC code of 1-1-5 or 1-1-7 c/w centre nozzle should proveeffective.

Parameters will be governed initially on the need to keep the hole straight, thereafter toachieve maximum drilling performance without compromising wellbore condition.

If the assembly begins to exhibits rough drilling, indicating drillstring vibration, possible(glacial drift, boulders, cobble beds, etc.) efforts should be made to drill past the obstacle byvarying weight on bit & rotary speeds to find best suited conditions.

Section hydraulics requirements, see results enclosed

1.8.5.1 Top hole drilling assemblyHOLE SIZE ASSEMBLY COMMENTS

36” HOLE 26" Bit Re-Run. Centre jet. Jetted forasymmetric flow

Short 2m DC ( inverted)26" Hole Opener36" Hole Opener Float valve

9. ½” inclinometer Totco in top box

1 short 4m 11” DC36” spiralled stabiliser1 x 9 ½” NMDC1 x 9 ½” DC’s

Totco Ring X/over3 x 8" DCX/over6 X HWDP

1. The BHA will contain 26" and 36" heavy duty hole openers. (suitable dressed with 12 x12/32nds nozzles.)

2. The BHA is designed to be as simple as possible.3. An inclinometer will be run for inclination checks.4. No jar is planned for this assembly.5. A float valve is to be installed in the string.6. Tandem single shot survey will be dropped at section TD and retrieved at the BHA on trip

out of the hole.

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1.8.6 26” Surface hole

1. A 26” pendulum drilling assembly will be used to drill out the shoe track.

2. The hole will be swept clean and a 50bbl hi-viscous pill spotted on bottom to allow the rat-hole to “cake up”.

3. A leak off test will be taken at the 20” shoe to establish kick tolerance to drill the nextsection.

4. The section will be drilled at optimal ROP’s.

5. Inclination build is not seen as a concern as it can be readily corrected in the next section.

1.8.6.1 26” drilling assembly

HOLE SIZE ASSEMBLY COMMENTS

26” clean out 26" Bit Re-run

9 ½” inclinometer Box/box bored out for float.

1 x 9 ½” NMDC Totco in inclinometer top box.

1 x 9 ½ DC.s

26” stab

1 x 9 ½” DC’s

26” stab

1 x 9 ½” DC’s

X/over

3 x 8” DC’s

6 5/8” reg pin, 4 ½” IF Box.

12 X HWDP

1. The BHA is designed to be as simple as possible.2. No jar is planned for this assembly.3. A float valve is to be installed in the string.4. A Multishot survey will be dropped at section TD and retrieved at the BHA on trip out of

the hole.

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1.8.7 17 ½” intermediate hole section

1. It is intended to drill the 17 ½” intermediate hole in one run, with a potential directional runlength of approx. 600m.

2. With soft clays, a insert bit aggressive jetted will quickly drill the clays, provide ease ofdirectional control to achieved 2 degree doglegs, and withstand occasional stringers thatmay be apparent.

3. As bit/BHA balling is seen as a primary concern proper drilling hydraulics to the bit andthe bottom of the hole must be afforded. Section attached.

4. To keep the well to required directional control, a motor/MWD assembly is planned. Lightweights and high RPM’s will be used. Initial indications are that 2 stands per hour arepossible. ROP's should be in the 60 m/hr range.

5. The assembly will contain 2 additional string stabilisers, tot ensure hole is reamed andbest wellbore geometry is obtained.

6. Ensure 2 x backup string stabilisers are on site.

7. If the hole angle shows signs of excess building, control may be exercised by reamingsection and changing drilling parameters.

8. If increasing resistance is experienced during tripping out (that cannot be wiped free.) theassembly will be pumped out of the hole monitoring drag and pump pressure, circulatingas required.

9. A decision to wiper trip back to bottom will be made at this stage.

10. A PWD/CDR configuration will be run to monitor ECD’s in this section for well control andhole cleaning purposes.

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1.8.7.1 17 ½” drilling assembly.

HOLE SIZE ASSEMBLY COMMENTS17 ½ "Intermediate hole

17 ½ ” Bit Motor Insert bit, 4-1-5 or 4-3-5,centrejet, mini extended nozzles

11 ¼” Motor (fitted with 17 1/8” stab) 0.75deg.

CDR PWD

MWD Totco

1 x 8” NMDC

1 x 17 1/8” SS

1 x 8” DC’s

1 x 17 1/8” SS

3 x 8” DC

Jar

2 x DC

Accelerator

2 x DC

X/over

12 x HWDP

1. The BHA will contain a new 17 ½” bit.2. The BHA is designed to be as simple as possible.3. Jar & accelerator is planned for this assembly.4. No float valve is to be installed in the string.5. If MWD fails, a multishot survey will be dropped at section TD and retrieved at the BHA

on trip out of the hole.

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12 ¼” drilling assembly.

HOLE SIZE ASSEMBLY COMMENTS12 ¼ "Intermediate hole

12 ¼” Bit Motor Insert bit, 4-3-5, 5-1-7, or 6bladed 16mm-13mm PDC, (centrejet, mini extended nozzles on insert)

9 ½ ” Motor (fitted with 12 1/8” stab)

CDR PWD

MWD

1 x 8” NMDC TOTCO

1 x 12 1/8” SS

1 x 8” DC’s

1 x 12 1/8” SS

2 x 8” DC

Jar

2 x DC

Accelerator

1 x DC

X/over

9 x HWDP Less BHA required due to >inclination.

1. The BHA will contain a new 12 ¼” bit (nozzles sizes see section 7.6).2. The BHA is designed to be as simple as possible.3. One 8” drill collar and 2 x 9 ½” drill collars will be racked back and the hole opener

assembly laid out during trip out.4. No jar is planned for this assembly.5. A float valve is to be installed in the string6. If MWD fails, a multishot survey will be dropped at section TD and retrieved at the BHA

on trip out of the hole

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1.8.8 8 ½” section

1. Drilling assembly will drill out the shoe track, clean rat-hole and drill 5 m of new formation.

2. A LOT will be performed.

3. Section will be drilled to section TD at optimised drilling parameters without compromisingthe (to be logged) condition of the hole.

4. A PWD/CDR configuration will be run to monitor ECD’s in this section for well control andhole cleaning purposes.

5. Bit and bottom hole cleaning is seen as a primary concern to optimising drilling efficiency.

6. A motor assembly and PDC bit will be run. Light weights and high RPM’s are anticipatedthat with BHA design should maintain the at high inclinations required. Initial indicationsare that 20-40 m/hr are possible. ROP's from offset averaged > 25 m/hr range.

7. The assembly will contain 3 string stabilisers.

8. Ensure a backup set of string stabilisers are on site.

9. If the hole angle shows signs of building, control may be exercised by reaming sectionand changing drilling parameters.

10. If increasing resistance is experienced during tripping out (that cannot be wiped free.) theassembly will be pumped out of the hole monitoring drag and pump pressure, circulatingas required.

11. A decision to wiper trip back to bottom will be made at this stage.

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1.8.8.1 8 ½” Directional drilling (geo-steering) assy

HOLE SIZE ASSEMBLY COMMENTS8 ½" HOLE PDC BIT

8 ½” near bit stabiliser

6 ½” Anderdrift

8 ½” stabiliser

CDR (GR/Res) PWD sub. (Totco in top box )

MWD/LWD Formation evaluation and geo-steering

1 x 6 ½” NMDC

8 ½” Steel Stab

1 x 6 ½” DC

8 ½” Steel Stab

4 x 6 ½” DC’s Fine tune for weight required

Jar 8”

2 x 6 ½” DC’s

Accelerator

2 x 6 ½” DC’s

1 X HWDP

Dart Sub

9 HWDP

1. The BHA will contain a new PDC bit2. The BHA is designed to be as simple as possible.3. Jar and accelerator is planned for this assembly4. If MWD fails, a multishot survey will be dropped at section TD and retrieved at the BHA

on trip out of the hole

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1.9 Hole cleaning hydraulics.

1.9.1 Summary

An evaluation of hole cleaning and hydraulics was made using BP’s drilling engineering toolkitand its hydraulics application.

The results show that 5” drillpipe can be used with sufficient flow obtained to clean allsections. Each hole sections were modelled for mud properties, hole inclination, anticipatedROP’s, BHA design.

A generalised bingham ( modified Herschel Buckly, model was selected from calculations runas it was calculated to be the best model to suit hole and mud conditions.)

Due to extensive field experience with this model, results were deemed satisfactory and theonly undue considerations that could not be accounted for was hole enlargement & instabilitydifficulties that would change a hole cleaning equation some what.

In that proper and correct drilling practices would in reality be exercised to ensure that holequality and prevention of washout and enlargement could be adequately managed at the rig-site through instituting proper drilling practices.

1.9.2 Section summary

Bit size Type Flow atsection TD

Hyd TFA

26”/36” 26” Bit36”h/opener

1200GPM 250ft/sec 1.4 – 1.8

26” Rock bit 1100GPM >350ft/sec 0.8 – 1.0

17 ½” Insert bit 950GPM 3 – 4 HHP/ins2 0.7 – 0.9

12 ¼” Insert bit orPDC

790GPM 4 – 6 HHP/ins2 0.9 – 1.2

8 ½” PDC 550 – 650GPM 6 – 10 HHP/ins2 0.4 – 0.6

Notes:

1.) Top hole and surface hole designed to maximise jet impact force to ensure bit and cuttersand bottom of hole are maintained cleaned. (and use energy available fromteh mudpumps!!!)

2.) 17 ½” bit erring on HHP design again to ensure bit/bottom of hole is kept clean but alsostarting to impact more on the bottom of the hole as formations firm up as sectiondeepens. (mini extended jets recommended to prevent hole washout.)

3.) HHP design applied to ensure sufficient energy is imparted to bit/bottom of the hole tomaintain >ROP’s and keep bit/bottom of hole clean.

4.) Designed for max HHP without compromising required flow rates to clean the hole.

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1.9.3 Top hole

Based on each cutter cuts a specific volume of rock.

1. Flow balance should designed to meet cutters size and amount of formation drilled.

2. Assuming a minimum desired Jet velocity of 250ft/sec required at nozzles for top holedrilling. ( i.e. to optimise cutter and adjacent hole cleaning.)

3. Rig max. rate 1200gpm +

4. The following results

Cutterarea

Volumeremoved /

ft

Flowbalance

TFA

required*Nozzlesrequired.

26” 3.7ft2 626gpm 0.80 sq ins 2 x 18, 1 x 16, 1x CJ nozzle

36” – 26” 3. 38ft2 574gpm 0.735 sq ins 6 x 14/32nds

Total 7.07 ft2 1200gpm 1.54sq ins

*Applying continuity equation where Q=1200gpm, V=250ft/sec.i.e. Q=A.V = A1.V1 + A2.V2

5. The 26” bit generally allows a balanced 50/50 split of formation cutting between bit andhole opener, better flow balance, better sized nozzles in bit.

6. Finally, to ensure adequate top hole cleaning, cutters and hole must be swept oftenenough with a sufficient sized sweep (60-80bbls/10m).

Note: when considering that 1m of 36” hole = +/- 2500lbs & 10m = 25,0000lbs of cuttings, Andthat transport ratio of seawater in top hole = +/- 25%.

7. Concluding a sweep should be displaced every 10m drilled, of 60-80bbls magnitude. I.e.to keep cutters and hole clean, that will ensure light WOB for > ROP and straight hole.

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1.9.4 26” surface hole

1. Clearing drilled cuttings from the bits and hole openers is paramount in large hole sizes tomaintain light WOB and achieve max ROP to stay straight and vertical. In that, flow rateswill be maintained at approx. 1100 gpm.

2. Centre jetted bit and asymmetric flow will be utilised to ensure is evenly balancedbetween cutters to keep them sufficiently clean.

3. Sweeps must be pumped often and of sufficient size (40-60bbls / 10m ) to keep bit andBHA clean.

4. Do not drill ahead with one pump.

1.9.5 17 ½” Intermediate hole

1. Centre jet bits and extended nozzles suitable sized will ensure optimal bit/bottom holecleaning and mitigate against hole washout in prognosed loose unconsolidated (sand/silt)sections.

2. On trips out, if an excess build up of solids on the wellbore while drilling is noted (i.e.increasing drag trend). Pumping out drag and pressures must be closely monitored toensure solids are pumped out faster than pipe is moved and that wellbore integrity ismaintained. Proper application will result in a trouble free trip with casing run andcemented without difficulty or a wiper trip being require.

3. Do not drill ahead with one pump.

1.9.6 12 ¼” production casing

1. Centre jet bits and extended nozzles suitable sized will ensure optimal bit/bottom holecleaning and mitigate against hole washout in prognosed loose unconsolidated (sand/silt)sections.

2. On trips out, if an excess build up of solids on the wellbore while drilling is noted (i.e.increasing drag trend). Pumping out drag and pressures must be closely monitored toensure solids are pumped out faster than pipe is moved and that wellbore integrity ismaintained. Proper application will result in a trouble free trip with casing run andcemented without difficulty or a wiper trip being required.

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1.9.7 8 ½” production hole

1. Nozzles will be selected to maximise bit/bottom hole cleaning and ROP within the pumppressures available (3400psi.) Maximum flowrate conditions can be met under theseconditions.

2. On trips out, if an excess build up of solids on the wellbore while drilling is noted (i.e.increasing drag trend). Pumping out drag and pressures must be closely monitored toensure solids are pumped out faster than pipe is moved and that wellbore integrity ismaintained. Proper application will result in a trouble free trip with casing run andcemented without difficulty or a wiper trip being required

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1.10 Kick tolerances

Kick tolerances were determined using BP Explorations toolkit.

Results for the 17 ½”, 12 ¼” and 8 ½” section are attached.Modelled data is provided in the following attached results and summary sheets.

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1.11 Stuck pipe and hole problem prevention

1.11.1 Introduction

There are very few cases of stuck pipe which are impossible to prevent. Many incidentscould be avoided by more careful planning or greater care at the rig site.

Among the many people involved in the drilling operation, the Driller has the key position inpreventing stuck pipe. Thorough planning, good drilling practices and an effective mudsystem can ensure that the hole is in the best possible condition.

However, once a problem exists, the only person who can prevent it resulting in stuck pipe isthe Driller.

At the instant that the formation grabs the pipe or the hole packs off, it is the Driller's reactionwhich is all important.

The Drilling Representative(s) and Toolpusher(s) must be sure that every Driller is aware ofany special problems and what his immediate actions should be.

The greater the Driller's understanding of the problems, the greater the chance that he keepsthe pipe free.

1.11.2 General

Rig Contractor's personnel should understand and be aware of tight hole and stuck pipeprocedures.

The BHA design run in all hole sections must be based on only the required components thatwill give the least risk of getting stuck. E.g. Why have a BHA weighing 80,000lbs whendrilling with a PDC at 10-15,000lbs weight on bit.

Be aware of the amount of open hole time for each section. Any reduction in this will help tocut the chance of stuck pipe.

Mud design is critical in keeping a hole in optimum condition. Careful consideration of themud system and planned mud weight will be rewarded by reduced tight hole.

Although the first priority for a casing design must be to ensure that the well can be drilledsafely, one consideration should be stuck pipe. Without compromising safety, the shoe depthhas therefore been planned to case off troublesome formations.

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1.11.3 Rig Site Precautions

1.11.3.1 Excessive drag

The primary reason for tight hole and/or excessive drags deteriorating to stuck pipe has beendue to IMPROPER PRACTICES, EXCESSIVE OVERPULLS OR SET DOWN weights applied.

Excessive overpulls / set down weights should only be applied if all other reasonable attempts towork the pipe have failed.

In abnormal drag situations, be patient. Time spent conditioning mud and the hole is notwasted time, but is insurance against greater time lost during stuck pipe incidents.

A Driller may be reluctant to break circulation and disturb the slug, but it is far easier to re-slugthe pipe than to free it once stuck. Ensure therefore that the Drillers are aware of what to do ifthe hole becomes tight and of any expected problems.

At the first signs of abnormal drags, the Company Representative and SeniorToolpusher should be informed.

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1.11.3.2 Guidelines.Limit initial applied overpull or set down weight to : Normal drag +/- the BHA weight below theJAR.

If no abnormal drags are observed to release the string from the weight applied, incrementallyincrease the applied weights until abnormal drags are noted.

This establishes the upper limit you can work the drillstring without mechanically sticking thedrillstring. If pipe is stuck while POH, initially work and jar downwards only. If pipe is stuckwhile RIH, initially work and jar upwards only.

Keep the drill string moving as much as possible in open hole.

Circulate sooner than later when tripping, if hole conditions are worsening.

Record all tight spots on trips in/out of the hole.

Have mud loggers provide a simple formation / depth chart for use while tripping. ( use offset data )

Know the position of your BHA components.

Acknowledge increasing hole drags.

Note : The information provided above aids in developing trends, identify what, why and whereyou may get stuck and enable you to apply the correct freeing practices for the stuck pipemechanism at hand. Time spent doing the above will be worth it if a stuck pipe situation shouldoccur, where reaction time will be critical to operational success.

Wash, wipe and/or ream any resistance experienced. Where necessary ream any consistenttight spots a few times. Report if this has no effect. Mud or formation characteristics may becontributing to the problem.

Work and trip pipe at a controlled speed. ( Note : As a rule of thumb in 8 1/2” and smaller hole sizespressure effects will more readily result in hole problems occurring.)

Wipe the hole ( without rotating ) before making a connection. Note: This is the most effectivemethod to monitor hole drags and establish if hole conditions are deteriorating.

NEVER force the bit to bottom.

REMEMBER : Prevention is better than the cure. Think about what formation you are drilling,what problems are likely to occur, and how you will handle them.

If tight hole or drags cannot be eliminated during POH, Back ream with caution. Although thispractice is widely used there is no documentation available stating that such practices benefitsthe drillstring, hole cleaning and/or wellbore stability considerations.

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1.11.3.3 Open hole

Always exercise caution when tripping in open hole. The Drilling Representative orToolpusher may wish to be on the floor throughout the newly drilled section and through anyproblem sections encountered.

Never try to force the string through a tight spot. Pulling firmly into tight hole, may well lead tothe string becoming stuck.

Take it carefully and do not pull more than half the weight of the collars below the jars. If thisrule is followed, it should always be possible to work the pipe back down. This gives the Drillera figure to work to and will prevent many stuck pipe incidents each year.

Depending on the situation, the Drilling Representative has the option of gradually increasingthe overpull, each time checking that the pipe is free to go down. At any stage, the top drivecan be used to wash down and work the pipe.

Never pull more than the weight of the collars, as this will almost certainly result in the stringbecoming stuck.

Always wash and ream at least the last 3 joints to bottom.

Before tripping, always endeavour to sufficiently clean the hole.

Minimise time spent in open hole.

Monitor and record the depths and magnitude of drags, overpull, and any rotary torque (ifrotation was necessary) to help assess the condition of the hole.

Wiper trips should be made regularly according to predetermined procedures or as holeconditions dictate. Often the wiper trip will be made back into the previous casing shoe, butshort trips through newly drilled hole may be all that is required.

Supervisors should make themselves aware how the drilling jars work. The differentmechanisms need to be understood because certain situations may arise which require thatknowledge. For example, Daily mechanical jar settings change with torque, while hydraulic jars havean infinite number of settings depending on the pull.

If the string is pulled to the maximum and mechanical jars do not go off, it may be that theamount of overpull needed for the jar to hit has not been reached.

With hydraulic jars, it would mean that either the string would be stuck above them or that thetool had failed.

The Supervisor must know how each set of jars works to make decisions from this point. Anyrelevant information should be passed to the Driller.

The shale shakers should be monitored regularly by the Drilling Representative, as well as bythe mud engineer. The shape, quantity and condition of the cuttings give valuable indicationsof what is happening downhole. Supervisors should check the shakers at frequent intervalsand this practice must be continued.

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1.11.3.4 Top drives

Top drive units are a successful development in reducing stuck pipe incidents. However, itmust be recognised that the different drilling technique requires some specialprocedures and the same amount of care.

Problems peculiar to top drives, have doubtless been identified by all operations which haveused them. One example was highlighted on a UK Land operation, where the use of the topdrive actually increased the amount of abnormal drag. When drilling in singles with akelly, the newly drilled hole was wiped at every connection. With a top drive, drilling instands, the new hole was wiped far less frequently. This resulted in poor hole conditions andaffected drilling performance. After increasing the frequency of wiping the hole to once everysingle, until hole conditions were significantly better.

There is a risk of complacency with top drives, as they are sometimes regarded as beingcapable of keeping pipe moving, however tight the hole becomes. Consequently, action toimprove conditions are delayed or not take at all. This is the wrong approach; top drives aregood, but they are not infallible and abnormal hole drags must be treated with the sameamount of care as it would be if drilling with a kelly. Top drives are a good tool, but must beused astutely.

On floating rigs, the drill string compensator can play an important role in the prevention ofstuck pipe by helping to control sudden movements of the pipe. When drilling, thecompensator should be stroked out as far as the heave permits. This prevents the stringdropping through a fast drilling break and possible becoming stuck in an unconsolidatedformation. It is especially applicable for top hole sections, where the reaction time to pick upan almost closed compensator can be too slow to save a stuck pipe incident.

If abnormal hole drag is expected when tripping out of the hole, it can be a good idea to keepthe compensator unlocked. This gives the Driller more time to react if he suddenly runs atight spot. The small amount of time gained, may make the difference between staying freeand getting stuck. Be aware that come compensators' rating may not permit this.

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1.11.4 Differential sticking

1.11.4.1 Planning Stage

Check in the section the presence of any permeable formations which may lead todifferential sticking. In this case the Chalk or sands could be a problem area.

Estimate the pressure of the problem formation. ( Check with Mud loggers. ) If the risk ofdifferential sticking is thought to be high, make this clear by communicating this to each other.

Thick reservoirs can give a high risk of sticking, because of the low formation fluid density.NOTE : Overbalance can rapidly increase with depth when drilling through a gas reservoir.

Where differential pressures are thought to be high across a permeable formation, considertaking a RFT measurement. The risk of getting the logging tool stuck should be taken intoaccount, but this may be outweighed by the value of the information on later wells. The RFTis as useful to a Drilling Engineer as to a Petroleum Engineer.

If differential pressures are known to be high, give careful thought to the logging programme,particularly the number of pad tools. These are always susceptible to becoming stuck andespecially those tools with radioactive sources should be used with discretion.

Stuck pipe freeing materials should be available at the rig site. Sufficient volume to spot a pillcovering the BHA, plus 50 barrels, is the recommended inventory, although this should begreater for remote sites.

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1.11.4.2 Rig Site Precautions

Continuously track the differential pressure across permeable formations, as accurately aspossible. Follow the trends of the D exponent graph, trip gas levels and connection gaslevels, which should indicate changing pressures.

Keep the mud weight at the lowest safe level. A widely used rule of thumb is 200 psi staticoverbalance, although conditions will frequently dictate a different figure. Aim to keepdifferential pressures across permeable formations to a minimum.

Maintain a tough, thin filter cake and keep drilled solids content to a minimum.

Keep the pipe moving at all times. Reciprocating is the preferred motion, as it shows that thepipe is free to trip in and out of the hole. However, when this is not possible, (E.g. Onconnections,) rotation is considerably better than leaving the pipe static. Do not programmeunnecessary surveys as they are a high risk operation. An MWD surveying tool is less likelyto become stuck than a single shot, because the string is stationary for a shorter time. In ahigh risk area, this alone may justify the additional cost of an MWD.

Differential sticking regularly occurs during a well kill procedure, due to the increased mudweight. Under no circumstances should the fear of becoming stuck dictate the kill weight tobe used. However, excessive safety margins are sometimes used in both kill mud weight andcirculating pressures. These increase the chance of stuck pipe.

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1.11.5 Inadequate cleaning

Poor hole cleaning will cause hole conditions to steadily deteriorate, rather than having animmediate effect. Consequently, there should be ample opportunity to recognise andreact to the problem.

1.11.5.1 Rig Site PrecautionsPrior to starting a trip, the hole should be circulated until it is as clean as is practicallypossible. A minimum circulating time should be predetermined, but a trip should not bestarted if there are still significant quantities of cuttings coming over the shakers at that time. Itmay be beneficial to rotate and reciprocate the string while circulating in inclined wells, as themovement assists hole cleaning by disturbing cuttings beds.

There are situations where circulation alone could be maintained for days without the holebeing effectively completely cleaned. This may often be the case with cuttings beds or wellswith severe over gauged sections. Special tripping procedures may need to be used for thistype of well.

Do not permit the flow rate to drop below the minimum required to clean the hole.If a mud pump goes down, stop drilling until it is repaired. Trip back into the shoe if the delayis going to be a long one. Do not drill ahead, expecting to clean the hole at a later stage. Itmay be too late.

There are several indicators which can identify hole cleaning problems:

• Excessive overpull on connections and trips

• Reduced overpull when pumping

• Excessive fill after trips

• Erratic and increasing torque while drilling

• Lack of cuttings on shakers

These must be recognised and action taken.

Minimise the amount of over gauged hole, where annular flow rates are reduced and cuttingsbuild up is most likely to occur. Serious problems may result in the next hole section if a largecasing sump is drilled. Always keep the sump to a minimum. Big safety margins areunnecessary.

Other avoidable causes of over gauging hole are:

• Excessively high flow rates and jet nozzle velocity (Wash-outs)

• Insufficient mud weight. (Cave-ins)

• Incorrect mud formulations. (Soluble formations)

Control ROP to a level at which the cuttings can be removed. This must be applied toinstantaneous ROP, not average ROP.

Always look at the shakers to get a feel for the effectiveness of the hole cleaning. Does thevolume of cuttings seem right for the ROP? Do slugs of cuttings appear followed by very fewcuttings? The shakers will give an early indication of a hole cleaning problem.

When a downhole motor is being used in an inclined well, without rotating the drill string, it isprobable that the cuttings beds are not being disturbed. If possible rotate the string prior totripping out of the hole.

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1.11.6 Formation instability

1.11.6.1 Rig Site PrecautionsUnstable formations can give a variety of combinations of the following. Recognise them andrespond to them:

• Drag on Trips

• Fill on taps

• Excessive material on the shakers

• Excessive torque

• Increasing MBT levels which are not due to mud treatments

• Salinity changes in the water phase of oil muds

• Out of gauge hole

• Cuttings from an earlier drilled section

Mud properties must be maintained, particularly in shales. Even if it means tripping back tothe shoe, time spent conditioning mud may prevent a stuck pipe incident.

Trip with caution through swelling formations.

Ream each single if abnormal drag is experienced when wiping string prior to making aconnection. When using a top drive, stop rotating, pick up midway through each stand andream down. If hole conditions are severe, more frequent reaming may be required. Timespent improving conditions is not time wasted.

A top drive allows tight sections to be tripped through using slow rotation and circulation.After pulling into a tight spot, run back into gauge hole and circulate before back reaming out.

Tight hole depths must be logged by the Drillers/Tool pushers.

Drillers should be on the brake when tripping through problem formations, as they will havegained a feel for the hole.

At the first indications of tight hole, the Driller should inform Drilling Representative and theToolpusher.

Wiper trips should be conducted regularly according to predetermined procedures, withadditional trips being made if required.

In tight hole situations, consideration of the stuck pipe risk should be made before dropping asingle shot survey.

Never spend unnecessary time in open hole.

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1.11.7 Bottom hole assembly changes

1.11.7.1 Rig Site Precautions

Always gauge bits and stabilisers before and after each trip. Ensure that the correct gaugering is used for bits, some PDC bits need special rings.

Unless torque records clearly show the point at which the bit gauge became worn, considerreaming the whole of the section drilled by the bit.

When running a BHA of increased stiffness, expect to have to ream. Do not trip into the openhole rapidly.

If the hole is thought to be under gauged, extreme caution must be applied when tripping intothe hole.

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1.12 Ways to Minimise Torque and Drag

1.12.1 Well profile designWell profile design to minimise torque and drag involves minimisingwallforces. Since string tension is always highest at surface (which can leadto high wallforces as described above), the way to minimise wallforces is tominimise doglegs (build rates) at surface, and to build angle towards thetarget further downhole where string tension will be less. This is achieved bydrilling the well with a tangent angle as close to the critical sliding angle aspossible, causing the string to “glide” under its own weight.

Well profile design is also a compromise meeting a large variety ofrequirements, of which torque and drag minimisation is just one factor. Forconventional wells (low reach/TVD ration), “under-section” profiles (whichhave a deep KOP) are better because they give tangent angles closer to thecritical sliding angle. In contrast, the “build and hold” profile causes highertension, hence torque and drag. In ERD wells however (high reach/TVDration), a high kick off point will be required to provide the critical sliding anglein the tangent section.

Note that in deep wells, it is particularly important to drill the top sections assmoothly as possible to minimise the torque contribution from tortuosity.Excessive use of steerable assemblies can worsen tortuosity, rotaryassemblies are beneficial.

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1.12.2 Drillstring designTorque and drag can be minimised by optimising drillstring design. By usingthe smallest and lightest weight drillpipe weight and tension is minimise.Tapered drillstrings are particularly effective where stronger 65/8” or 5 ½”drillpipe is only used at the top of the string where loads are lightest.

1.12.3 BHA designBHA’s have historically been designed to ensure that WOB can be applied tothe bit without putting drillpipe into compression. Experience with horizontalwells where compressive forces in drillpipe cannot be avoided have shownthese assumptions to be overly conservative. BHA’s should be designed fordirectional control and of minimal weight in ERD wells. A torque and dragprogram (such as DSS) would be used to analyse the probability andconsequences of buckling.

1.12.4 Mud designAs noted earlier, mud type can have a significant influence on torque anddrag. To minimise torque and drag, muds should be designed to satisfy therequirements of wellbore stability, hole cleaning and lubricity. Wellborestability and hole cleaning are covered elsewhere in this manual (in the shaleproblems section, wellbore stability section and hole cleaning section). Herewe only consider mud lubricity.

Mud lubricity can be assessed in the laboratory with testing devices whichcrudely attempt to simulate field conditions. The resulting friction coefficientspossess a degree of error. However, they indicate trends and so are a usefulway of screening lubricant additives and comparing mud systems. The trendsare most useful when correlated with data from actual wells.

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1.12.5 Water based muds

•• The coefficient of friction will depend on the formation type being drilled.For water based muds where shale softening is possible due to poorinhibition, decreased values of friction may be observed. In hardsandstone etc. higher values of friction may be observed for an identicalmud system.

• Baryte improves lubricity when used in weighted systems possiblydue to the formation of a soft “bearing layer” modifying the surfacecontacts. Above ca. 1.2 to 1.3 sg baryte promotes reducedcoefficients of friction.

• Polymers in water based muds can have a beneficial effect onlubricity - partially hydrolysed polyacylamide (PHPA) can exhibit afriction reducing effect.

• The coefficient of friction is less for a steel/steel contact than asteel/rock contact (cased hole has a lower coefficient of friction thanopen hole.

• A wide variety of lubricants are available for addition to water basedmud systems. These have been systematically evaluated within BPand all show different performance features in reducing thecoefficient of friction. They are of benefit in low mud weight systemsbut less benefit in high mud weight systems.

1.12.6 Oil based muds

• In the laboratory and in the field, oil based mud systems exhibitlower values of friction than water based mud systems. By virtue ofits film forming capacity, oil is intrinsically a better lubricant thanwater, however, the presence of strong surfactant packages in an oilbased mud system may also aid the lubricity effect.

• The positive effect of baryte is less pronounced for oil based mudsbut oil/water ratio does noticeably affect lubricity: lubricity decreasesas the water content of the oil mud is increased.

• The coefficient of friction value measured in laboratory tests iscomparable for metal-metal and metal-sandstone contact. As withwater based mud, it is still observed that cased hole has a lowercoefficient of friction than open hole.

• Some of the new synthetic oil mud systems demonstrate betterlubricity than those formulated with mineral oil.

• So far, lubricants in oil based mud have had little application, asOBM’s are considered sufficiently lubricating. Water based mudlubricants are not effective in OBM. Solid lubricants (graphitepowder and lubra beads (see below) are more effective.

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1.12.7 Physical Methods

1.12.7.1 Lubricating BeadsA commercially available product called Lubra beads (small glass sphereswhich function like ball bearings) has been trialled with some successresulting in torque reductions of up to 20%. Removal of the beads by cuttingshandling equipment can be a problem. To get around this, the product can beused selectively to spot areas where high torque is occurring.

1.12.7.2 Drillpipe CoatingsA small amount of work has been carried out looking at coatings which could be applied tosteel to reduce the steel/steel friction coefficient. Hardbanding of tooljoints to reduce casingwear has also been examined. Because of the extreme forces involved in drilling, theintegrity of the coating remains an issue.

1.12.7.3 Drillpipe ProtectorsNon-rotating drill pipe protectors (DPP’s) have been shown to reduce torqueby up to 30% in many ERD wells, The recommended tool at the moment isthe Wester Well Tool non-rotating stabiliser, although other tools are beingdeveloped. However, there are a number of downsides to their use:

• annular pressure loss is increased (up to 2 psi per tool, quoted inNorway)

• sliding ability is reduced• durability still causes some problems• their use is restricted to cased hole• significant cost and installation/removal time

Their use should therefore, be optimised by placing them in areas of highestwallforce. Wallforce should be calculated with the DSS to determine optimumplacement and the number per joint required.

1.12.7.4 Bearing SubsBearing subs may be used in open hole where DPP’s are not suitable. TheDBS bearing sub has been successfully trialed on BP’s Miller platform. Again,sliding may be hindered in very high angle wells. Time for make up and cost,must also be considered.

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1.13 Mud gas definitions.

1.13.1 SummaryPlease be aware and fully appreciate that it is imperative in pore pressure estimation that thegas levels in a drilling mud are correctly interpreted and the definitions are strictly adhered to.

Pore pressure can only be definitively assessed on the basis of observations of trip gas ,connection gas , swab gas and pump off gas. If any of these are observed then porepressure levels are close to mud hydrostatic.

Increasing background gas levels can indicate increasing pore pressure if correctlydetermined and analysed - it is important that the drilled gas level content of background gasis understood.

For definition purposes the level of gas in the mud is due to one or a combination thefollowing:-

Background GasThe general level of gas carried by the mud purely as a function of circulating in open hole.

Drilled GasGas which has entered the mud due to the actual drilling of the formation. i.e. the gascontained in the matrix of the rocks which have been drilled.

Connection GasThe gas which enters the mud when a connection is made due to reduction in hydrostatic dueto loss of ECD and due to swabbing while pulling back.

Swabbed GasThe gas which enters the well due to swabbing . This may be caused by tripping or bysimulating tripping.

Trip GasThe gas which enters the mud during a trip which is measured after a trip has taken place.

Pump Off GasThe gas which enters the mud due to turning off the mud pumps and removing ECD from thehydrostatic pressure on the bottom of the well.

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1.14 Riserless drilling

It is not desirable to close in a shallow gas kick due to formation integrity in offshore wells. Ifflow should occur, the following reasons are provided to illustrate the benefits of drillingriserless.

Riserless drilling is carried out for the following reasons :

a. Hydrostatic pressure of water ( sea level to sea bed ) reduces rate of gas flow fromthe well thus increasing chances of successful dynamic kill.

b. Keep gas away from personnel and rig.

c. Gas will be partly or completely dispersed by currents

d. Fire hazard will be reduced.

It is commonly thought that shallow gas is LOW volume and that gas will deplete quickly orthe hole will bridge. This is NOT ALWAYS TRUE.

Shallow gas must therefore be expected to blowout long term and the hole to stay open. Itmust be treated as such until events show otherwise.

At the first signs of Shallow Gas kick the rig MUST be placed immediately on standby forabandonment with only designated key personnel on duty.

Immediately these designated key personnel shall activate the shallow gas handlingprocedures prepared for the well.


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