1 Overview Preamble Status pre-abandonment Stena Don The rig – sublet from Statoil (long term contract) at a very high dayrate. Completing wells on the Norne field, 99 nm north of Draugen. New build – less than 2 years old. Excellent Hydralift drilling package, very motivated crew, Class 3 DP (6 thrusters) Limited deck space, poor pitch/roll characteristics. Cranes so large the rig lists when they boom out! Poor HSE statistics (5 LTI’s in the past 1.5 years) Kit – 2 x 2200 hp 7.5 k pumps + 1 backup (6" liners for whole well); mousehole for offline stand building; can move at drilling draft – full rotary ops Preamble The Garn Central North appraisal well (6407/9-10) was planned to evaluate possible additional recoverable oil in the northern part of the Draugen field, some 4 km north of the platform. The well was drilled by the Stena Don on a single well campaign in June 2003. The design drew heavily on successful exploration wells drilled in the area in 1999 (Draugen South & Hasselmus) by the Maersk Jutlander. The well was planned with the premise that subsurface drilling risks were fairly well understood, and this, when taken together with the simple well design, made the well an ideal candidate for operational optimisation. The well functional specification was also relaxed as much as possible (directional & logging requirements). This document forms The drilling end of well report (formation evaluation results will be reported separately). Summary of the well after action review conducted with Schlumberger D&M, MI, Smith, Red Baron and Shell. The intended audience is those involved in the planning & execution of similar design wells in the future, especially on Draugen. Conciseness & accessibility have been favoured over a fully comprehensive single document. However, a list of references for further details is included. It is important to read the well programme (or at least be familiar with Draugen well designs) to take advantage of this document. Shreyas Bordia and Harald Nevøy Status pre-abandonment 24 m Air gap Overall lithology 273 m Top 18 ¾" WH 275 m Seabed OWC? Pre-drill prognosis, reservoir sections Questions answered by the Garn Central North well Depths of Garn & Rogn? Is the Rogn flushed? Is the Garn oil bearing? Rw of formation water? Glacial deposits: boulders 288 m Btm 20" extension 359 m 30" conductor 360 m 36" hole 9 ⅝" NSCC 53.5# L-80 above 602 m 9 ⅝" casing x-o Nordland: reactive clays (hydrostatic) 9 ⅝" VAM Top 47# L-80 below Hordaland & Shetland shales: over-pressured up to 1.35 sg. at the base 1008 m 9 ⅝" csg shoe 1020 m 12 ¼" hole Rogn & Garn sands (hydrostatic) 1800 m TD 8 ½" hole Well position: N 7 139 619 m, E 440 613.5 (UTM zone 32) All depths in this schematic and hereafter are mbRKB. The well was vertical to TD – max inclination 0.8°. Note wireline TD is 1802 m.

Time & performance analysis 2 2 4 6 8 Days 10 12 14 16 18 Zero line = target aspired performance = 9.9 days for complete programme -1 Days behind base plan (TDS repair) -2 Days behind Target -3 Days behind (low ROP due to bit/BHA balling) -4 (wiper trip) (long MDT pump times) Pull BOP -5 Clean-out Move off 9 ⅝" csg -6 Move in 36" hole 30" cond 12 ¼" Run BOP 8 ½" hole Wipertrip & logging Deep plugs Cut csg -7  Contractor performance Time breakdown HSE Acceptable No LTI’s or MTC’s Two first aid cases: A roustabout laying down the pennants slipped, the pennant hook fell down on deck, cutting his boot open by the ankle, with the clump weight hitting the toe cap. Examination by the Medic showed no sign of fracture but a small superficial cut to the small left toe. A wireline operator was attempting to turn a logging tool (approx 100 kg) on a 0.3 m high roller stand along with a colleague when it slipped out of the stand and dropped on his foot (instep bruised). The medic put ice on it and he went back to work. Schlumberger D&M BHA's/MWD/LWD DD/MWD/LWD P/U assy, R/U eqpt on floor Tripping, reaming Drilling Circulating BOP Logging Rig moves Casing Cement (incl plugs) Stena DT – Other 2% DT Stena – TDS retractor arm repair 7% Wiper trip 4% DT - serv co 2% Down time – other 1% Planned maintenance 4% Downhole & subsea ops Non productive time 20% Stena Ltd Rig MI Drilling fluids Halliburton Cementing Cementing/bridge plug Oceaneering ROV ROV Costs Dril-Quip Wellhead Stena/Weatherford Casing running Smith Bits Bits Red Baron Hole opener/csg cutter Schlumberger WL Logging (combined offshore and onshore performance)

3 36" hole section The master plan Operations BHA Lessons learnt Definite formation change observed from hard pebble beds to soft clays (in this well at ~315 m). Can perhaps set the conductor once this bed is penetrated. Do we need dye in the lead spacer? Rarely observed by the ROV in practice... Involve the other operator early in planning – in this case Statoil agreed to begin the move while their rotary ops were continuing, ie the rig was on their contract. Since our rotary ops took the rest of the move, this implied that the move was no longer on the critical path. Also very helpful to send a DSV out early (excellent reception by Statoil offshore). They also left their infrastructure in place & provided a very informative handover. Points to ponder ROP in this section for Draugen wells tends to be low (10-24 hr to drill)... Can we use a more aggressive hole opener (i.e. a milled tooth one)? Main reason given by Smith for using inserts in HO – pebbles may cause MT cones to lock up (not a problem with lead bit) In all other respects, milled tooth performance should be better for both soft clays and pebbles/boulders. Can it be advantageous to run a milled tooth lead bit and insert hole opener? Reducing WOC time Run faster setting slurry (2-3 hr)? Increase stickup as much as possible since fill not major issue (can be washed away) while may not be able to tag btm again after cementing…? (we could make up assy's in the mousehole on the Don while WOC) Based on hi-res seismic the Quaternary glacial deposits ended at about 350 m – a 7 jt conductor was chosen to isolate these (based on the risk of pebbles falling in while drilling 12 ¼" hole). Main objectives were to maintain a vertical hole for the BOP (incl max 1.5°) & to minimise BHA damage from boulders, identified as a major risk. Overall philosophy was to keep the BHA's for the 36", 26" & 12 ¼" as similar as possible. All assemblies were intended to be P/U on move from Norne. However the MWD used for this section was to be laid out due to expected shock damage from boulder drilling. It was intended to set the conductor on bottom to reduce wait on cement time from expected 4-6 hr to 2-3 hr. No cement top job planned unless no cement returns to surface. Would be done with 5" stinger stabbed into annulus. Only a 2 jt 5" DP stinger premade to the 30" CART was used to save time. Hole opener: 26" x 36" Smith Red Baron heavy duty hole opener (360/2HD) dressed with cones similar to lead bit. Flow split 60:40 bit-hole opener. Used 5" HWDP to surface for stiffness to reduce inclination. 5" HWDP to surface 6 ½" DC 3 jts) Crossover 8" DC 7 jts 12 ¼" NM Stabiliser 9 ½" NM Collar PowerPulse HF Pony DC 26" x 36" HO w/float 17 ½"" Bit First 3 m soft (RPM 40, no WOB, flow 3000 lpm with hivis) Cont drilling at 3-4 m/hr. RPM 75, 4500 lpm, 2-3 T WOB. Pumping SW with 2 x 10 m3 hivis sweeps per stand. Erratic torque. Torque cont erratic (7-15 kftlbs) but axial vibrations moderate indicating pebble beds. Inc RPM up to 140, WOB to 5-6 T. 290 m – torque stabilised but ROP still 3-4 m/hr. 315 m – drilling break… torque smoothened, ROP inc from 3 to 50 m/hr. TD 360 m (36" hole) Reamed last std, circ clean with 15 m3 hivis sweep. Displaced hole to 1.2 sg hivis mud. POOH – little wear on HO/bit. Downtime report… Cracks were discovered in the top drive retractor arms during routine maintenance just before spud. These took 28 hr to grind out and fill in. The cause of these cracks is thought to be a temporary modification (stops installed) made to the arms months ago to prevent them from extending too far, which caused excessive stresses at the top edge of the arms. Logging requirements – GR/res up to reservoir LWD quad combo in reservoir Casing & cement Casing: 7 joints 30", 1" WT, X-52, SL-60 Suspension jt was 1.5" WT. Run using double bails and 2 sets of 30" elevators. Ball valve was left open in RT and conductor not filled while RIH (ROV closed valve later) Cement: Pumped 52 m3 1.95 sg Class G slurry. Tagged btm, P/U 1 m to cement. Old cement residue in surface lines caused blockages. While these were cleared (3 hr) contd circ – this could have washed away the bottom of the hole, hence could not tag btm again without burying 30" housing. Pumped hivis dye pill – no trace on seabed. Clear cement returns – hence no top job performed. WOC (in tension, heave compensated) 5 hr based on surface samples & ROV seabed checks. 200% OH excess cement 1.95 sg 2 m cmt inside shoe (was not possible to set on btm) 2 jt 5" DP stinger 30" final stickup ~1.7 m The lead bit 17 ½" insert lead bit with centre nozzle (Shell owned, IADC 435) Displ with 1.2 sg mud

4 12 ¼" section The master plan Operations BHA Alternatives to cleanout run “Long” x-o: 13 ⅜" xo with tailpipe, drill longer 17 ½" pilot section. Displace cement to within the tailpipe. “Short” x-o: XO directly to 13 ⅜", no extension, overdisplace cement. No x-o or shoe, overdisplace: As above overdisplace cement out of shoe, but omit shoe entirely - plain 30" pipe (may guide shoe by bending in). Note we WOC anyway. Drill out with 12 ¼": Routinely done to drill out 17 ½" hole from 30" cond (not Shell though…). Can we do this for 12 ¼"? Different tail cement recipe? Fibre cement? Drill 12 ¼" & 36" hole together on same run: Drill 12 ¼" "pilot hole" to near TD, trip out, install hole opener in string and drill to TD (note flexibility in setting depth for 9 ⅝"). Ideally (in deeper water) have the 30" cond hung off in the moonpool with the 9 ⅝" csg + 18 ¾" WH inside it, locked in. Cement only through the 9 ⅝" to achieve both cement jobs (can divert cmt outside 30" by restricting ID at 30" shoe if reqd, else can use Titus system for 2-3 jts) Otherwise, run 9 ⅝" through 30" housing and lock it down in the moonpool. 36" 17 ½" 30" xo 36" TD 12 ¼" TD Points to ponder How fast can this hole be drilled? Note: drilled at ~150+ m/hr in Draugen South (DS) with lower pump rates. Limited by "hole cleaning", but presumably only when pumps off… What exactly will be the limiting factor? Change in ann size at the 30" shoe? (assuming a hivis pill is spotted across the BHA & btm of the hole) Can we run a 1 jt 30", xo to 20" to shoe – enough structural support? If if there is some cutting settling, can we stir up this lightly packed bed that has settled during, say, one connection time? Are the cuttings dispersed completely? If not, what is their slip velocity? ECD sub not thought useful in DS & Hasselmus – why not? Can get static pressures with pumps off… How deep can we drill? If ROP performance in the 8 ½" section is poor c.f. 12 ¼", it may be useful to drill deeper with this section… Objective: Cleanout 30" shoe with 26" bit (to eliminate risk of cement blocks falling in when drilling 12 ¼" hole) & then drill into or above the pressure ramp at/near the top of the Hordaland. Note there is a significant range possible in casing setting depths, and no particular measures to evaluate the pore pressure were taken. Hole to be displaced to heavy inhibitive mud (kill mud prep with CMC, added KCl) to ensure stability for running csg in case pressure ramp was penetrated. Shoetrack minimised (no intermediate jt). Ommited 9 ⅝" FIT, since: Irrelevant for kick tolerance (the Rogn would be over-balanced even with oil to the shoe set at 950 m) Good data available from several offset wells (LOT’s ~1.7 sg). Note the ECD was modelled at 1.45 sg out of the 9 ⅝" shoe. Therefore, FIT would be useful only if leak off between 1.35 & 1.45 Deviation from EP 1500-2002 but not NORSOK/NPD. 5" HWDP 27 jt 6 ½" DC 3 jt Crossover 8" DC 3 jts Hydraulic Jar 12 ¼" NM stabiliser 9 ½" NMDC 1 jt PowerPulse HF Bit Sub xo w/ solid float 12 ¼" bit Cleanout run: Drilled out shoe with 26" bit (6 hr total) RIH 12 ¼" assy, drilled at 100 m/hr on btm constrained due to hole cleaning concerns throughout section. Pumped 1 x hivis sweeps per std. Gradually incr WOB over section to maintain ROP. WOB 3 – 10 T RPM 120 - 140 Flow 4500 lpm At TD, circ B/U, displaced to 1.2 sg KCl/CMC mud. POOH, jetted cuttings bed around WH. No major wear on bit. Logging requirements – GR/res up to reservoir LWD quad combo in reservoir Casing & cement Casing from top: 18 ¾" Dril-Quip SS-15 WH – 20" extension – 9 ⅝" 53.5# L-80 NSCC csg – x/o - 9 ⅝" 47# L-80 VAM Top csg. Note – NSCC csg was old Shell stock. Cement: Lead – 58.4 m3 1.56 sg Class G slurry. Recipe HR-4L 1.5 lhk, Econolite 3.2 lhk + defoamer. Tail – 10 m3 1.92 sg Class G slurry. No clear confirmation of cement returns at seabed. Saw clear indication of btm plug rupture & top plug release. Bumped plug and tested csg to 207 bar/10 min. Displacement volumes consistent with lower range of calipered ID's. Top 18 ¾" WHH 272.8 m Lead cmt to surface Bit – Smith FGXi IADC code 117 milled tooth bit Twisted teeth for scraping cutting action (“Twist & Shout” in the Smith literature) Dull grading 1-1-WT-A-E-I-NO-TD 9 ⅝" csg x-o 602 m Tail (theo) TOC 847 m Internal TOC 988 m Landing collar 992 m Shoe 1007.6 m

5 8 ½" section – what we did Bit BHA Mud The master plan Actual properties (selected) Specifications 1000 Accelerator – Weir Houston (to achieve very high jarring forces in case of diff sticking) 1100 5" HWDP (6 joints) 1200 Jar (Weir Houston) 1300 First check after C/O active system 1400 5" HWDP (13 joints) Bit – Smith S88 Steel bodied 6 bladed PDC bit with large cutters (17 x 19 mm, 7 x 16 mm, 12 x 13mm) Large junk slot area. Steel body for raised blades  junk slot area. 6 nozzles 3 x 13, 3 x 14 – TFA 0.840. HSI 3.4 at 2300 lpm BLC vendor bit similar to Draugen South 8 ½" bit Added backreaming cutters (often required in silicates’ gauge hole) 1500 5" NM HWDP 8 ⅜" NM stabiliser 1600 The master plan Logging requirements – GR/res up to reservoir LWD quad combo in reservoir 1700 PowerPulse Position of PWD sub Drill out cement while displacing to 1.35 s.g. sodium silicate mud (Sildril). Mud wt required to support possible overpressures in the base Shetland clays (just above the reservoir) up to 1.35 sg. Drill to TD below the Garn sand (35 m logging pocket in the Not claystone). Note Rogn expected to be depleted due to production to sub-hydrostatic pressures, hence overbalance expected approx 70 bar, with attendant diff sticking and seepage losses risks. Intended parameters – WOB 5-10 T, RPM 140-170, 2500 lpm. BHA Packed hole assy Backup BHA's – straight motor pendulum assy in case 9 ⅝" shoe set at >3 deg; also a sidetrack BHA. Rationale No DC – reduce diff sticking potential. Stabilisers to hold hole angle even if WOB reqd to drill, esp deeper in section. Also to reduce diff sticking. Stabs chosen as "open" as possible to avoid balling. Unable to procure straight blade stabs that pass NS-2. CDR with APRS. GR & resistivity only 1800 8 ½" String stabiliser 1900 6 ¾" Pony collar (solid float included… swabbing risk) 13.0 11.0 10 30 26 34 pH PV (cP) Pf (tit. vs 0.1 N H2SO4 in ml, phenolphthalein ind.) 50 YP (Pa) Calc Sildril % content from Pf 14 8 ⅜" NB stabiliser 8 ½" Bit

8 ½" section – what happened 6 1631 Not Further Operations POOH – saw incorrect fill & drag as expected… pumped out to shoe. Circ B/U precautionarily – saw large quantities of cavings up to 8 cm in size over shakers! POOH after shakers clean. Entire BHA nearly completely balled. 5" TJ's balled up. Bit balled up with layered fine "pottery clay" type material. Ran wireline – hung up at 1130 m. Wiper tripped – washed 1130 m, say another obstruction at 1580 m (washed). 8 m of fill on bottom! Weighed up mud to 1.4 at TD (in case cavings were pressure related). POOH with no overpulls but balling on BHA again! Ran wireline logs – no diff sticking or hole stabilty problems at all. Hole in gauge over entire section except circulation points. ECD s.g. ROP m/hr ROP Hit hard cement at 988 m, drilled at 1.5 m/hr. Soft cement below collar! Initial ROP 30-40 m/hr with planned parameters. YP higher than spec caused initial ECD of 1.56 sg (expected 1.45 sg). 1060 m – Rise in ECD (soon after top stab enters new hole). Indication of balling soon after... pump off force, reduced torque, swab/surge. Reduce flow to 1800 lpm. Cont drilling keeping ECD < ~1.7 sg. Vary parameters to reduce balling – no effect. Max ECD spikes up to 1.9 sg. No losses. Cuttings structure – no clear PDC type cuttings, small, inhibited on inside but with fine solids dispersed around them. (similar for whole shale section) 1285 m – Discover low silicate content in mud, previously incorrectly measured. C/O mud system to reserve (no more silicate on board or in the area!). SPP/ECD dropped 0.2 sg during displacement Top stab (above PWD) clears at times. SPP cont high in 150-170 bar range. 1525 m – SPP up to 200 bar (no change in ECD – but calculated eqv ~1.9 sg). Attempt to clear (pumping sweeps, RPM)... no effect. SPP reduced in sands, constrained now by bit (esp in Upper Spekk & Not). Drill to TD at low ROP. Circ 2500 lpm down string + same up riser to 3 x BU – shakers clean. Points to ponder Why was the cement above the collar much harder than below? (~150 litres – ½ surface lines volume of cement pumped behind dart to prevent plug rotation) …perhaps falling cement and vacuum below top plug reduces cement strength? High ECD's but no losses! …clearly difficult to induce massive losses even at EMW higher than LOT's in the area. High FPP? Possibly continuously sealing off fracs with drilled solids + precipitated silicates (as is used for LCM) Origin of cavings…? Some random stressed zone?… reduction in EMW at end of drilling and POOH? …probably microfracs created by the high ECD's and spalling off when POOH (swab effects) Gauge hole but 8 m fill & large quantities of cavings…? (8 m of fill observed in wiper trip but no large deviation from gauge hole seen in caliper log. Additionally circulated large volumes of cavings for 1.5 hrs… how is this possible?!) Possible cause – "accretion" of re-worked cuttings continuously plastering the hole while drilling. Note ECD was probably high only over a short section of the BHA. No invasion or diff sticking! Heat checking/cat's eye wear on bit? Wear on bit indicated extreme heat – indicating reduction in flow across bit... how? Could be during cement drillout (but pumping SW at high rates)? Plugs "stuck" on bit preventing flow from reaching nose cutters? Note – further discussion of balling on next page. Reduce shoe drillout time Took 5 hrs to drill the shoe & probably damaged the bit in the process Use Shark-Bite to prevent rotation …and overdisplace the cement (pump water ahead of the wiper dart) …or pump light lead cement ahead Shorten shoe-track no intermediate jts in this shoe track but can run landing collar immediately above shoe. General wear – chipped & broken cutters. Bit was completely balled up around the gauge. Dull grading 4-3-CT-X-I-BU-TD Logging requirements – GR/res up to reservoir LWD quad combo in reservoir "Cat eye" – rare IADC dull grading caused by extreme heat checking – parts of the diamond compact around the edges of the cutters spalls off

8 ½" section – a closer look 7 What was happening (we think) MI's view: “It’s them stabs wot dunnit”… Balling problems were due entirely to the BHA. Recommend never running NB stabs, no FG stabs, and no packed BHA’s with silicates (give e.g. of Statoil well where removal of a NB stab made startling improvement). Stress that since MBT, PV, LGS were normal (until late in the section), the mud showed excellent inhibition properties. Always recommend a wiper trip with silicates. Also view additional KCl as a waste since it does not contribute to inhibition. Do not think mud formulation can reduce/prevent accretion as long as silicate levels are high enough – if balling occurs, pull BHA and change. Balling/accretion are complex phenomena with many variables. Silicates run in low salinity systems (note the definition of “low” in itself depends on hydraulics, BHA, hole size, bit type, etc.) show a marked tendency for balling. The mechanism is thought to be  reworking/regrinding of cuttings, esp large PDC ones, when in a constricted environment (NB/FG stab).  KCl is known to reduce/prevent this from field experience (see note below), however the “best practice” number of 80 kg/m3 (which we had) may be insufficient in some areas.  High rheologies exacerbate this – we had laminar flow even around the the BHA.  Additionally, these clays contain gypsum which can cause silicate gelation when certain condition exist. BHA Bit Mud Procedures Stabs (minimise) Under-reamer? (ideally without stabs below at all) Junk slot area (high). High blade standoff No FG stabs (UG should work since hole perfectly in gauge) Straight blade if poss, max open area Depth of cut (low – ensure "stoppers" in bit) High RPM (straight motor?) HSI/flowrates (very high) Electro-negative coating? Low(ish) WOB Flow (AHAP) Bicentre bit? (formation may be too soft) Silicate content shd start at high end of spec "ROP enhancer"? Environment issues… KCL min 130 kg/m3 (similar level to what a normal KCl/poly mud would run in the area) Pendulum? YP: only as high as absolutely reqd to suspend barite (in vertical hole) 8 ⅜" NM stab 8 ⅜" stab Silicates are generally less prone to balling than other WBM, but when it does occur it tends to be more severe. Anti-balling agents exist (“ROP enhancers”), but are invariably lubricants and/or surfactants, discouraged in Norway for environmental reasons (yellow chemicals). Once balling occurs, it is very difficult to remedy. Traditional fixes (e.g. caustic/nut plug sweeps) have limited value, as do “anti-balling” bits. Strategies to reduce these problems are depicted in the diagram to the right. Lessons learnt MI's performance was abysmal. Important to have at least one mud engineer familiar with silicates, and support from onshore. The mud engineers on board, among many other things, did not communicate with Shell and were apparently unable to measure the silicate levels. Note: MI onshore – Svein Stokkeland & Arne Askø. Stan Alford (silicate expert) at the AAR. Consider pre-well interviews (like BP in the UK) or additional consultant mud engineers Silicates are temperemental! Wells need to planned as a whole, with BHA’s, bits, mud properties & drilling practices all working together. Relatively small changes in the programme can have major effects – unforgiving system. Fully “scientific” models to describe downhole mechanisms are still limited… field experience must be the guide. This has been limited in the North Sea since 1999 (due to the widespread use of OBM’s). However there have since been hundred’s of successful silicate runs elsewhere. Compare the Hasselmus well Drilled in 1999 east of the Draugen main field Practically identical BHA’s… same formations... But two differences in the mud system discovered during the well review KCl content 130-140 kg/m3 instead of 80 kg/m3 YP lower at about 15 Pa These differences are typical between Baroid’s Barasilc and MI’s Sildril. No balling experienced on Hasselmus or Draugen South & Draugen A-4 also drilled with Barasilc Similar successful runs with Barasilc by Conoco in 2000 in the geologically similar & neighbouring Heidrun area Correlation also seen in Shell Expro’s infamous Merlin W11 well (Dowell – 80 kg/m3 KCl) c.f. Bittern wells (Baroid – 140 kg/m3 KCl) drilling the Shetland clay/marl. Logging requirements – GR/res up to reservoir LWD quad combo in reservoir Why KCl is still critical Inhibition by silicates is a "surface" phenomenon, achieved entirely by isolating (both chemical & pressure communication) the formation from the mud. However, when the BHA/hydraulics allow regrinding of the cuttings, new surface areas are continuously exposed and squeezed together. If the shale is not internally inhibited (i.e. as achieved by KCl through mechanisms still under dispute), cuttings can agglomerate. This can continue until they are finely ground, with the appearance of hydrated clay. [There is some evidence the silicate layer (i.e. silica gel network structures + precipitated Ca/Mg silicates) acts as semi-permeable membrane with high KCl/NaCl in the mud, further dehydrating the shale by osmotic transport]. This concept is rejected by MI. Note this may be ineffective with shallower, younger shales (however drilled with SW in SEPNo)

Electric wireline logging 8 The master plan Lessons learnt It is possible to avoid MDT tool plugging in silicate muds – a good flushing procedure needs to be used. CMR tools have a higher risk of diff sticking than MDT's (Schlumberger experience). Overbalance confirmed as 72 bar with the Rogn depleted to 0.98 sg. Silicates are excellent for logging due to negligible invasion, very low diff sticking risk and long open hole times. Can be used when invasion/unstable hole causes problems in getting good logs or cores MDT pump times should be based on data from similar reservoir/mud systems (e.g. can use shorter pump times in this situation) Do not need to run existing fluid analysers (LFA/OFA) for WBM/water sampling. Commercial considerations should be involved in decisions for the logging programme (e.g. SLB recommend filling all possible sample bottles... 2 for each depth, but only one ea was used). The log witness should be aware of these issues. Experienced ex-logging engineer consultant log witness very valuable. Toolstrings Three runs planned (PEX – minimum success criterion, MDT, CMR). Run in decreasing order of value & increasing order of sticking risk. Perceived high diff sticking risk Detailed decision tree for contingency formulated. Fusible weak point run for max possible pull. (note CaCO3 added to mud prior to drilling reservoir) Risk of MDT tool plugging due to silicate precipitation Experimental flushing procedure used involving surface and downhole flushing with water filled bottles. PEX MDT flow diagram CMR Run in OFA mode… and not used at all For internal flushing Note entire tool eccentralised against borehole… including stationary times when tuning or taking MRF stations Points to ponder Excessive pumping time for MDT? Time for MDT was about 4 hr each… even though resistivity logs showed practically NO invasion into reservoir. Water samples in WBM meant no clear parameter could be used to differentiate the two – pump time chosen was a “safe” value. Sensors to distinguish water samples in WBM are under development (based e.g. on pH) Until then, time will depend qualitatively on data value, level of invasion & mobility Replace PEX run with LWD? If the quad combo is run on LWD, the PEX run may be eliminated (sonic run on CMR run). Depth correct with wireline GR. Advantages – reduce risk in case not able to run wireline, less chance of sticking sources, eliminate one wireline run. Huge upside if only quad data reqd & wireline can be eliminated entirely. Issues – resolution of LWD, “software incompatibilities” with LWD and Shell software. Downtime report… Unable to pass 1130 m on first run with logging string #1. Wiper tripped… see 8 ½" section. Schlumberger QAQC of cables Separate failures on three successive cables sent out! 1. Short circuit; 2. Corroded – not checked before sending; 3. Short circuit (had to cut off length). If the 8 ½" section had been drilled in the normal time, this would have caused substantial down time. See logging AAR minutes for further actions from Schlumberger re better tracking of cables Hung up at 1130 m first run in the hole. After wiper trip, ran logs as per plan (wireline TD 1802 m). EMS caliper did not close after up log across reservoir. Used down log as repeat. Took 12 pressure readings & 3 sample depths (2 bottles each). Pump time 4 + 4 + 2.5 hr. No overpulls after sampling. No sample contamination at all. Overbalance confirmed as 72 bar, Rogn depleted to 0.98 sg. Performed bound volume and full polarisation passes. Took 4 MRF station points (using faster CMR "Plus") No indications of diff sticking.

9 Abandonment Approved deviations from regulations Cutter assembly Final well status Air gap 1. Testing of barriers: The abandonment cement plugs were not inflow, weight or pressure tested. The open hole cement plug extends to 141 m above the top reservoir level and was formulated based on calliper and temperature values and will thereby ensure a competent barrier. The second cement plug is set from a tested mechanical plug at the bottom of the 9 ⅝" casing. 2. Surface cement plug: The top of cement on the surface cement plug is deeper than 50 m below the seabed. As there is only one casing string in the well, the 200 m cement plug set above the mechanical plug will also constitute the “surface” cement plug. 24 m Casing Cut: Assembly: 11700 pipe cutter with 44" opening arms and 9 ½" Drillex motor with slip mandrel assembly and bumper subs. Cut 20" (0.812" wall) x 30" (1" wall) at 280 m in compression. 275 m Seabed 280 m Casing cut Cement plug #2: 7.4 m3 1.90 sg seawater Class G slurry. No special additives. After setting EZSV, pumped 10 m3 seawater followed by cement slurry (through EZSV setting tool). Displaced to balance with water and 3 m3 mud. Displaced well above cement plug to seawater. Pumped sponge wiper ball. No cement residue in tool joints. 30" conductor Downtime report… Traces of cement were found inside the 4 ½" IF & 3 ½" IF tool jts from drill pipe used for the first (open hole) cement plug, even though a sponge wiper ball was pumped. Contaminated pipe was laid down – a total of about 12 hr was spent to L/O DP and to flush through the pipe, most of it on the move (was needed for completions by Statoil) How can we prevent this? Internal landing shoulder & latch 763 m TOC Bridge plug: Type EZSV, permanent. Ran in hole and set permanent bridge plug at 963.5 m. Confirmed set by setting down weight on plug. Pressure tested plug 207 bar/10 min. Points to ponder Time for cutting casing... Took exactly as long as planned – 4 hr, however according to Red Baron, can take up to 24 hr. Issues – possible 20" rotation (hence was cut in compression); cement quality in annulus (should be present but be soft) Preventing cement contamination of IF connections Cannot pump SW at high rates after OH plug, but… Can we use a very retarded OH slurry so cement is still flushable after cased hole plug, then PLF seawater? Note that wiper darts or sponge balls do not seem to be sufficient. Pulling wearbushing Had to pull wearbushing before cutting casing (special – 16" OD nominal bore protector but with 8.7" ID to prevent vibration in wellhead while drilling. Recommended by Dril-Quip. Preinstalled) Can we run normal nominal bore protector? Discuss with DQ. 963.5 m EZSV 1008 m 9 ⅝" csg shoe 1020 m 12 ¼" hole Cement plug #1: 13.2 m3 1.92 sg Class G slurry. Halad-613L 7.5 lhk, HR-5L 0.2 lhk, CFR-3LE 0.7 lhk with drill water 35.74 lhk Pumped 1.65 sg spacer followed by the cement and 0.98 m3 spacer behind the cement to balance the plug. Displaced cement with 10.4 m3 1.40 sg silicate mud (underdisplaced by 0.6 m3). P/U to 1450 m and pumped sponge wiper ball down string & contd POOH. Discovered traces of cement inside tool joints. 1490 m TOC 1800 m TD 8 ½" hole Lessons learnt Observed severe backflow up string when POOH after cased hole plug due to change in annular heights of cmt & spacer. Suggest use only 5" DP to eliminate this problem.

Would you like to know more? More on this well General Programme Detailed drilling guidelines BHA sheets Lessons learnt table Planning questions Data LAS files Geoservices logs 8 ½" section Schlumberger good practice for running MWD in silicates Justification note to omit FIT Logging Logging AAR note Log witness report Schlumberger good practice for running MDT tools in silicate muds Similar wells in Draugen Draugen South Hasselmus Similar concepts elsewhere Shell Malaysia – see their website Woodside Silicate muds Shell documents Silicate Best Practices ROP in shales SIEP BTC Best Practice Expro silicate book by Jim Simpson Bit balling report – Shell Expro Merlin W11 well WGN notices (URL refs on GCN drive) Shell people Eric van Oort, SEPCo New Orleans Ron Rock, SEPTAR BTC Houston Chris Higgins, Shell Expro (erm, EP Europe), Aberdeen External documents (all these are available on the Garn Central North drive) Baroid silicate guidelines Baroid silicate database MI database SPE papers External people Stan Alford, MI Tom Pogue, Baroid Logging requirements – GR/res up to reservoir LWD quad combo in reservoir