ELGIN /FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID /CEMENTING REVISION 00
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HP/HT Best Practices and Guidelines
ELGIN / FRANKLIN Development
Volume 1
- DRILLING FLUIDS - CEMENTING - HYDRAULICS
ELGIN /FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID /CEMENTING REVISION 00
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Central Graben Asset : Subsurface Manager
1 Copy
Drilling & Completion Department : DCD Library ( archives ) Drilling & Completion Manager Drilling Superintendent Drilling Fluids Advisor
2 Copies 1 Copy 1 Copy 1 Copy
Elf Exploration Production : EP/T/ER/CPU
1 Copy
Page
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ELGIN /FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID /CEMENTING REVISION 00
Foreword The purpose of this document is to report the experience gathered during the drilling of the extreme high-temperature / high pressure[HPHT] wells on ELGIN / FRANKLIN field with GALAXY 1 and MAGELLAN . This is done in order to make it available to the people in charge of such particular well , but also to generate discussion on this up to date topic within drilling people with similar experience . This report describes developments in the management of drilling fluids for use in High - Pressure , High - Temperature wells . Section 1 to 8 of this present document concern the successful role of the Fluids ; Cementing and Hydraulic in the drilling phase of this project . It’s presented close to a detailed programme with the three main parts :
1. Programme / Execution 2. Achievement – 3. Experience transfer ; rules of Thumb ; Recommendations . A separated Fluids / Cementing / Environment report has been issued per well with a detailed report.
Selection of Drilling Fluid for HP/HT well : The philosophy of the mud optimisation is to improve overall drilling efficiency so the well can be economically drilled . The aim is to design mud rheology and hydraulics in such way that minimum drilling incidents and maximum drilling efficiency can be achieved . Mud selection and maintenance are absolutely essential to the successful drilling of a hostile environment with BHP over 1200 bars and bottom hole temperature in excess of 200 °C . The deliberate choice of an invert emulsion presents obvious advantages for well integrity . The co-operation between EEUK ; ELF Exploration Production , mud Laboratory and the drilling fluids supervision are essential to obtain the most from this drilling fluid . The chosen XP07 mud system developed by Baroid should be capable of satisfying all of the following critical issues : • • • • •
Minimal rheology through a low kinematic viscosity of the base oil . Medium but not progressive thixotropy Good suspending characteristics to avoid sagging of weighting materials . High resistance & stability to contaminants under HP / HT conditions . Efficient sealing of the porous and permeable formation with Over-pressure up to 88 bars in static across the reservoir , and to 150 bars in front of the Palaeocene sandstone . • Good lubrication . Selection of Cementing company for HP/HT well : The technical results showed that the two contractor’s Dowell and Halliburton , were competent with the qualification exercise and ELF specifications for the HP/HT challenge .
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ELGIN /FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID /CEMENTING REVISION 00
t Due to the extreme conditions and the limit of the present technology in this range of temperature , it was decided to keep the both major cementing contractor’s on the separate rig . The needs for optimisation , adjustment and correction of the current practices , innovation , Engineering and improvements was the key factor of the decision . It was considered that by having two contractors the services would be kept at a high level with : • A long term competition • The involvement of two engineering instead one . • The gain of a valuable expertise . This report contains information on how the entire cementing process was optimised for HPHT field development . Improvement to the equipment , the slurry testing , the placement and bond logging procedures are presented .
Elf are developing a “ DMS which , among other things allows wells to be planned , drilled and performances analysed so that “ lessons learned “ are carried forward into subsequent wells . This philosophy was applied to the drilling of these 11 HPHT wells with ELF and BAROID off and on shore personnel involved at the planning stage , drilling , monitoring and recording phase , and evaluation / analysis of performances . Programmes and pre-spud meetings provided the link from planning to drilling , the Final well Report and debriefing meetings from drilling to evaluation . Agreed recommendations carry “ the lessons learned “ into the planning of the next well . A “ HPHT “ Best practices “ Book is being developed for inclusion into the DMS and is designed to bridge any gap in the HPHT drilling schedule .
The pre-planning phase involved the ELF Drilling Team in ABERDEEN , ELF Research Centre in FRANCE and the Mud Company BAROID with field proven Synthetic Mud system .
E LF’s D rilling M anagem entSystem
Pre-Spud Meeting Programs DRILL MONITOR RECORD
PLAN D.M.S
Best Practices Lessons Learned September, 99
EVALUATION & ANALYSIS
FWR & Debriefing Meeting
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ELGIN /FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID /CEMENTING REVISION 00
t Personnel. Team building and competency were key issues at the start on the project and minimising personnel turnover as the project progressed was another.
MUD & CEMENTING
Geology Sea bed 140m
Mud 30" CP at 200m
Nordaland Group
36" Phase Mud Type S.W + Hi Vis Pills 26" Phase
Deviation 0 to 15° 20" casing @ 900m Hordaland Group
Mud Type: Bentonite + Gel
Cement 30" casing Lead slurry 1.55SG Neat cement 1.92SG or XLITe 1.56SG 20" casing: G+Silica Lead slurry 1.44SG Neat cement 1.92SG TOC surface
MW: 1.10/1.19 SG 17½" Phase
13 3/8" casing:
Mud Type: SBM: XP07 or ESTER
G + 35% Silica
+/- 1600m
Lead slurry 1.66SG Neat cement 1.92SG
MW: 1.55/1.65 SG
Paleocene Balder +/- 3300m Sale +/- 3350m Lista +/- 3400m Andrew +/- 3480m Ekofisk +/- 3680m
Tor +/- 3800m
TOC surface
Deviation 20 to 40° 13 3/8" casing @ 3600m 72# p110
Upper Cretaceous
BHST: 145°c 12¼" Phase
Hod +/- 4350m
Mud Type SBM: XP07 MW: 1.35 to 1.70 SG
10 3/4" x 9 7/8"casing G + 35% Silica Lead slurry 1.66SG Neat cement 1.92SG TOC +/- 200m above Xo 9 7/8" x 10 3/4"
Herring +/- 5100m Plennus Marl +/- 5280m Hydra +/- 5290m
Lower Cretaceous Rodby +/- 5390m Sola +/- 5440m Valhall +/- 5500m Kimmeridge Clay Heather +/- 5560m Franklin sands
Pentland
Deviation 20 to 0° 9 7/8" x 10 3/4" @ 5200m 66.9# Q125 - 110.2# C110
Deviation +/- 0° 7" Liner @ 5900m 42.7# 125.25 Cr
BHST: 180°c 8½" Phase Mud Type SBM: XP07 MW: 2.15 to 2.17 SG
BHST: 180°c
7" Liner G + 35% Silica Neat slurry: 2.30 SG
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Contents VOLUME 1 1
36”(or 42” x 36”) SECTION
1.1
Purpose
1.2
Drilling procedure
1.3
Expected problems
1.4
Drilling fluid
1.5
Experience
1.6
30" (or 30”x 36”) casing and cementing
1.7
Experience
2
26” SECTION
2.1
Purpose
2.2
Expected problems
2.3
Drilling fluid
2.4
Experience
2.5
20" casing and cementing
2.6
Experience
3
17 ½” or 16” SECTION
3.1
Purpose
3.2
Expected problems
3.3
Drilling fluid – Experience - Hydraulic
3.4
Recommendations ( Table ) - Borehole Stability in the Hordaland
3.5
14” x 13 3/8” casing and cementing
3.6
Experience – Recommendations ( Table )
3.7
Cementing recommendations
4.
12 ¼” SECTION
4.1
Purpose
4.2
Drilling procedure
4.3
Expected problems
4.4
Drilling fluids – Experience - Hydraulic
4.5
Recommendations ( Table )
4.6
10 ¾ “ x 9 7/8” (casing or Liner ) and cementing
4.7
Experience
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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4.8
Recommendations ( Table )
4.9
Temperature simulation
5.
8 ½” SECTION – HP/HT
5.1
Purpose
5.2
Drilling procedure – Hydraulic Tests
5.3
Expected problems
5.4
Drilling fluids - Hydraulic
5.5
Experience - Recommendations ( Table )
5.6
7” ( or 7”x 4 1/2” ) liner and cementing
5.7
Experience
5.8
Recommendations ( Table )
5.9
Temperature simulation – Enertech / Cemcade software
6.
5 5/8” SECTION .
6.1
Purpose
6.2
Drilling procedure
6.3
Expected problems
6.4
Drilling fluids
6.5
Experience
6.6
4 1/2” liner and cementing
6.7
Experience – Recommendations ( Table )
7.
MECHANISMS OF WELLBORE Instability in the TRANSITION ZONE
7.1
Wellbore Instability
7.2
How to recognise a well instability ?
7.3
Reasons for well instability
7.4
Guide lines – Experience
7.5
Matrix
7.6
Stragegy
7.7
Fluid Simulator - ECDELF Software
7.8
Field results – Conclusions
7.9
Hydraulic Tables
7.10
81/2” PWD Interpretation
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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8.
COMPLETION. - NON PERFORATED WELLS
8.1
Purpose
8.2
Well Clean up Procedure
8.3
Inflow test – Horner plot
8.4
Well Control – Pipe light scenario with 1.00SG fluid
9.
COMPLETION. - PERFORATED WELLS – CESIUM FORMATE BRINE
9.1
Purpose
9.2
Well Clean up Procedure
9.3
Inflow test
9.10
Experience
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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INDEX : Additives , Cement : Section , page Alkalinity : section ,page
Electic Stability [ES] : section ,page Emulsifier : section , page
Borehole stability : Section page Batch mixing : section , page Baracarb : section ,page BHCT evaluation : section ,page BHST evaluation : section , page Barite plug : section ,page Brine : section ,page
Flow rate : section , page Flash point : section ,page Fann 70 : section ,page Flow check procedure : section ,page
Cementing Practices : section ,page Cavings : Section ,page CBL records : section , page Compressive strength : section , page Contract : section ,page Compressibility : section , page Cement class : section , page Cement plug : section , page CEMCADE : section , page CESIUM brine : section ,page Channeling : section , page Chemical concentration : section ,page Centralisers : section ,page Consistometer : page , section Compatibility tests : section ,page Coring : section ,page Compressibility : section ,page
Gumbos : section , page Gels : section , page
Hydraulic : section , page High vis pill : section , page Hole cleaning : section , page Horner plot : section , page HP/HT fluid loss : section ,page Hydrates : section , page Hordaland shales : section ,page High pressure test : section ,page HP/HT cementing plugs : section ,page Hydraulic Tests : section ,page [ H2S : section ,page HP/HT Drilling practices : section ,page HP/HT Rheometer : section ,page
Displacement : section ,page Density : section , page Dye : section , page Differential sticking : section , page
Inflow test : section page ID measurement : section ,page Incentive : section ,page
ECD : section , page ESD : section , page Excess of cement : section , page Enertech : section , page ECDELF : section , page ESTER mud : section , page Evaporation : section , page
Kill mud : section , page Kimmeridge clay : section ,page
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Safety margin : section , page Sagging : section ,page Sacrificial mud : section , page Shoe track : section , page Slurry volume : section ,page Safety stock : section page Screens : section , page Shakers : section , page Solids control : section , page Swab and Surge calculations : section ,page Specific Laboratory Tests : section ,page Supercharging : section , page
Lead Slurry : section , page Light slurry : section , page Losses : section , page LOT : section , page Logistic/Supply : section , page Low vis pill : section , page LCM selection : section , page Liner cementing : section , page
Mud lab Test Mud cooler : section , page Mud system : section , page Mud pits : section , page Modeling software : section ,page
Oil on cuttings : section , page Oil Water ratio : section ,page Oil based mud procedures : section ,page Tail Slurry : section ,page TOP CEMENT : Section page Thickening time ; section , page Top job : section , page Temperature modelling : section , page Transition zone : section , page Timing : section , page Tripping Speed : section ,page Temperature reference SG : section , page
Personnel : section , page Pressure Test : section page Pumps : section , page Pumping sequence : section ,page PWD tool : section ,page Pollution : section ,page Pressure Transmission : section ,page
: section , page : section page section , page
Quality : section , page
Rig capacity : section , page Remedial cement job : section , page Rheology : section , page Retarder sensibility : section , page Stinger : section , page
Wiper trip : section , page Well Instability: section , page Wellsite procedures : section , page Well clean up : section , page Weighting agent : section ,page
: section , page : section , page : section , page Zinc Bromide : section ,page
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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1
36”(or 42” x 36” ) SECTION : Interval Max expected BHP
: +/- 140 to 230 m : 1.09 E.M.W.
1.1
Purpose : Platform wells : Install the 30” casing and the retrievable guide base structure. Pre-drilled wells : Install the 36”x 30” casing with MLS.
1.2
Drilling procedure : Drill the 36" hole to approximately 235m using a stabilised string with a 26" bit and 36" hole opener. Sea water and high viscosity gel slugs will be used to clean the hole. At the TD displace hole with 1.15 SG mud. Wiper trip before pulling out of hole. For the pre-drilled wells, open hole 42” to 15m below the mud line in one pass with 36” assembly ( i.e. 42” hole opener incorporated in the 36” string).
1.3
Expected problem : Hole cleaning / large amount of cuttings.
1.4
Drilling fluid : Sea water with viscous mud slugs and return lost at seabed. Pump at least 2 slugs of 8 - 10 m3 of viscous mud every 10m drilled or as required for hole cleaning. A 16 m³ viscous slug should be pumped around the casing depth, to sweep the hole. Before the check trip (if deemed necessary) and before running the casing, the hole should be over-displaced by 50% of open hole volume with bentonite high viscosity mud. The final displacement should be weighted to 1.15 SG to avoid any tight hole or excessive fill. During entire drilling phase, keep a kill mud reserve of 1.15 SG (one hole volume).
1.4.1
Typical composition of mud Typical composition of viscous pills: Sea water Guar Gum or Fresh water Caustic soda Soda Ash0.5 kg/m³ Bentonite
8 to 10 kg/m³
1 to 2 kg/m³ 80 to 100 kg/m³
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Typical composition of displacement mud: Fresh water Soda Ash Caustic soda Bentonite Barite CMC HVT 1.4.2
0.5 kg/m³ 1 kg/m³ 80 - 100 kg/m³ 210 kg/m³ 2 to 3 kg/m³
Typical mud characteristics Weight Funnel viscosity Required mud volume
1.4.3
Safety stocks Bulk material: Barite Bentonite Cement G
1.4.4
: 1.05 / 1.15 : > 100 sec. : 500 m³
: 150 t : 50 t : 100 t
Minimum stocks of chemicals in sacks or drums required: Caustic soda LCM F/M/C Sodium bicarbonate Soda ash CMC HV/LV Pipe free Cement accelerator (CaCl2)
1.5
EXPERIENCE
1.5.1
TYPE OF MUD USED.
:5t : 3 t/ 3 t/ 3 t :1t :2t : 3 t/3 t : 2 m³ :3t
Types Used Gel Spud mud / Guar gum / Viscous Sweeps 1.5.2
Recommended Gel Spud mud / Guar gum / Viscous Sweeps
DENSITY. Density Used
Density Recommended 2
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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1.15 Kill / Spotting fluid Unweighted spotting fluid Unweighted sweep fluid MUD BUILT.
1.5.3
1.15 Kill / Spotting fluid Unweighted spotting fluid Unweighted sweep fluid
Type & Weight Used Guar gum at 1.03 SG. Gel mud at 1.07 to 1.15 SG. Volume Built / Used 760 / 450 m3. 1.5.4.
Recommended Guar gum at 1.03 Gel mud at 1.07 to 1.15 SG. Recommended 500.0 m3.
PIT MANAGEMENT. Pit space on the Galaxy I or Magellan is generally not a problem because of the large capacity that this new generation of rig .
Recommendations:
-
RIG SELECTION : Need a large Mud pit capacity . ( 600 m³ minimum )
-
High mixing rate for bulks to the pit is necessary .
-
The pits must be selected on the basis of the valves the derrickman needs to operate for the frequent sweeps and the lines needed to spot high viscosity mud on bottom .
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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1.6
30" ( or 30”x 36” ) casing and cementing Cementing job with STINGER : - Before cementing wash cuttings around wellhead. - Check free circulation with viscous sea water. - The 30" casing (or 36”x 30”) must be cemented up to seabed or Mud Line Suspension. - To estimate the hole volume, a sea water spacer with dye will be pumped ahead the slurry, and the return will be monitored by ROV. - When the spacer is seen at the mud line ( Identification at the sea bed with R.O.V not easy ) ,the open hole volume will be assessed and slurry volume will be adapted in order to fill the annulus (provide for 200% excess on theoretical volume). Slurry volume calculations : 36” hole volume: 656.7 l/m E.A. 36”/30” volume : 200.6 l/m 5” DP inside volume: 9.05 l/m Annulus volume: 19 m³ Spacer volume: 20 m³ Tail slurry volume (200% of excess) 75 m³ Displacement (stinger) 2 m³ Fluids Design: - Spacer Sea water + Dye - Lead slurry G cement (Dyckerhoff or Lafarge ) 35% Silica 350 kg/t Sea water 1218 l/t D144 or NF5 Antifoam 1 l/t D020 Bentonite 15 kg/t Or D111 Thixotropic agent 70 l/t - Tail slurry G cement (Dyckerhoff or Lafarge ) 35% Silica Drill water D144 or NF5 Antifoam CaCl2 Cement Slurry properties : ! Lead slurry 4
350 kg/t 550 l/t 1 l/t 20 kg/t
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Density Yield Thickening Time
1.55 SG 1740 l/t 6h00 - 8h00
! Tail slurry
Density SG Yield Thickening Time Compressive strength
1.90 1006 l/t 4h00 - 5h00 > 100 bar in 24 h
Consumption expected: G+S Antifoam Bentonite CaCl2 Thixotropic agent
Cmt + Silica
92 t 80 l 250 kg 1150 kg 1100 l
When cement operation has been successfully verified by ROV, stop pumping slurry and displace with sea water until top of cement inside 30" casing is approx. 5 m above the shoe. Depending on the quality of the primary cementing job, a cement top job may have to be performed. In case of MLS system, displace sea water + retarder to wash the MLS equipment.
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1.7
EXPERIENCE :
Surface and conductor casings provide the foundations for the construction of an oil /gas well Cement plays a major role in re-enforcing the casing in the formations near the surface that are weak and non-consolidated .To address and minimise these problems a new Cement blend has been developed giving a high strength at a low temperature ( +/- 10 °C ) with a nominal weight of 1.45 / 1.56 SG . This slurry is Thixotropic with a gelling period of less than an hour ( in static conditions ) .
Recommendation : - The X-Lite blend can eliminate remedial jobs , reduce W.O.C time . -
Use Class G cement without any Silica , no impact on the casing design ( thermal degradation in production phase )
- Identification of Dye with sea water at sea bed with R.O.V is very challenging . - Volume to be pumped as a minimum is : 80 m³ . CEMENTING PROCEDURE Applied on F3 & 29/4D-4 : Ref : { HALLIBURTON Design X-Lite Blend } - Running Procedure and centralisation : ( see UWG detailed procedure ). Note : The casing will be filled up with sea water . Pumping Sequence : 1-
25 m³ of Sea water +Sapps to break gels
2-
Spacer 500 E+ : 15 m³ ( see Hallibuton formulation ) SG = 1.30
3-
3 / 5 m³ of Sea water + fluorescene
4-
Mix and pump 75 m³ of X-Lite slurry : SG =1.52 @ surface - 1.56 SG @ bottom
One Annular volume +/- 26 m³ ( theoretical )Slurry yield = 1033 l/ton of X-Lite blended
Cement X-Lite Sea Water Defoamer CaCL2
1 ton 753 l/ton 1 l/ton 40 kgs/m³ of SW
Thickening Time
: 5 hours
72 tons( blended ) 39 m³ 50 liters 1560 kgs
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Compressive Strength
: 1476 PSI @ 10°C 24 hours.
NOTE : It is recommended that extra mix water is prepared for X-Lite slurry and that the slurry is mixed and pumped until all the X-Lite Blend has been used . Contingency Tail Slurry design . If after pumping all the X-Lite slurry there are still no returns at sea bed , the X-Lite mix water can be used to prepare a 1.90 SG slurry mixed with Lafarge G+S .See formulation attached . X-Lite slurry is THIXOTROPIC with a Gelling period of less than an hour ( STATIC conditions ) Thus any prolonged shutdowns must be avoided . 5-
Displacement with sea water at 2000 l/min .
Monitor continually the return with ROV .If there is no sign of cement return , the volume will be limited to 4 times the theoretical annulus volume . A complementary cementation will be made after cement has set .( a formulation with G+S will be used as tail slurry ) if losses/problems whilst drilling 26” section . Check for back flow . If there is some return , check volume and pump same volume .Wait for cement samples . Differential pressure = + 2 bars ( positive ) 6 - Timing : Mixing + Pumping Slurries Displacement N° 1 Safety factor Total
= 100 min = 3 min = 60 min = 163 min
7 - Excess volume versus hole volume :
Estimated Diameter
40 “ 42 “ 44 “ 46 “
Volume Planned
Annul. Volume hole/casing
Slurry Volume
350 l/m 432 l/m 518 l/m 608 l/m
36 m³ 44 m³ 53 m³ 62 m³
7
75 m³ 75 m³ 75 m³ 75 m³
Excess in %
110 % 70 % 41 % 20 %
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8 – Well Recap : Lead Pumped
Tail Pumped
22/30 – C G4
20 m³ @ 1.55 SG
66 m³ @ 1.92 SG
22/30 – C G5
27 m³ @ 1.55 SG
22/30 – C G6
Total
Remarks
Top Job
Wells 86 m³
Observe return after 59 m³ pumped
70 m³ @ 1.92 SG
97 m³
21 m³ @ 1.55 SG
73 m³ @ 1.92 SG
94 m³
22/30 – C G7
21 m³ @ 1.55 SG
73 m³ @ 1.92 SG
94 m³
22/30 – C G8
21 m³ @ 1.55 SG
75 m³ @ 1.92 SG
96 m³
No return of spacer observed Return seen after 65 m³ pumped Use G neat – Return seen at the sea bed Use G neat – No return clarified identified
29/5 B – F1
22.5 m³@1.55 SG
48.5 m³@ 1.92 SG
71 m³
29/5 B – F2
22m³ @ 1.55 SG
70 m³ @ 1.92 SG
92 m³
29/5 B – F3
X-Lite 78 m³ @ 1.52 SG
Followed by 11 m³ of Tail slurry
89 m³
29/5 B – F4
X-Lite 84 m³ @ 1.52 SG 21 m³ @ 1.55 SG
Followed by 17 m³ of Tail slurry 70 m³ @ 1.92 SG
101 m³
X-Lite @ 1.52 SG
17 m³ @ 1.90 SG
109 m³
29/5 B – F5 29/5 B – F6
92 m³
8
No No Unable to pump through the line Not able to pump through the line Pump 13 m³ top job
Good return at the sea bed
Pumped through the line 29 m³ 1.90 SG
No return clrealy identified Top cement inside 30” CP found 20 m above shoe ROV failure – Unable to check return
Pumped 27 m³ of tail slurry . Pumped 25 m³ of tail slurry
91 m³ Unable to see return
No
29/5b FRANKLIN - 36" OPEN HOLE / 30" CASING CEMENTATION Well Date Top of cement Casing shoe Height BHST BHCT Type of slurry Theoritical slurry volume Excess Total slurry volume Weight of cement (G+S) Slurry weight Cement Silica flour Water Additives
29/5b-F1 01/02/1998
29/5b-F5 16/02/1998
29/5b-F2 19/02/1998
29/5b-F3 28/09/1998
29/5b-F4 04/01/1999
29/5b-F6 15/10/1999
140 229 89 10 10
140 229 89 10 10
140 229 89 10 10
140 230 90 10 10
140 230 90 10 10
140 230 90 10 10
m m m ºC ºC m³ % m³ ton sg
% type
lead 22.4
tail 22.4
lead 22.4
48.3 65 1.92
22.4
220 22.4 17 1.55
tail 22.4
lead 22.4
48.3
22 17 1.55
220
lead 22.4
70 90 1.92
78 80 1.52
300
107 1.55
tail 22.4
1.92
tail none
lead 22.4
11 20 1.92
97 80 1.52
300
tail none
lead 22.4
20 20 1.92
92 89 1.52
420
tail none 400 17 17 1.92
Lafarge G 35
Lafarge G Lafarge G Lafarge G Lafarge G Lafarge G X-Lite Lafarge G X-Lite Lafarge G X-Lite 100 35 35 35 35 35 35 35 35 1/3fresh 2/3sea Sea 1/3fresh 2/3sea Sea 1/3fresh 2/3sea Sea Sea Sea Sea Sea Sea Sea 2.5% Bento 2.5% Bento 2.5% Bento 3% CaCl2 2% CaCl2 3% CaCl2 2% CaCl2 3% CaCl2 2% CaCl2 3% CaCl2 3% CaCl2 3% CaCl2 3% CaCl2 3% CaCl2 3% CaCl2
l/ton or %
Thickening time (70BC) Compressive strenght 12 hr Compressive strenght 24 hr Flow pattern Spacer Plug type Remedial jobs
hr:min PSI PSI type sg type
18:38
06:50
50 695 laminar laminar Sea water/mica/fluo 1.03 Stinger 1 remedial + 1 top job
18:38
06:50
50 700 laminar laminar Sea water + dye 1.03 Stinger 1 top job
18:38
06:50
50 695 laminar laminar Sea water/mica/fluo 1.03 Stinger 2 remedial + 1 top job
05:03 03:28 830 520 1500 900 laminar laminar Spacer 500E+ 1.30 Stinger None
05:10 02:44 420 350 930 670 laminar laminar Spacer 500E+ 1.30 Stinger None
05:08 03:25 500 300 1100 700 laminar laminar Spacer 500E+ 1.32 Stinger None
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26” SECTION
Interval : 230 to approx. 900 m TVD Pressure gradient : hydrostatic (EMW) Expected temperature : 36°C BHST at 900m TVD 2.1
Purpose : To set the 20" casing at +/- 900m TVD BRT, above the under compacted clays and deep enough to cover all the unconsolidated sands. LOT : 1.80 SG EMW expected - 1.55 SG EMW required.
2.2
Expected problems : Severe losses in the sands @ +/- 280 m .Large mud capacity is required . Hole cleaning. Running 20” casing
2.3
Drilling fluid: This section can be drilled using a simple GEL/CMC drilling fluid. Down to a depth of 600 m where mud making clays are encountered a bentonitic/CMC system will be used. Thereafter below 600 m bentonite additions will cease and dilution pre mixes of seawater/CMC will be sufficient to control system properties.
2.3.1
Typical composition of mud: Above 600 m Sea water Caustic soda Soda Ash Prehydrated Bentonite CMC LV CMC HV Barite Below 600 m Sea water Caustic soda Soda Ash CMC LV CMC HV Barite
2 - 3 kg/m³ as required 30 - 50 kg/m³ 3 - 4 kg/m³ 2 - 3 kg/m³ as needed
2 - 3 kg/m³ as required 4 - 5 kg/m³ 2 - 3 kg/m³ as needed
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2.3.2
Typical mud characteristics Above 600 m Weight Funnel viscosity PV YP Gels 0/10 Filtrate API pH
: < 1.13 : 45 - 50 : 15 - 20 : 20 - 25 : 6 - 10 / 10 - 25 : 15 down to 8 cc : 9.5
Below 600 m Weight Funnel viscosity PV YP Gels 0/10 Filtrate API pH Required mud volume 2.3.3
: < 1.13 : 45 - 50 : 20 : 20 : 6 / 20 : 8 cc : 9.5 :2000 m³
Safety stocks Bulk material Barite Bentonite Cement G + Silica Flour
: 150 t : 50 t : 100 t
Material in sacks or drums Caustic soda
:5t
LCM F/M/C
: 3 t/ 3 t / 3 t
Sodium bicarbonate Soda ash CMC HV/LV Free pipe CaCl2
:1t :2t : 3 t/ 4 t : 2 m³ :3t
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2.3.4
Maintenance Recommendations - A significant dump and replace regime will be need to be employed to ensure control of mud rheology and density. It is critical that the mud density is controlled below 1.13 SG while drilling to avoid losses under dynamic conditions. - While drilling ahead, sweep the hole with 10 m³ of bentonite slurry prior to each connection to ensure hole is kept clean. These sweeps can be incorporated into the active system to assist in “mudding up”. Once mud making clays are encountered these pills can be replaced by CMC Hi Vis to allow easier control MBT levels in the mud system. - Density should be controlled under 1.13 SG while drilling. Increase to 1.15 SG prior POOH to run casing. - Flow rates must not be reduced unless it is not possible to keep up with hole mud losses. Pump output is recommended to be > 4000 l/min. - Instantaneous penetration rates should be controlled less than 90 m/h. Average penetration rates should only be reduced if the pump rate is lowered. - Fluid loss should be maintained initially at less than 15 cc, reducing to 8 cc below 600m to control swelling of the reactive shale. Increased additions of CMC in the premix should control it. - Hi-Vis sweeps should be used while drilling. It is recommended that a 10 m³ sweep should be pumped such that is CLEAR of the BHA on the connections or as required. These sweeps can be formulated with bentonite above 600 m then using CMC Hi-Vis. - In case of downhole losses under 5 m³/h add LCM to the system. If the losses increase over 5 m³/h pump a pill of LCM as follow: Mud from the system CMC Hi-Vis for VM>150 LCM F : 50 kg/m³ LCM M : 50 kg/m³ LCM C : 50 kg/m³ - NUT PLUG F , BAROFIBER “M” , MICA “M” ARE THE PRIMARY LCM
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2.4
2.4.1
2.4.2
2.4.3
2.4.4
Experience :
Type of mud used : Type Used Seawater and sweeps Bentonite/polymer
Recommended Not recommended Bentonite/polymer
Volume Built / Used @ +/- 2300 m³
Recommended m3 as required
Density Used 1.15-1.18
Density Recommended < 1.18 SG
Type & Weight Used None
Recommended None
Density
Kill mud used.
Desilter To minimise the sand content and assist in controlling the mud weight use the mud cleaner as a desilter, i.e. dump cone discharge. Have a suitable number of spares on the rig. Service the mud cleaner prior to starting the phase.
2.4.5.
Shaker Screens The gumbo shakers ( scalpers ) were dressed with 20 over 40 mesh screens. As soon as screens became available the shakers were changed to 10 over 20 mesh screens so that the shakers could handle the volume. The THULE shakers were redressed with the last of the coarse shaker screens in stock on the rig. The configuration of the bottom deck of the shakers was: Top Section : Shaker #1 Shaker #2 Shaker #3 Shaker #4
84 x 84 x 105 x 105 52 x 84 x 105 x 105 52 x 84 x 105 x 105 52 x 105 x 105 x 105
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Shaker #1: 105 x 105 x 105 x 105 Shaker #2: 84 x 84 x 105 x 105 Shaker #3: 84 x 84 x 105 x 105 Shaker #4: 84 x 84 x 105 x 105 Increase the number and selection of shaker screens kept in the store on the rig. 2.4.6.
Pit management. No problems were encountered.
2.4.7.
Personnel During top hole drilling it is helpful to have extra roustabouts to help man the shaker house.
2.4.8
Drill Water Have the maximum amount of drill water on hand for pre-hydration of bentonite when drilling top hole.
2.4.9
Pump rate Do not exceed 4,200 litres per minute with the pumps. The surface equipment cannot process the mud at the higher pump rates. Too much drilling fluid is lost from the shakers at the higher pump rates.
Recommendations: -
GUMBOS OBSERVED AT THE SHAKERS : ADDITION OF SEA WATER IS REQUIRED . Losses :
-
PARTIAL TO TOTAL LOSSES @ 280 M : CONCENTRATION OF 150 KGS/M³ ( 15 /
SPOT HI VIS PILL FOLLOWED BY A LCM PILL AT A 20 M³ ) .
-
SET CEMENT PLUG TO CURE LOSSES WITH CACL2 IF NO SUCCESS WITH LCM .SPOT LCM PILL ( 150 KGS/M³ ) AHEAD A HI-VIS PILL FOLLOWED BY A SLURRY WITH 2% OF CACL2 -
-
RUNNING 20” CASING AT TD : PUMPED 15 M³ OF PILL ( CAUSTIC / DETERGENT ) 70/80 KGS/M³ OF NUT COARSE @ 1.19 SG
FOLLOWED BY
30 / 40
M³ OF MUD
–
DISPLACE WELL WITH 90 M³ HI-VIS MUD @ 1.19 SG -
-
PIT VOLUME : RIG SELECTION , ENSURE THAT THE MINIMUM CAPACITY IS 600 M³ .
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2.5
20" casing and cementing (shoe at approx. 900 m TVD) Cementing job with long STINGER : - Due to the high porosity / high permeability of the sands drilled and the risks of losses the 20" casing will be cemented with two slurries: • Tail slurry 1.90 SG from the 20” shoe to +/- 700 m • Lead slurry to the seabed or MLS - To estimate the hole volume, a sea water spacer with dye / LCM will be pumped ahead the lead slurry, and the return will be monitored by ROV. - When the spacer is seen at the mud line, the open hole volume will be assessed and the slurry volume will be adapted accordingly in order to fill the annulus. Slurry volume calculations 26” hole volume: 342.5 l/m E.A. 26”/20” volume : 139.4 l/m 5” DP inside volume: 9.05 l/m Spacer volume: 20 m³ Lead slurry volume (100% of excess) 175 m³ Tail slurry volume (50% of excess) 50 m³ Displacement (stinger) +/- 10 m³ Fluids Design: - Spacer Sea water + Dye XCD Polymer Barite
10 to 15 kg/m³ For 1.25 SG
- Lead slurry G cement (Dyckerhoff or Lafarge ) 35% Silica 350 kg/t Drill water / Sea water 1681 l/t Antifoam 1 l/t D075 or Bentonite Extender 35.5 kg/t or 2% BWOC
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- Tail slurry G cement ( Dyckerhoff or Lafarge ) 35% Silica 350 kg/t Drill water 546 l/t Antifoam 1 l/t D060 or Halad 344 FLC 10 kg/t or 0.35% BWOC Cement Slurry properties : - Lead slurry Density Yield Thickening Time
1.44 SG 2161 l/t 6h00 - 7h00
- Tail slurry Density Yield Thickening Time Compressive strength
1.92 SG 999 l/t 5h00 > 150 bar in 24 h
When cement operation has been verified as successful by ROV or return identified at the wellhead , stop pumping slurry and displace with sea water until top of cement inside the 20" casing is approx. 7 m above the float. Bleed off pressure and check for back-flow before unlatching running tool and pulling out of hole. In the case of MLS, flush the 30”x 20”annulus above the MLS by pumping sea water or a solution of sugar through the ports. During this job the flushing pressure should not exceed pumping pressure at the end of displacement. A remedial cement job will be considered if the slurry is not back to the mud line or surface.
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2.6EXPERIENCE : ( see Example below )
20” CEMENTING Procedure : Running Procedure and centralisation : ( see UWG detailed procedure + centralizer placement). Note : The casing will be filled up with mud 1.15 / 1.16 SG . Stinger will be run to +/- 10 m above float collar + Vetco circulating head will be used for cement job . ( Stinger seal assembly is only available as a back up ). Circulation at bottom to reduce mud rheology –
Pumping Sequence : 1 - Spacer to break gels - 14 m³ with QBII or DESCO 2 - Spacer to be used : +/- 48 m³ of Spacer 500 - ( equivalent of tail slurry volume ) Composition : Fresh water + Viscosifier ( 32 kg/m³ ) + Barite -SG = 1.30 Reminder : On F4 - Good interface between thin spacer and viscosified spacer , but poor interface between spacer and lead slurry .( 20 m³ contaminated ) 3 - Mix and pump Lead slurry : SG =1.45 Total volume +/- 180 m³ ( with Excess ) Slurry yield = 2126 l/ton Cement G ( Lafarge ) + 35 % Silica Water (sea water)+50% Drill water DefoamerNF5 L Bentonite CaCl 2
1 ton 1660 l/ton 1 l/ton 3% 2%
114 tons( blended ) 140 m³ ( 3 mud pits ) 80 litres 2400 kgs 1600 kgs
Thickening time = 12 h 30 min + Compressive Strength 10 bar in 24 hours 4 - Mix and pump Tail slurry : SG =1.92 Volume = 48 m³ Slurry yield = 982 l/ton Cement G ( Lafarge) + 35 % Silica Fresh water Defoamer Halad 344 Thickening time = 5 h at 100 BC Compressive Strength
1 ton 532 l/ton 1 l/ton 0.35 %
65 tons 25.5 m³ ( 160 bbls ) 50 liters 168 kgs
87 bar in 12 hours 154 bar in 24 hours @ 30°C
5 - Displacement with mud SG =1.15 at 1500 l/min8
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Monitor continually the return at flow line in case of channeling ( Ref. On G5 & F4 ). Check for back flow . If there is some return , check volume and pump same volume .Wait for cement samples . Final static pressure should be 45 bars at the end of displacement. 6 - Timing : Mixing + Pumping Slurries Displacement N° 1 Safety factor Total
= 235 min = 10 min = 60 min = 305 min
7 - Excess volume versus hole volume : Theoritical Annulus volume + Overlap ( 30” X 20 “ ) + Shoe = 140 m³ -
Diameter 26 “ 28 “ 29 “ 30 “
Annul. Volume hole/casing 142 l/m 192 l/m 220 l/m 250 l/m
Equivalent Volume Planned Equivalent Excess in Slurry Volume % - Open Hole 140 m³ 173 m³ 192 m³ 213 m³
228 m³ 228 m³ 228 m³ 228 m³
89 % 42 % 25 % 10 %
The first number is for an O.H diameter of 26” and the last one for 30” . Anything outside these limits should be considered as suspect , like channeling , losses , … Reminder : On “F4 “ a contaminated return has been reported after pumping a volume of 169 m³ of Lead + Tail Note : It has been very difficult to check the losses on F4 cement Job . Could you inform everyone ( mud loggers , Derrick-man & Mud Engineers ) that this issue is critical as the 20” casing is our foundation to handle all the weights as the 30” CP cement job is not reliable .
Recommendations : - No wiper trip , Back reaming systematically before running casing - The use blend cement is required (“ G + 35% of silica “ ) - Pump a pill to break the gel before the cement job .( SAPP ) - Use Stinger with stab-in device in case of surface leak .( stab in shoe ) -
Well volume : gauge hole +/- 20 %
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RECAP : Well 29/5 - B F1 29/5 - B F2 29/5 - B F3 29/5 - B F4 29/5 - B F5 29/5 – B F6 22/30 - C G4 22/30 - C G5 22/30 - C G6 22/30 - C G7 22/30 - C G8
Lead 134 m³ 120 m³ 135 m³ 103 m³ 133 m³
Tail 48 m³ 49 m³ 48 m³ 45 m³ 52 m³
Total 182 m³ 169 m³ 175 m³ 148 m³ 185 m³
Comments Water bushing was leaking Spacer back to surface Return cement Return cement Return cement ( access deck )
175 m³ 175 m³ 128 m³ 118 m³ 119 m³
54 m³ 48 m³ 48 m³ 46 m³ 48 m³
229 m³ 223 m³ 176 m³ 164 m³ 167 m³
No cemt in the shoe track , Pb with plug
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Spacer w/Breaker , Good return @1.40 sg
idem Lead return @ 1.43 SG
29/5b FRANKLIN - 26" OPEN HOLE / 20" CASING CEMENTATION Well Date Top of cement Casing shoe Height BHST BHCT Type of slurry Theoritical slurry volume Excess Total slurry volume Weight of cement (G+S) Slurry weight Cement Lafarge G Silica flour Water Additives
m m m ºC ºC m³ % m³ ton sg % % type
l/ton or %
Thickening time (70BC) hr:min Compressive strenght 12 hr PSI Compressive strenght 24 hr PSI Flow pattern Spacer type sg Plug type Displacement type
29/5b-F1 12/02/1998
29/5b-F2 01/03/1998
29/5b-F5 09/03/1998
29/5b-F3 04/10/1998
29/5b-F4 11/01/1999
29/5b-F6 22/10/1999
Surface 905
Surface 907
Surface 905
Surface 899
Surface 909
Surface 911
670
205
672
36 20
205
670
36 20
205
670
36 18
199
670
209
670
36 18
36 20
211 36 18
lead 83 60 120 74 1.44
tail 35 50 49 66 1.92
lead 83 60 120 74 1.45
tail 35 50 49 66 1.92
lead 83 76 133 82.1 1.45
tail 35 60 52 71.5 1.92
lead 83 70 135 92 1.45
tail 35 42 48 65 1.92
lead 83 30 103 65 1.45
tail 35 42 48 62 1.92
lead 83 30 102 60 1.45
tail 35 30 40 60 1.92
100 35 ½fresh ½sea 3% Bento 2% CaCl2 1 lit NF5
100 35 Sea
100 35 ½fresh ½sea 3% Bento 2% CaCl2 1 lit NF5
100 35 Sea
100 35 ½fresh ½sea 3% Bento 2% CaCl2
100 35 Sea
100 35 ½fresh ½sea 3% Bento 2% CaCl2
100 35 Fresh
100 35 ½fresh ½sea 3% Bento 2% CaCl2
100 35 Fresh
1 35 ½fresh ½sea 3% Bento 2% CaCl2
1 35 Fresh
0.35%Hal-344
13:19
08:30
70 2100 laminar laminar Spacer 500E+ 1.25 Stinger Sea water
0.35%Hal-344
13:20
09:20
280 2200 laminar laminar Spacer 500E+ 1.28 Stinger Sea water
0.35%Hal-344
13:20
09:00 1300 280 2200 laminar laminar Spacer 500E+ 1.30 Stinger Sea water
0.35%Hal-344
12:11
04:51 1100 130 2200 laminar laminar Spacer 500E+ 1.25 Stinger Sea water
0.35%Hal-344
15:12
05:32
90 1650 laminar laminar Spacer 500E+ 1.25 Stinger Sea water
0.3% Hal-344
15:50
06:30 670 90 1900 laminar laminar Spacer 500E+ 1.25 Stinger Sea water
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3.
17"1/2 or 16” SECTION Interval Max expected BHP LOT at 20" shoe Expected temperature
: From 900 to +/- 4000 m( MD ) +/- 3600 m (TVD) : 1.47 EMW (Hordaland) : 1.85 EMW required (for 15 m³ limited kick) : 135°C BHST at 3600m TVD
If the LOT is under 1.85 EMW at the 20” shoe, a remedial cement job will be performed. 3.1
Purpose: Set the 13 3/8” casing below the Palaeocene just into the Tor formation to cover overpressured Hordaland Shales and the potentially weak Palaeocene sand.
3.2
Expected problems - Hole stability in the Nordland and Hordaland clays which are water sensitive , dispersive and potentially over-pressured. - Danger of differential sticking in Palaeocene sandstone , and seepages losses . - Hole cleaning in deviated wells.
3.3
Drilling fluid – Experience – Hydraulic This hole section will be drilled using a synthetic oil base mud with mud weight 1.55SG.
3.3.1
Typical composition of mud ( 1.55 SG , 65/35 , 160 000 ppm WPS) XP-07 EZ MUL 2F Lime DURATONE HT Water GELTONE Calcium Chloride Barite RM 63
(Base Fluid) (Primary Emulsifier) (Ca(OH)2) (Fluid Loss Control)
447 l/m³ 32 - 45 l/m³ 11.5 kg/m³ 12 - 19 kg/m³ 246 l/m³ (Viscosifier/Gelling Agent) 5 kg/m³ (CaCl2) 110 kg/m³ (Weighting Agent) 633 kg/m³ (Rheology Modifier) 1.5 - 2 l/m³
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3.3.2
Typical mud characteristics Weight PV YP YS Gels 0/10 Filtrate API Filtrate HP/HT E. S. Cl-(Water Phase Salinity) H/E Excess of Lime
3.3.3
: 1.55 – 1.60 : ALAP : 20 - 25 lbs/100ft³ : 8 - 10 lbs/100ft³ : 15/25 - 20/30 : 0 cc : 3 - 4 cc : > 400 V : 160 g/l : 65/35 - 70 /30 : 10 g/l
Safety stocks Bulk material Barite Cement G + Silica Flour
: 150 t : 100 t
Material in sacks or drums BARACARB 50/150 : 3 t/ 3 t Ultra seal :3t 3 Chemicals to mix 300 m of synthetic base mud Kill mud / Synthetic Base Oil Kill mud 1.75 SG Base Oil 3.3.4
: 50 m³ : 150 m³
Recommendations Displacement to SBM: SBM/Base fluid should not be brought on board until platform wide containment measures have been fully discussed with all rig crews and implemented. No base fluid spacer should be pumped between the sea water and the XP-07 mud. Its inclusion will only add to the volume of contaminated interface. A small degree of contamination will take place. Divert the interface to a reserve pit on its return to surface. Condition the volume for later use in the 17 ½ “section. The first 10 m³ of XP-07 mud should contain one drum of oil wetting agent. The XP-07 mud system will be cold during displacement operation (YP>35 lbs/100ft²). The rheology will be reduced as the temperature of the circulating system increases.
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Dress the shale shakers (screens) accordingly to avoid whole mud losses at the shale shakers.
Until the XP-07 has been sheared through the bit and it’s temperature has increased, utilise coarse screens ( + 84 mesh) on the shale shakers to avoid unnecessary surface losses. Note that if the mud is a reconditioned stock then it will take less time to fully yield. If the mud is predominantly new mud then it will take longer to fully shear up and yield. As the mud heats up and becomes less viscous, the screens should be progressively changed to a finest mesh which can cope with the flow rate in use. Displace the sea water from the well with the maximum available pump rates, reducing the pump rates when the synthetic mud is close to the surface. A minimum of 600 m³ of fully-formulated XP-07 whole mud weighing 1.55 SG will be required to displace the hole and enable drilling to proceed without the need to mix new volume. An additional + 300 m³ of mud will be required during this section. By having sufficient reserve volume of premixed mud available, the mud engineer and rig crew will be free to concentrate on the maintenance of the active system while penetration rates are high. Reserves of XP-07 Base Fluid + 150m³, should be kept onboard for dilution, oilwater ratio adjustments and weight reductions. An estimate 950 m³ of XP-07 mud will be required to drill the section. 600 m³ will be shipped from town, with the balance being made offshore. - Mud weight: A review of offset wells in the area indicates mud weight up to 1.74 SG have been required to stabilise the Lower Tertiary. Some wells have experienced losses during running and cementing of 14”x 13 3/8” casing with mud densities above 1.60 SG. Formation pressure in this section are anticipated as being overpressured with the pore pressure increases from 1.08 - 1.44 SG. Experience has shown that if these shale are permitted to slough due to insufficient mud weight at the outset, rig time is likely to the lost whilst attempting to stop this occurrence by increasing mud density after the fact. An initial drill out weight of 1.55 SG is anticipated to be adequate for this interval. Further increases in the mud weight may be required to insure a stable wellbore and any indications of hole instability e.g. caving, should be addressed immediately by reviewing the mud density. This is especially true as the hole will be deviated to 25 degrees. - Possible shale shakers screen blinding due to the size/shape of Palaeocene sand grains, hence the shale shakers should be attended to all times and screens size type/shape (oblong/square), and angle changed as required to prevent surface losses. Ensure base fluid wash guns are set up and operational at the shakers. - Mud rheology: The XP-07 mud system has a good relatively flat rheological profile. This result in reduced ECD and permits greater circulating rates for given pump pressure. It is recommended to maximise hole (and riser) cleaning: • Use the highest possible pump output / annular velocities. 3
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• Keep the Yield Point at 50°C between 20 and 30 lbs/100ft² with the Plastic Viscosity as low as possible. • Optimise the low shear rheology using RM 63 and GELTONE II to suppress the formation of cuttings beds, and assist in hole cleaning by maintaining the Yield Stress between 12 and 15. • Maintain high initial gel strength giving rapid suspension of cuttings when the pumps are off during surveys, or trips. This should be combined with flat gel strength development. • Use mechanical means (e.g. wiper trips, pipe rotation, reciprocation, back reaming with the top drive, etc.) and weighted pills pumped prior to trips to assist with hole cleaning. • If a more viscous mud is required, suggest initial treatment to raise Yield Point to 28 30 and initial to + 15. • If further viscosity increases are deemed necessary to improve the muds carrying capacity, increase the Yield Point and 6 RPM reading in increments of 5 lb/100ft². An upper limit of 30 should be considered the upper limit to ensure optimisation of hydraulics. - Pumping rates: Bottom hole assemblies must be optimised such that pressure limitations allow for pump rates of over 4,300 l/min. In addition, bit (e.g. PDC), MWD and downhole motors (if used) should have a maximum possible I.D.’s and must be rated for use with pump rates of this magnitude. The use of 6 5/8” and/or 5 ½ “ drill pipe is recommended to enable 4,300 l/min to be achieved. Note particularly that pumps should be started slowly on running into the hole to avoid excessive surge pressures on the formation which could cause pressure fluctuations and destabilise the hole. - Penetration rates: Penetration rate must be controlled to minimise the accumulation of cuttings beds and prevent overloading in the annulus which would be detrimental to hole cleaning and would exacerbate hole pack-off as well as loss of return /induced fracturing. Additionally, bit balling, as related to solids crowding in the mud, is also affected by drilling rates. Very high instantaneous ROP will cause bit balling , hence the ROP must be controlled not only on an average basis but also over short drilling periods. - Hole cleaning: To ensure that good hole cleaning is achieved in this section, it is recommended that the Yield Point and Yield Stress be maintained as programmed. Pump rate should also be as recommended. Hole cleaning is a function of mud rheology, circulation rates and ROP. Any indication of failure to clean the hole adequately should be countered by increasing the circulation time on connections and before trips. Maximum allowable pump rates must be used when circulating the hole clean, do not circulate at less than drilling rates. 4
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Even with mud properties and flow rates optimised a hole cleaning problem may still occur. At the first indication of possible problems, pump a high viscosity/weighted pill (pump these pills prior the trips). This should be sized to cover 100 m of annular hole. It is recommended that a 2.0 SG weighted pill be pumped around while rotating the string > 150 rpm if possible. In the case of all pills do not stop or reduce the circulation rate before the pill(s) have been evacuated from hole. To do so will result in material dropping out of the pill and possibly avalanching downhole. All attempts should be made to isolate weighted pills on surface for re-use. Return of all pills should be monitored at the shakers, to gauge their effectiveness. The trend in the correlation of cuttings generated and seen at the surface to ROP can provide another indication of the effectiveness of hole cleaning. The mud engineers should be monitoring cuttings volumes and correlating with these drilling rates at all times. The shaker hands should also be shown what to watch for so that they can provide a speedy warning e.g. a soft sticky must means the cuttings are being reground in the well and are not being removed. - Seepage losses/differential sticking: Since mud weight increases above normal will be required to stabilise the Nordland and Hordaland shale sections, there is a risk of differentially sticking the drill-string when drilling the Palaeocene sand section. Prior to drill the sands, the mud system should be treated with 20 kg/m³ BARACARB 50 and 9 kg/m³ BARACARB 150 (Graded Marble) as bridging agents. Maintain the concentration of material in the mud by adding 1 sack of BARACARB 50 and 1 sack of BARACARB 150 per stand, while drilling the sand to ensure enough fresh material is available for bridging. BARACARB will effectively bridge opposite the porous sand and minimising the filter cake build-up, filtrate/whole mud invasion, seepage losses and differential sticking. Mud samples should be sent to town on a regular basis to check the bridging effectiveness by measuring the particle size distribution of the fluid. - Water phase salinity: It is recommended that the WPS is run at 160 g/l Cl-. Based on the offset well data on blocks in the area, this level of salinity will mean that the shale are stabilised without taking so mush water into the mud and having to adjust the SWR. Starting with 160 g/l Cl-, adjustments will be made as dictated by cuttings integrity and indications of water gains from the formation by way of osmosis. - Alkalinity: the alkalinity should be maintained in the range of 10 - 15 kg/m³. Depletion and/or acid gasses may necessitate regular additions of lime to maintain this level. - Solid control: It is essential that the maximum use be made of all available solids control equipment. Run the shale shakers utilising the finest mesh screen possible. Ensure that
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Shale shaker screens are being effectively used by analysing the LGS/HGS ratio in both the
input and output. Sand blinding has been experienced on the most of the surrounding wells, hence the selection of shale shaker screen sizes will be critical to avoid any surface losses of this expensive mud system. It is recommended that 120 mesh be used initially and as soon as possible they should be changed for 145/165. However this should be reviewed in the light of mud properties and the nature of the solids on the screens at the time. Shale shakers have to be attended to at all times, and screens changed as circumstances dictate to keep the optimum screen size on the shakers. It is also suggested that both oblong, square and pyramidal screens be available on the rig site and various combinations are tried to minimise sand blinding. The base fluid wash gun should be available prior to drilling the 17 ½“ hole. - Synthetic Oil on Cuttings: For the DTI Department of the Trade and Industry the SOC Synthetic Oil on Cutting are to be performed every 300 metres or daily, whichever is the sooner. The average quantity of oil on the cuttings for each well must be kept under 10%. i. cuttings samples will not be taken while coring. ii. cuttings samples will not be taken while drilling cement. iii. prior to take a cuttings sample, the shakers must be washed down with a high pressure oil gun. iv. if the retort analysis gives a figure in excess of 120 g/kg, the procedure must be repeated using a different sample to con firm the high value. v. cutting sample will be taken from the shakers only. vi. cutting sample must be retained for onshore analytical analysis. reporting of the SOC must be issued daily and a cumulative SOC will be issued at the end of each phase and at the end of each wells.
6
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
3.3.5
Experience :
NOTIFICATION
Environmental concerns are now taking priority over technical or economical considerations in the selection of drilling mud systems for off shore uses. This trend is corroborated by the increasingly stringent regulations governing the amount of oil allowed to be discharged into the sea with drilled cuttings. On the 1/1/2001, a zero discharge limit will be imposed in the North Sea, with a four years transition resulting in a reduction of 20% per year of the tonnage of oil wet cuttings discarded to the sea, based on the 1996 year quantity. This regulation preclude or limit the use of oil base mud or force that drilled cuttings be : • transported on shore and treated to remove adhering oil. • grounded and slurryfied off shore and injected in a dedicated formation through a disposal well. Facing this scenario much efforts has gone to improve water based mud, but the drilling performances remain lower compared to those obtained while using oil base muds and PDC bits. BAROID have carried out extensive research into alternates to low aromatic mineral oil mud systems. The outcome of these researches was the development of the Petrofree invert emulsion system which exhibits equivalent properties to mineral oil base mud without the environmental inconveniences. The Petrofree shows very good bio-degradation properties, and due to this matter its discharge to sea had been allowed. This mud was first used in the years 1990 but it is very costly ( £ 1,200.00 m³ ) : • 5 time the cost of a low toxic oil base mud. • 2 to 3 time the cost of an synthetic oil base mud. ELF has been very reluctant to use this mud due to its cost. For the Elgin and Franklin developments the 17½ sections are drilled from 900 m to 3800 m with invert oil base mud. The first 2000 m are drilled in three days resulting in the generation of 1200 tons of oil wet cuttings. It is impossible to recover and store on the rig this amount of cuttings for on shore or off shore process, so they must be discarded to the sea. Due to the Elf Strategy for reducing oil discharge submitted to the D.T.I and the transition period for discharge of oil wet cuttings by using an Ester base oil , it has been decided to run for the first time in the Elf group the Petrofree mud system from BAROID.
7
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
1
Type of mud.
Type Used XP07 or Petrofree 2.
Recommended XP07 or Petrofree
Density. A density of 1.55 SG provided good hole support.( vertical hole ) Density Used 1.55 SG
Density Recommended if angle> 35° 1.60 / 1.65 SG
3.
Contingency stoks . Barite, LCM and ester stocks should be reviewed with the Elf supervisor prior starting each section. It is recommended to continue to keep these minimum contingency stocks for each future 16” section. Base Fluid Barite LCM F/M Starting Stock 326 MT 30 MT 207 m3 Minimum Contingency Stock 150 MT 3/3 MT 150 m3
4.
Rheology The average yield point was in the 25 to 35 lb/100 sq. ft. range. No tight hole attributable to poor hole cleaning was seen. PV YP Yield stress Used 32 to 54 17 to 55 7 to 15 Recommended A.L.A.P 20 to 35 12 to 15
5.
Emulsifiers and HPHT Due to the high efficiency of the mud cooler, lower then previously seen mud temperatures were recorded, resulting in slightly lower rates of evaporation. As a consequence, less water was added to the mud but additions of emulsifier to the system were essential to maintain a stable mud system. The electrical stability was kept at 600-800 volts with concentrations of EZ MUL NTE between 40 and 60 Kg/m3.
6.
Used Recommended
Primary Emulsifier EZ MUL NTE EZ MUL NTE
Electrical Stability 380 to 885 > 400
Used Recommended
HP/HT ml 1.8 to 2.0 < 4.0
Temperature deg. C 130 130
Alkanility 8
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
XP07 or PETROFREE does not require high alkalinity. Excess lime kg/m3. 0.9 to 1.5 2.0 to 3.0 4.0
Used Recommended, engineers Recommended, program 7.
8.
Evaporation. Levels of evaporation, were low throughout the interval considering the down hole temperature. Again this is due to an efficient mud cooler. Oil water ratio and water phase salinity. Base fluid / Water ratio Used Recommended
9.
10.
69 / 31 to 75/ 25 65 / 35 to 70 / 30
Low gravity solids : ESTER application Due to the temperature related expansion properties of the PETROFREE system, care must be taken when running the retort. The sample must be allowed to cool to 20 degrees Celsius and the weight of the sample at this temperature checked on the temperature vs. weight chart ( obtained with DFG+). This temperature corrected weight is then used to calculate the true LGS content of the mud. True Low Gravity solids, kg/m3. Used 35 to 138 Recommended > 150 Kg/m3
Solids Control
Mesh size used at start. Mesh size used at end
Scalper 12
Scalper 20
12
20
12
20
12
20
Recommended at start. Changing to :-
11.
Water Phase Salinity. mg/l Chlorides 128,134 to 176,942 >160,000
No.1
N0. 2
No. 3
No. 4
No. 5
125 125 100 185 185 145 94 94 94 185 185 145
125 125 100 185 185 145 94 94 94 185 185 145
125 125 100 185 185 145 94 94 94 185 185 145
125 125 100 185 185 145 120 120 94 185 185 145
125 125 100 185 185 145 120 120 94 185 185 145
Base Fluid on Cuttings. Interval average
80 /90 gm/kg 9
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
The slow ROP and the PDC bits used in the bottom section of the interval produced small cuttings resulting in a high arithmetical average for the Base Fluid On Cuttings. Data from OILTOOLS. 12.
26” Cement drill out The well was displaced to PETROFREE or XP07 mud after drilling out the cement with water base mud. A good interface was seen on the displacement and the last two cubic meters of water and the minimal interface was caught in the pits to minimise any risk of spillage. Drill out of cement. Displace to SBM only after good cement has been encountered. Drill rest of cement with SBM.
13.
Kill mud used. Type & Weight Used Not required due to programme change.
14.
Recommended Exploration well 50 m³ @ 1.75 SG
PIT Management No problems were encountered with the pits due to the adequate volumes available. The pill tank should be left free of slugs so any pills / dilution can be made up. A separate pit should be used for slugs.
RIG Selection :
The pit capacity is a major problem during this section , volume handle is around 1000 m³ .
10
FRANKLIN 29 / 5b-F5 Hydraulics analysis - 17½" hole
02/05/1999
1025
1023
5.0
3390
146
112
4
9 x 16
5
31
25
1.60
27
03/05/1999
1425
1422
2.0
3980
171
242
4
9 x 16
5
37
30
1.60
38
04/05/1999
1821
1817
5.0
4190
175
244
4
9 x 16
5
38
32
1.60
49
05/05/1999
2571
2539
25.0
4220
175
235
4
9 x 16
5
39
32
1.60
57
06/05/1999
2983
2900
29.4
4230
60
290
4
9 x 16
5
39
32
1.60
65
07/05/1999
3000
2915
4215
60
271
4
9 x 16
5
39
32
1.60
65
08/05/1999
3239
3123
26.1
4300
120
255
5
9 x 14
6
39
32
1.60
60
09/05/1999
3305
3182
25.3
3800
150
203
5
9 x 14
6
35
29
1.60
10/05/1999
3382
3252
22.5
3850
70
200
5
9 x 14
6
35
29
1.60
11/05/1999
3388
3258
3800
70
195
5
9 x 14
6
35
29
12/05/1999
3435
3435
4300
150
240
6
6 x 20
7
39
13/05/1999
3462
3330
3870
110
170
6
6 x 20
7
36
14/05/1999
3476
3343
3850
150
175
6
6 x 20
7
15/05/1999
3482
3348
3800
110
190
7
9 x 16
8
16/05/1999
3493
3359
3800
110
184
7
9 x 16
17/05/1999
3502
3368
3850
110
197
8
4 x 22
18/05/1999
3505
3370
3800
100
195
8
4 x 22
9
35
29
1.60
40
19/05/1999
3524
3387
4050
60
266
9
1x16+3x20
10
37
30
1.60
46
20/05/1999
3536
3398
4050
60
263
9
1x16+3x20
10
37
30
1.60
47
21/05/1999
3542
3404
3700
60
218
10
1x17+3x20
11
34
28
1.60
47
22/05/1999
3546
3408
4000
60
150
10
1x17+3x20
11
37
30
1.60
47
22.8
1.61
31
41
54
27
18
1.05
1.60
42
57
54
35
20
1.04
1.59+
52
73
60
40
23
1.08
1.60
59
102
58
31
20
Hordaland
1.60
71
116
58
28
18
Hordaland
1.60
71
117
57
28
17
Hordaland
1.60
68
125
55
26
17
Balder
45
1.60
56
127
50
23
15
Sele - Lista
41
1.60
56
130
48
17
13
Lista
1.60
41
1.60
57
131
48
20
13
Lista
32
1.60
51
1.61
62
138
47
21
13
Andrew
29
1.60
57
1.60
65
133
44
20
12
Maureen
35
29
1.60
49
1.60
59
134
42
18
12
Maureen
35
29
1.60
43
1.60
54
134
47
20
14
Maureen
8
35
29
1.60
44
1.60
54
135
45
20
14
Maureen
9
35
29
1.60
40
1.60
55
135
45
19
12
Maureen
1.60
54
135
47
20
15
Maureen
1.60
60
136
47
23
14
Maureen
1.60
61
136
47
23
14
Maureen
1.60
62
136
46
24
14
Maureen
1.60
62
Maureen
137
47
23
14
23/05/1999 3546.0 3408
1.60
137
47
23
14
24/05/1999 3546.0 3408
1.60
137
47
23
14
25/05/1999 3546.0 3408
1.60
137
47
23
14
Nordland
Hordaland
Stand Pipe Pressure versus ECDEFLF on 29/5B - F5 17 1/2" Section 445 430 415
Flow rate value x 10 = l/min
400 385 370 355
Stand pipe Pressure
340 325 310 295 280 265 250
SPP rig / ECDELF
235 220 205 190 175 160 1821 2271 2455 2850 3000 3200 3285 3370 3388 3405 3460 3475 3487 3493 3500 3505 3535 3546 3542
Page 1
Depth MD
DRILLING FLUIDS RECOMMENDATIONS
17½” – 16” Drilling section (910 to +/- 3500 m TVD) PARAMETERS
INDICATORS
♦ Increasing of Solids Contents.
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
♦ Dilution with new mud. ♦ Drilled some wells in 16” (wells performed with Ester system) to minimise the volume drilled. ! Necessity to have 850 m³ of new mud on board at the beginning of section due to high ROP in shales. ♦ Use the finest screens possible (compatible with OOC) on the shakers to minimise mud contamination with solids. ! Good results.
Specific gravity SG = 1.55 / 1.60
♦ Cavings on shakers up to 5% in Hordaland.
♦ Maintain 1.55 SG mud weight, decrease flow rate to 4000 l/min when ROP decrease. ♦ Increased mud weight to 1.60 SG to prevent caving in deviated well above 20-degree angle. ! Small amount of cavings during the section, decreasing at the end of section.
♦ Large cavings after side track in G8 well at 40 degree angle
Rheology
HT Fluid loss < 3/4 cc
♦ Hordaland formation destabilised by water base cement spacer during side track. No mud solution: requested to side track again the section just below the 20” casing, thus above top of Hordaland.
♦ Hole Cleaning.
♦ Maintain a good carrying capacity with 4500 l/min Flow Rate and Yield Point > 30 by treatment with Geltone II / Suspentone + RM 63.
♦ PV: ALAP.
!
♦ Increasing.
♦ Necessity to keep a low HP/HT filtrate due to a low-pressure zone in the Palaeocene: Kept Duratone HT concentration at 14-16 kg/m³.
Good result: no hole cleaning problems.
♦ Achieved by dilution with new mud, addition of EZMUL-2F and solids control.
! HP/HT = 2.2 - 2.6 cc at 130ºC.
PARAMETERS
Lime excess > 5/7 kg/m³ with XP-07 system
Electric Stability
INDICATORS
♦ PB decreasing.
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
♦ Treat the active system continuously with Lime. ! No problems of mud stability in spite of an excess of Lime sometimes less than 1 kg/m³.
♦ > at 400 V.
♦ Kept a correct concentration of EZMUL-2F in the system to maintain good mud stability in spite of water incoming from the formation (osmotic action on the shales) and water additions at surface to balance evaporation. ! ES at around 700 V at the end of section.
♦ Potentials Formation Losses.
♦ Before reaching the Palaeocene the Mud system will be treated with: • Baracarb 150:10-15 kg/m³ • Baracarb 50: 20-25 kg/m³ • Baracarb 600: 1-2 kg/m³ • Barofibre: 2-3 kg/m³ • Soltex: 10-15 kg/m³ ! Only some seepage observed.
Palaeocene Formation
♦ Differential Sticking. (2800 PSI over pressure) ♦ REMINDER
♦ Kept a H/P H/T filtrate as low as possible as seen above. ! No differential sticking met in this section. ♦ Have a LCM pill (+/- 20 m³ with a concentration of 180 to 200 kg/m³) ready to be pumped.
Weak Zone Shell Shearwater
The HPHT fluid loss was maintained at less than 2 cc (<1 cc in most cases) at the maximum geothermal temperature to minimise the filter cake. This was maintained prior to entering the Palaeocene sands until the 14” x 13 3/8” casing was cemented. To improve the quality of the filter cake, 70 kg/m³ cellulose LCM pills were spotted over the Palaeocene sands during connections until the bottom hole assembly was below the permeable sands. Prior to trip out of the hole, the same pills were pumped to cover the complete Palaeocene sands interval to prevent the formation of thick filter cakes. The above measures proved effective in minimising the risk of differential pressure sticking as no signs of differential sticking was observed during the six –well project.
PARAMETERS
INDICATORS
♦ Oil on Cuttings.
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
♦ Optimisation of shakers screens. ♦ Use High G Dryer when available to return base fluid to the system and then minimise Oil Discharge to the sea.
Environment
Ø Kept Oil Content on cuttings less than 10%. ♦ Use time to time an Ester Mud System to drill section in order to minimise the environmental impact of cuttings in the sea. Ø Met problems of high rheology, gels and borehole instability with this system on G8; system no more allowed to be discarded with cuttings to the sea in 2002.
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
3.5
14” x 13 3/8” casing and cementing Running the casing: prior to run the casing, the gel strength and yield point must both be reduced, the yield point + 18 lb/100ft², and the 10’ gel to < 25 to avoid excessive surge pressures when running in. Pilot tests will be completed by the mud engineer to determine the optimum treatment levels. This can best be accomplished by additions of OMC 2 or by addition of base fluid. Care should be taken so as not to over treat the system with OMC 2. When running casing, consideration should be given to breaking circulation half way in the hole, to reduce back pressure when breaking circulation on bottom prior to cementing. Swab and surge calculations should be run on the actual data of the time to optimise the rheological properties and casing running speeds, to ensure they are well within the limits of the LOT at the 20” shoe.
- Synthetic base mud recovery: if no major problem of borehole stability has been seen while drilling, a sacrificial water base mud will be pumped to remove the SBM { Ester or XP07 }from behind the casing. Recommended concentrations: Drill water Soda ash Caustic soda Bentonite BARAZAN Plus DEXTRID BARASCAV D ALDACIDE G Barite to adjust density .
0.75 kg/m3 1.5 kg/m3 30 kg/m3 1.7 kg/m3 7 kg/m3 0.75 kg/m3 0.25 kg/m3
- Cementing job The 14” x 13 3/8”or 13 3/8” casing will be cemented with a lead and tail slurries. The top of the lead will be around 2000 metres TVD ( See casing Load design ) . The top of the tail will be at 3050 metres TVD, to cover the Palaeocene sands. A bottom and top plug cementing head will be used. 17 1/2” hole volume E.A. 17 1/2”x 13 3/8”: E. A. 20” (# 129.3) x 13 3/8”:
155.2 l/m 64.4 l/m 87.0 l/m 11
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
13 3/8” inside volume: Annulus volume: Synthetic Base Oil Sacrificial water base mud: Spacer volume: Lead slurry No excess Tail slurry volume 30% excess Displacement Fluid design: - spacer 1
77.24 l/m 263 m3 5 to 10 m3 143 m3 Optional 25 m3 0 m3 15 m3 circa 288 m3
5 to 10 m3 (Has to be adjusted)
Synthetic Base Oil - spacer 2 : 15 / 20 m³ System Spacer Viscosifier Antifoam Surfactant Barite
Dowell Mud Push XL D149 D144 U66
Halliburton. Spacer 500 Spacer 500 NF5 PEN5 & SEM7
- Lead slurry mixed with Drill Water : G cement (Dyckerhoff or Lafarge) 35 %BWOC Silica Bentonite Extender Retarder
Dowell Yes Yes D159 D110
Halliburton Yes Yes Silicalite 97 HR4
- Tail slurry mixed with Drill water : G cement ( Dyckerhoff or Lafarge ) Dowell 35 % BWOC Silica Yes Fluid Loss Control D143 Antisettling D153 Retarder D110
Halliburton yes Halad 100 No HR4
Remark: - For an accurate displacement, the internal diameter of the casing must be measured on 10% random joints. Cement slurry properties: 12
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t - Lead slurry
Density Yield Thickening time Compressive strength at BHCT
1.65 SG 1445 l/t 10 - 12 h >80 bar 24 h
- Tail slurry Density Yield Thickening timeCompressive strength at BHCT
1.90 SG 996 l/t 6-8 h >170 bar 24 h
13
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
3.6
Experience :
Examining the practical aspect of cementing a 13 3/8” casing. It is a detail procedure used to cement the casing with an ESTER mud . This section gives preparation details and some recommendations for the 13 3/8" cement job . In order to achieve a good cement job and minimise the risk of contamination it ‘s recommended to perform the displacement of slurry with Petrofree and pumping a large sacrificial spacer ahead . Current Well status : TD for the Section : Shoe Depth :
3478m +/- 3463m - Float collar : 3406m ( 5 joints )
Top Balder Top Lista Top Andrew Top Maureen
3182 m 3250 m 3294 m 3397 m
A : Centralisation for this casing should be as per following : Diameter for centraliser :
16 1/8”OD for 17 1/2 ” hole
- 2 Solid SpiroGlider (16 1/8” OD ) per joint over the first four joints. - 1 Solid Spiroglider ( 16 1/8” OD ) per joint from the float collar to the top of the tail slurry +/- 3000 m - 1 Solid Spiroglider ( 16 1/8” OD ) every 3 joints from top of tail to 2000 m . ** - Marine Section from sea bed to well head : 1 Cast Centraliser 18” per joint ( internal clamp type ) installed Mid-joint , to be done on the deck to minimise pause when approaching bottom .( see procedure Tie back on Elgin ref. UWG specif. E520 ) Note : - Special care for the installation and pass through the table .( Frank’s spider might be removed for each centraliser ) Stand off : 72 % for this casing .
14
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
B : Pre-job preparation : 1)Ensure all pits (to be used for the preparation of spacer and cement slurry mix waters)[suggest one Reserve pit is used for the preparation of these water based fluids], mixing lines, circulation lines, transfer lines (including and especially the transfer lines from the pits to the Halliburton unit and cementing line to the rig floor are thoroughly cleaned out and flushed through with drill water .Check volume line between Rig floor and Halliburton unit . 2)The 13 3/8” casing has been drifted and dimensionally controlled in order to better assess the ID of the joints which will be used for the displacement calculation. 13 3/8” Average ID : 12.44 “ Volume = 78.40 l/m Mud film removal = 1.665 m³ 3 )The Halliburton or Dowell Batch Tank will be used for the Tail mixing water .( Capacity = 23 m³ or 150 bbls ) Preparation of Spacer 4 ) The spacer ahead to be used is to consist of 14 m³ with Surfactant followed by 50 m³ without surfactant of Spacer 500 weighted to 1.67 SG with Barite. The cement spacer should be prepared in the dedicated pit during running of the casing as per Halliburton mixing instructions attached.. Check the rheology at room temperature at this stage and compare to that achieved in the Halliburton lab. Weight up with barite to 1.67 SG (monitor throughout with a calibrated pressurised mud balance), take a sample, check rheology, note result and compare it to the result achieved in Halliburtonl Lab and retain. The Surfactant should be added just prior to pumping downhole to prevent foaming i.e. directly into the Slug Pit. In the same time : Prepare lead cement slurry mix water ( as per Cement recipe attached ) in a clean pit .The retarder will be added once the circulation will be completed. Prepare in the Batch tank the mixing water for Tail slurry.(same recommendation for retarder ). Once the freshwater has been added to the pit the chloride content of the freshwater should be checked , the result noted and a sample of this water retained. C :Running procedure and Fluid pumping Sequencee Recommendations : 1 - In case of major problems ( abnormal drag ) , prior to entering the Palaeocene formation Top Balder another circulation could be done and the parameters established.( if necessary )
15
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
2- According to the calculations, the down weight should be in the range of 340 T ( Martin Decker ) . 3 - Circulation prior to the job ( Annular volume +/- 225 m³ ) should be, at a minimum, 1.5 times complete Annular Volume or entire casing contents. The flow rate will be gradually increased while monitoring for losses and cavings . Wait long enough during each step to assess the potential losses. - Circulation through wellhead outlets to be done to remove potential cavings ( see F2 ) - Record pressure at bottom at different flow rates ( 1000 / 1200 / 1500 l/min ) - Losses reported on G7 ( 20 m³ during displacement ) - Cavings were reported on previous wells ( F1& F2 ) D : Pumping sequence : 1 ) Pump Ester thin mud +/- 40 m³ at 1.65 SG with YP = +/-12 ( if possible ) 2 ) Pump Spacer 1 , +/- 14 m³ at 1.67 SG with SEM 7 ( slug pit ) 3 ) Pump Spacer , +/- 50 m³ at 1.67 SG without SEM 7. 4 ) Lead and Tail Slurry formulations as per Cementing receipe. The Volumes required are as follows: •Lead Cement slurry : Volume to fill annulus from 3100 m above the tail to 2000 m MD. No
Excess on Open Hole Estimated volume : 75 m³ at 1.70 SG ; 75 Tons ( blended ) •Tail Cement Slurry : Volume to fill annular volume to 3100 m. above the 13 3/8" shoe plus the shoe track. Estimated volume : 32 m³ at 1.92 SG with 30% excess , 43 Tons ( blended )
Monitor density throughout mixing of both the lead and tail slurries with a pressurised mud balance. Take a sample of both lead and tail slurry during mixing and check rheology in Fann Meter. 5 ) Displacement with mud ( Petrofree ; SG = 1.65) Rig pumps at 1500 Litres/min. Monitor rates and pressures during the displacement and if losses occur, record the volumes, adjusting the rates as required. ! 170 m³ @ 1500 l/min ! 102 m³ @ 1000 l/min Total displacement : 272.139 m³ ( to be adjusted according to the casing string diameter )
16
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
ECD estimation before bump the plug : TD ( 1500 l/min ) Surface Pressure before Bump : Static pressure before Bump :
1.76 EMW at +/- 80 bars ( @ 800 l/min ) +/- 30 bars ( low flow rate )
6 ) Bump plug and then pressure test casing to 160 bars . ( Plug ; Float collar & Cementing Head Pressure rating : to be checked ) Pressure Test casing will be done prior drilling out cement to 280 bars with mud at 1.30 SG ( to get 2.10 EMW at the shoe ) Timing : Mixing + Injection Lead Displacement N° 1 Displacement N° 2 Safety factor Total
90 min 105 min 107 min 60 min 422 min # 7 hours 12min
- All samples of fluids should be 1 litre in size. - Chloride content of Fresh water should be less than 500 mg/litre. Thickening Time : TAIL Slurry : BHCT = 80 °C " 7 hours 20 mn @ 100 Bc Compressive Strength :
2706 PSI 24 hours at 80 °C .
Thickening time : LEAD Slurry : BHCT = 80 °C "9 hours 12 min @ 100 Bc Compressive Strength:
329 PSI after 24 hours at 80 °C.
E ) Wire Line Logging : CBL to be done prior to drilling the next section .( +/- 24 hours after bump ) The aim of this need is to check the top of cement in the annulus for safety factor requirement during the production phase .The log will be recorded from +/- 2500 m to the Top of cement . F ) ESTER displacement before resuming 12 ¼” drilling : A spacer of Viscosified CaCl2 Brine could be pumped ahead of XP07 before drilling out the cement . 30 m³ of Spacer seems enough to minimise the contamination of the ester . ( TBA in due time ) . Logistic with supply boat is the main problems to avoid any risk of contamination .
17
CEMENTING RECOMMENDATIONS
14” x 13 3/8” Casing set 50 m inside the TOR formation. PARAMETERS
INDICATORS ♦
TECHNICAL COLUMN DESIGN
♦
Cover the overpressured Hordaland shales. Cover the potentially weak Palaeocene sands.
BHCT Prediction : THICKENING TIME BHST = 130º / 148 ° C at bottom
RECOMMENDATIONS •
Top of cement at 2000 m. TVD, typical excess 30%.
•
FIT at 13 3/8” above 2.00sg EMW
•
A P I prediction : 96°C Enertech: 80°C
Check the thickening time (T. T.) of Lead and Tail slurries at the maximum expected temperature according to the simulation.
Slurry Design : • TT for Tail = 7 to 8 hours at 80°C.
Cemcade: 75° C BHST = 80 / 95°C At the Top of Cement
COMPRESSIVE STRENGTH
• MWD record at TD in dynamic conditions is around 100°C
Check the compressive strength after 24 hours of WOC
TT for Lead = 9 to 10 hours at 80°C.
Change in Thickening time values cement setting did not have a pronounced effect on the set of cement at BHST
• For the tail the strength was checked at 110 °C according to the Enertech simulation after 24 hours of wait on cement. • For the lead slurry the strength was checked at the BHST estimated at the top of cement (80 °C).
SLURRY DESIGN G+35% silica "
♦
•
Tail slurry : 1.92sg
Gel with bentonite system is recommended and easier to design.
!
Top of cement from 900 to 2300 m
!
No wet shoe, no restoration needed.
Thickening times: G4 - Lead 15 h 14 Tail 5 h 49 at 95ºC G5 - Lead 13 h 05 Tail 5 h 49 at 93ºC G6 - Lead 13 h 39 Tail 9 h 32 at 90ºC G7 - Lead 12 h 45 Tail 9 h 37 at 85ºC F1 - Lead 7 h 50 Tail 5 h 50 at 80ºC F2 – Lead 7 h 50 Tail 7 h 10 at 80ºC F3 – Lead 9 h 05 Tail 7 h 15 at 80ºC F4 – Lead 9 h 13 Tail 8 h 25 at 83ºC F5 – Lead 9 h 38 Tail 7 h 43 at 80ºC F6 – Tail 9 h 21 Tail 7 h 35 at 80ºC !
3000 PSI after 16 hours
!
700 PSI after 22 hours
Samples set after 24 hours at room temperature !
Lead mixing water mixed in a mud pit.
!
Tail mixing water prepared in the batch tank.
Dowell:1.5 % BWOC of bentonite Halliburton: 2.5% BWOC of bentonite
Lead slurry : 1.65sg ♦
"
Slurry extender + fresh water
RESULTS / Remedial Action
Retarder: Dowell: 2.2 lit/t D110 Halliburton: 0.3% to 0.5% HR4
•
Adjust the TT to have the safety margin (+ 40%) for the cement Job . The quantity of retarder is very low then a special attention is necessary to prepare the mixing water .
1
PARAMETERS
INDICATORS
RECOMMENDATIONS
Sacrificial SPACER
♦
In case of use ESTER
•
To recover mud behind casing for cost reduction
Primary SPACER
♦
Compatibility with SBM and cement slurry.
•
5 m³ of base oil + 5 m³ of chemical wash were pumped ahead to thin the mud.
•
A volume of 20 m³ of spacer at 1.60sg with surfactant was pumped ahead the lead slurry at 1.65sg.
•
Adjustment of the rheology on the rig
RESULTS / Remedial Action
!
No channelling reported.
!
Spacer rheology has been increased before the injection by readjustment of viscosifier.
! ! ! ! !
G4 - TOC = 1720 m G5 - TOC = 1720 m G6 - TOC = 1470 m G7 - TOC = 927 m G8 - TOC = 2300 m
! ! ! ! ! !
F1 - TOC = 1815 m F2 - TOC = 1700 m F3 – TOC = 2275 m F4 – TOC = 2107m F5 – TOC = 2120 m F6 – TOC = 1800 m
!
Bump the plug : OK
!
Some losses were reported during displacement.
CAUTION : • Foaming after adding the surfactant. It is essential that mixing procedures be adhered to the recommendations done by contractor’s. ♦ Well Conditioning
CBL - Top Cement
DISPLACEMENT Calculation
Pack off annulus with cuttings (see G5, F2) between the adjustable mud hanger and the landing ring.
Circulation long way with correct mud parameters. A clean annulus is requested before the job.
A CBL /VDL has been recorded to check TOC, generally the bonding is between 10 to 30 volts in front of the lead slurry. The top cement is clearly identified.
♦
CBL analysis
♦
Internal micrometer recordings for 14 “ and 13 3/8” casing, typical ID = 12.426” compared to 12.347” nominal ID.
•
Mud compressibility.
•
♦
This check is crucial to achieve a good displacement of the slurry. Average on 6 Franklin wells: the difference in volume between the nominal ID and the measured ID accounted for +3.5 m³ on the displacement calculation, this volume is equivalent to 45 m of casing. The extra volume due to the Hydrostatic column of the fluid can be calculated but must not be included in the displacement. This volume on the 6 wells on Franklin was + 3.7 m³ average, or 47 m of casing.
♦
Rig pump
•
Displacement done with dedicated pump, rig pump efficiency (typically 97%).
♦
Max volume
•
Do not over displace 50% of the shoe track.
2
29/5b FRANKLIN - 17 ½" OPEN HOLE / 13 3/8" CASING CEMENTATION 16" open hole
Well Date Top of cement (real) Casing shoe Height BHST BHCT Type of slurry Theoritical slurry volume Excess Total slurry volume Weight of cement (G+S) Slurry weight Cement Lafarge G Silica flour Water Additives
m m m ºC ºC m³ % m³ ton sg % % type
29/5b-F1 30/03/1998
29/5b-F2 21/07/1998
29/5b-F3 24/10/1998
29/5b-F4 15/02/1999
29/5b-F5 25/05/1999
29/5b-F6 10/12/1999
2000 (1815) 3640 1145 495 130 80 lead tail 74 28 50 50 111 40 148 1.65 1.92
1400 (1700) 3466 1600 466 130 80 lead tail 62 26 0 30 62.5 32.4 95 1.65 1.92
2000 (2275) 3464 1100 364 130 80 lead tail 75 35 0 20 71 38 120 1.70 1.92
2000 (2107) 3968 1500 468 136 83 lead tail 97 38 35 30 130 48 194 1.65 1.92
2000 (2120) 3532 1032 500 135 80 lead tail 71 45 35 0 95 43 158 1.65 1.92
2000 (1800) 3563 1063 500 135 80 lead tail 71 37 43 11 102 40 150 1.65 1.92
100 100 100 100 100 100 100 100 100 100 100 100 35 35 35 35 35 35 35 35 35 35 35 35 Fresh Fresh Fresh Fresh Fresh Fresh Fresh Fresh Fresh Fresh Fresh Fresh 2.5% Bento 2.5% Bento 2% Bento 2.5% Bento 2.5% Bento 2.5% Bento 1 lit NF-5 1 lit NF-5 0.45% HR4 0.28% HR4 0.45% HR4 0.28% HR4 0.53% HR4 0.35% HR4 0.5% HR4 0.28% HR4 0.55% HR4 0.36% HR4 0.52% HR4 0.36% HR4
l/ton or 0.5% Hal-100 0.5% Hal-100 0.5% Hal-100 0.5% Hal-100 0.5% Hal-100 0.5% Hal-100 0.5% Hal-100 % 50 lit Sil-97L 50 lit Sil-97L 50 lit Sil-97L 50 lit Sil-97L 50 lit Sil-97L 50 lit Sil-97L
Thickening time (70BC) hr:min 07:50 05:51 Compressive strenght 12 hr PSI 380 740 Compressive strenght 24 hr PSI 930 2300 Flow pattern laminar laminar Spacer type Base oil / Spacer 500E+ sg 1.60 Plug type Displacement type 2 plugs
07:50
07:10
09:05
07:15
09:13
870 2400 laminar laminar Spacer 500E+ 1.60
330 2700 laminar laminar Spacer 500E+ 1.67
08:25 1400 600 4700 laminar laminar Spacer 500E+ 1.62
2 plugs
2 plugs
2 plugs
09:38 07:43 870 (32 h) 1100 (40h) 1100 laminar laminar Spacer 500E+ 1.62 Bottom and top plug 1.60 sg mud
09:21
07:35
940 (40 h) 2900 laminar laminar Spacer 500E+ 1.62 Bottom and top plug 1.61 sg mud
m
3.97
3.07
2.03
1.92
2.5
2.48
m
3572.68
3398.73
3398.17
3890.58
3464.68
3501.25
m
3467.68
3398.73
3268.17
3440.58
3327.68
3457.25
12.44 78.41 280.5
12.42 78.16 265.9
12.44 78.41 266.6
12.43 78.29 304.7
12.419 78.15 271.0
12.404 77.96 273.2
∆ ∆
in. l/m m³ m³ m³ %
0.0% Yes
0.7% Yes
0.6% Yes
0.4% Yes
0.6% Yes
-0.1% Yes
0.4%
12.347 77.25 276.28
12.347 77.25 262.77
12.347 77.25 262.65
12.347 77.25 300.68
12.347 77.25 267.82
12.347 77.25 270.65
12.347 77.25
∆ ∆
in. l/m m³ m³ %
-1.5%
-1.2%
-1.5%
-1.3%
-1.2%
-0.9%
-1.3%
XP-07
Ester
Ester
XP-07
XP-07
XP-07
1.56
1.56
1.65
1.63
1.60
1.61
3640
3466
3464
3968
3532
3563.3
g/l
12.426 78.23 278.0
m³
m m³
2.7
Nominal casing ID size
Casing ID measurements
Casing ID measurements mud Compressibility
Top plug - 3.5 m³ + 1.0 m³ Landing collar
+ 4.7 m³
TEMPERATG4 Chart 4
17 1/2" Temperature Prediction - ELGIN /FRANKLIN 160
140
120
Temperature in °C
100 Enert. BHST Geol.BHST 80
MWD Temp in °C Temp out°C Mud Cooler
60
Mud Cooler
40
20
0 1110
1448
2027
2730
2930
3091
3139
3160
3182
3209
3211
Depth TVD
Page 1
3292
3320
3360
3402
3440
3475
3550
3600
3610
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
4.
12 ¼” SECTION Interval: Max expected BHP: Expected temperature:
+/-3900 m MD to +/-5300 m (MD) 1.80SG EMW. 176°C BHST at 5100 m TVD BRT.
4.1
Purpose Set the 9 7/8” casing at the top of the Rodby ( circa 5050 m TVD BRT ) above the high pressure transition zone.
4.2
Drilling procedure Run in hole with 12 ¼” bit, drill out cement, the rat hole and 5 m new formation. Perform a leak off test (minimum expected 1.85 SG EMW, limited to 2.15 SG EMW). Drill ahead to drop off point. POOH and pick up the drop off assembly to obtain 0.5 degree/ 30 m. Drill ahead. Run and cement 10 ¾” x 9 7/8” casing.
4.3
Expected problems Loss/Gain situation: The transition zone below the Upper Cretaceous is thin and over-pressured. The 12 ¼” section must be stopped at the top of the Rodby but loss/gain situations could occur towards if the transition zone is too deeply penetrated.
4.4
Drilling fluids – Experience – Hydraulic Synthetic base mud at 1.55 SG from the 17 ½“ section will be used to start drilling. The density will be adjusted to 1.35 SG to start and gradually increased to 1.65 SG around 4500 m TVD BRT (circa 400 m TVD above the transition zone).
4.4.1
Typical composition of mud (1.65 SG, 75/25 OWR)
XP-07 EZ MUL 2F Lime DURATONE HT Water GELTONE Calcium Chloride Barite RM 63
(Base Fluid) (Primary Emulsifier) (Ca(OH)2) (Fluid Loss Control)
482 l/m³ 48 l/m³ 11.5 kg/m³ 43 kg/m³ 159 l/m³ (Viscosifier/Gelling Agent) 3 kg/m³ (CaCl2) 99 kg/m³ (Weighting agent) 742 kg/m³ (Rheology Modifier) 3 l/m³
1
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
4.4.2
Typical mud characteristics Weight PV YP YS Gels 0/10 Filtrate API Filtrate HP/HT E.S. Cl-(Water Phase Salinity) H/E Excess of Lime
4.4.3
: 1.55-1.65 SG : ALAP, typically 30-45 cPo : 18-20 lbs/100ft² : 8 - 10 lbs/100ft³ : 10/12 - 28/32 : 0 cc : 3.5 - 4 cc : > 400 V : 200 g/l : 70 /30 - 75/25 : 0.5 – 0.7 g/l
Safety stocks Bulk material Barite Cement G + Silica Flour
: 150 t : 100 t
Material in sacks or drums BARACARB 50/150 :3t/3t LIQUID CASING :3t 3 Chemicals to mix 300 m of synthetic base mud Kill mud / Synthetic Base Oil Kill mud 1.95 SG Base Oil 4.4.4
: 50 m³ : 150 m³
Recommendations Hole stability and mud weight. The mud weight must be gradually increase to 1.65 SG to reach the Rodby marker. The transition zone is in the Rodby, Sola, Valhall, Kimmeridge clays where the pore pressure increase sharply from 1.40SG EMW to 2.09 SG EMW. There is uncertainties on the top of formations, therefor the mud must be prepared for a major increase in density without major impact on other mud properties. Pilot testing must be done daily on a weight up to 2.00SG. Hole cleaning. Optimise the cleaning of the hole through conventional rheology adjusting the yield stress to 8-10 lbs/100sqft and with the maximum feasible pump rates (3,600 2
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
4,000 l/min) . If necessary pump high viscosity cleaning pills. The following points were raised for the 17 ½” section and are still relevant in this section: • Use the highest possible pump output/annular velocities, do not circulate at less than drilling rates circulation. • Keep the Yield Point at 50°C between 18 and 22 lbs/100ft² with the Plastic Viscosity as low as possible, typically below 45 cPo. • Optimise the low shear rheology using RM 63 and GELTONE II to assist in hole cleaning by maintaining the Yield Stress between 10 and 12. • Maintain high initial gel strength 10 to 12 lbs/100sqft giving rapid suspension of cuttings when the pumps are off during surveys, or trips. This should be combined with flat gel strength development. • Use mechanical means (e.g. wiper trips, pipe rotation, reciprocation, back reaming with the top drive if available, etc.) and weighted pills pumped prior to trips to assist with hole cleaning. • If a more viscous mud is required, suggest initial treatment to raise Yield Point to ± 25 and initial gel to ± 15. • If further viscosity increases are deemed necessary to improve the mud carrying capacity, increase the Yield Point and 6 RPM reading in increments of 5 lb/100ft². 30 should be considered the upper limit to ensure optimisation of the hydraulics. • Even with mud properties and flow rates optimised a hole cleaning problem may still occur. At the first indication of possible problems, pump a high viscosity/weighted pill (pump these pills prior the trips). This should be sized to cover 100 m of annular hole. It is recommended that a 2.0 SG weighted pill be pumped around while rotating the string > 150 rpm if possible. In the case of all pills, do not stop or reduce the circulation rate before the pill(s) have been evacuated from hole. To do so will result in material dropping out of the pill and possibly avalanching downhole. All attempts should be made to isolate weighted pills on surface for re-use. Return of all pills should be monitored at the shakers, to gauge their effectiveness. • The trend in the correlation of cuttings generated and seen at the surface to ROP can provide another indication of the effectiveness of hole cleaning. The mud engineers should be monitoring cuttings volumes and correlating with these drilling rates at all times. The shaker hands should also be shown what to watch for so that they can provide a speedy warning e.g. a soft sticky must means the cuttings are being reground in the well and are not being removed. Seepage losses : Maintain the concentration of the bridging material at 20-25 kg/m3 to effectively seal the formation, through the addition of BARACARB 50 and BARACARB 3
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
150. Monitor the effectiveness of treatment with a Permeability Plugging Apparatus fitted with 40 micron aloxite disc. Water phase salinity : It is recommended that the WPS is run at 200 g/l Cl-. adjustments will be made as dictated by cuttings integrity and indications of water gains from the formation by the way of osmosis. HPHT fluid loss. To be measured at 160°C. HPHT fluid loss must be maintain from 3.5 to 4 ml all oil, and with no API fluid loss. The filter cake must effectively seal the formation preventing differential sticking and seepage losses. Alkalinity. The lime content must be maintained in the range of 0.5 – 0.7 kg/m³. Depletion and/or acid gasses may necessitate regular additions of lime to maintain this level. Sagging. Barite subsidence can take place in deviated wells. Monitoring of the start of circulation must be done thoroughly. • The derrickman measures the specific gravity and the temperature of the mud with a pressurised mud balance every 15 minutes, until the bottom-up reaches the surface. • The mud logger records the lagged depth versus the time until the bottom-up reaches the surface. Note: do not rely on mud weight measurements from the mud logging company as most of the devices used are not accurate, when cold and viscous mud are processed. The mud weight must be recorded manually by the derrickman. • The mud engineer plots a graph of SG corrected at 50°C versus lagged depth and he records separately: i. mud weight of mud before circulating. ii. rheology, gels of mud at end of last circulation. iii. maximum mud weight recorded while circulating. iv. minimum mud weight recorded while circulating. v. time spent while circulating. Barite sagging handling procedure: • Prevent the subsidence of barite adding 4 to 8 kg/m3 SUSPENTONE, anti-sagging agent. • Avoid excessive treatment by thinners OMC 2, defloculants and excessive dilution. • Decrease the particle size distribution of the weighting material in running fine screens on the shale shakers along with running the centrifuge at a low bowl speed. Note that a large addition of barite will increase the sag. This is attributed to the presence of a coarse fraction in barite ore, which becomes progressively screened out.
4
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
• Drilling practices: if the subsidence of barite cannot be eliminate, then the mud must be circulate on stage, while running in to the bottom to decrease the length of heavy mud in the annulus. Temperature at flow line (± ± 85°°). Towards the end of the section, temperature will be high causing steam evaporation carrying oil vapours. Sufficient water will have to be added
daily to maintain the oil water ratio in the range. In case of drastic increase in the temperature, use the mud coolers. Hydraulics. Plastic viscosity must be maintained as low as reasonably possible. PV at 30cPo would be ideal (with maximum at 45 cPo) to promote low ECD Equivalent Circulating Densities. The ECD and ESD will be calculated using the ELF software along with FANN 70 data. Therefor a sample of mud must be sent to town at least twice a week for analysis. This sample will to be stirred 2 hours in a high shear mixer, before starting any measurement. Solid control equipment. It is essential that the maximum use be made of all available solids control equipment. Run the shale shakers utilising the finest mesh screen possible. Ensure that Tertiary equipment are being effectively used by analysing the LGS/HGS ratio in both the input and output. The Creteaceous is quite inert and the selection of shakers screens will be based on fluid properties and OOC figures. 140 to 165 meshes could be used in the upper part with attempt to size down the shakers to 165 to 200 meshes. Shale shakers have to be attended to at all times, and screens changed as circumstances dictate to keep the optimum screen size on the shakers. It is also suggested that both oblong, square and pyramidal screens be available on the rig site and various combinations are tried for optimum performance. The base fluid wash gun should be available to clean the screens. Synthetic Oil on Cuttings: For the DTI Department of the Trade and Industry, the Mud engineers performs the SOC on a composite sample every 300 metres or daily, whichever is the sooner. The mud engineer also collect all statutory samples while using synthetic oil base mud.
5
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
4.4.5
Experience :
Recommendations : 1. Type of mud. Type Used XP-O7 - synthetic based mud 2.
Recommended XP-O7 - synthetic based mud
Density
A density of 1.30/1.35 SG provided good hole support and improved penetration by approximately 10%. The mud was weighted up at 4,800 metres.
Density Used 1.30 to 1.60 SG 3.
LCM Contingency. The requirement to have higher stocks of BARACARB for contingency stock was met from the start of this well. It is recommended to continue to keep this minimum contingency stock for each future 12 ¼” section.
Starting Stock Minimum Contingency Stock 4.
Density Recommended 1.30 to 1.60 SG
Barofibre / C 2 / 2 tonne 3 tonne F
Steelseal 3 tonne 3 tonne M
BARACARB 50 / 150 / 600 4½ /2½ /2T
RHEOLOGY. A yield point of 15 - 20 gave adequate hole cleaning properties. The average was 18 lb/100 sq. ft. A 6 rpm reading of 10 - 12 was adequate for a hole angle of 38.8 degrees inclination as measured by the lack of hole problems while drilling or during trips. No tight hole attributable to cuttings beds or poor hole cleaning was seen. . PV 20 -32 Recommended
5.
YP 15 - 20 A.L.A.P
6 rpm 10 -12 15 - 20
8 - 12
EMULSIFIERS and HPHT. The HPHT test temperature was raised from 130 ºC to 160 ºC at 4,900 meters. Used Recommended Used Recommended
Primary Emulsifier EZ MUL 2F EZ MUL 2F HPHT, ml. 1.6 - 3.0 < 3.0 - 4.0
6
Electrical Stability 400 - 600 > 400 Temperature deg C. 130 / 160 130 / 160
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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6.
ALKALINITY. Continue to use lime to maintain an adequate alkalinity. Excess lime kg/m3. 3.0 - 6.0 5.0 - 10.0 < 5.0
Used Recommended, engineers Recommended, program 7.
8.
EVAPORATION. Levels of evaporation,averaged about 5 m3 per day. The rate of evaporation was in the 0.751.30% range. OIL WATER RATIO and WATER PHASE SALINITY. Water additions were required to maintain the O/W in the upper half of the interval. Evaporation was used to increase the O/W in the lower half of the interval towards 80/20. Evaporation necessitated water additions to maintain the O/W ratio. Oil / Water ratio Used Recommended
9.
Water Phase Salinity. mg/l Chlorides 160,000 - 225,000 160,000 - 200,000
70 / 30 - 79 / 21 70 / 30 - 75 / 25 - 80 / 20
LOW GRAVITY SOLIDS. No centrifuge was available. Low Gravity solids kg/m3. 20 - 116 < 175
Used Recommended 10.
SOLIDS CONTROL. Used at start. Used at end. Recommended at start. Changing to :
11.
Scalper 20 20 20 NA
Scalper 20 20 20 NA
No. 1 185 185 150 185
N0. 2 185 185 150 185
No. 3 185 185 150 185
No. 4 185 185 150 185
No. 5 185 250 150 250
Base Fluid on Cuttings.
The slow ROP in the bottom section of the interval produced small cuttings resulting in a high arithmetical average for the Base Fluid On Cuttings. Interval average
14 / 15 gm/kg
7
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
12.
Cement Drill out Drillout of cement. Use the XP-O7 mud to drill out the cement.
13.
KILL MUD USED. Type & Weight Used XP-07, 50+m3 1.95 SG
14.
Recommended XP-07, 50 m3 1.95 SG
PIT MANAGEMENT.
No problems were encountered with the pits due to the adequate volumes available. The pill tank should be left free of slugs so that pills or dilution can be made up. The pit used for kill mud can then also become the source of heavy slugs.
8
FRANKLIN 29/5b-F3 Hydraulics analysis 12 ¼" hole
01/11/1998 02/11/1998 03/11/1998 04/11/1998 05/11/1998 06/11/1998 07/11/1998 08/11/1998 09/11/1998 10/11/1998 11/11/1998 12/11/1998
3479 3608 3642 3648 3907 4155 4405 4650 4868 4957 5065 5160
3397 3459 3492 3498 3827 4073 4326 4570 4785 4875 4980 5077
1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9 1.9
3500 3500 3500 3500 3500 3500 3500 3500 3500 3500 3250 3250
80 190 110 175 200 200 200 200 200 200 200 200
270 270 258 258 270 274 280 280 295 295 260 260
6 6 6 6 7 7 7 7 7 7 7 7
4 x20 4 x 20 4 x 20 4 x 20 9 x 13 9 x 13 9 x 13 9 x 13 9 x 13 9 x 13 9 x 13 9 x 13
8 8 8 8 9 9 9 9 9 9 9 9
79 77 80
64 62 65
81 82 82 82 79 74 75 75
25 25 25 25 24 23 23 25
1.30 1.30 1.31 1.31 1.31 1.31 1.31 1.45 1.61 1.60 1.60 1.60
54 56.8 58.9 58.7 65.9 63 66 67 65.8 65.4 67
1.30 1.30 1.30 1.31 1.31 1.31 1.31 1.45 1.61 1.60 1.60 1.60
76 63.9 67.7 66.2 73.1 73 73 73.2 73 73.4 74.3
20 20 21 21 25 23 23 32 38 36 38 40
12 12 12 12 14 15 14 14 20 18 18 16
10 9 13 13 14 14 14 15 18 16 16 17
1.04 1.04 1.04 1.04 1.04 1.04 1.21 1.40 1.49 1.50 1.50 1.50
Claystone FAIL
Fail Fail Fail Fail Fail Fail Fail Fail
Fail Fail Fail Fail Fail Fail
Limestone
Hydr. sum. F5-12 ¼
FRANKLIN 29/5b-F5 Hydraulics analysis 12¼" hole
29/05/1999
3546
3406
23.0
3180
60
276
11
3 x20
12
73
50
1.30
43
1.30
55
133
21
11
30/05/1999
3555
3414
23.0
3240
63
286
11
3 x 20
12
74
51
1.30
42
1.30
51
134
28
16
31/05/1999
3596
3452
23.0
3220
91
280
11
3 x 20
12
74
51
1.30
44
1.30
55
135
22
14
01/06/1999
3626
3481
23.0
3240
120
280
11
3 x 20
12
74
51
1.30
45
1.30
56
135
22
16
02/06/1999
3657
3509
23.0
3240
115
283
11
3 x 20
12
74
51
1.30
44
1.30
58
136
26
18
03/06/1999
3698
3550
19.1
3260
175
291
12
9 x 13
13
75
51
1.30
47
1.30
56
137
24
17
04/06/1999
3730
3580
18.6
3230
139
290
12
9 x 13
13
74
51
1.30
46
1.31
56
138
28
15
05/06/1999
3857
3702
16.4
3250
190
291
12
9 x 13
13
75
51
1.32
52
1.32
62
142
29
15
06/06/1999
4081
3918
13.2
3250
195
305
12
9 x 13
13
75
51
1.36
48
1.34
60
148
31
16
07/06/1999
4081
3918
08/06/1999
4128
3965
12.2
3225
127
313
13
9 x 13
14
74
51
1.38
45
1.37
56
149
28
17
09/06/1999
4215
4050
11.57
3230
160
309
13
9 x 13
14
74
51
1.38
48
1.39
59
152
30
15
09/06/1999
4279
4113
3230
160
314
13
9 x 13
14
74
51
1.38
52
1.39
59
154
36
17
10/06/1999
4394
4223
10.6
3220
160
309
13
9 x 13
14
74
51
1.38
50
1.39
58
157
30
15
11/06/1999
4606
4434
9.1
3240
156
313
13
9 x 13
14
74
51
1.39
48
1.39
60
163
33
15
12/06/1999
4800
4627
7.4
3230
155
305
13
9 x 13
14
74
51
1.42
55
1.42
65
169
32
16
12/06/1999
4824
4650
7.2
3200
154
324
13
9 x 13
14
73
50
1.47
51
1.46
66
169
39
17
13/06/1999
4925
4750
6.9
3020
158
306
13
9 x 13
14
69
48
1.56
55
1.56
61
172
34
17
4951
4775
7.0
3030
154
309
13
9 x 13
14
69
48
1.60
46
1.61
61
173
34
17
14/06/1999
4990
4815
6.8
3030
159
325
13
9 x 13
14
69
48
1.61
47
1.61
61
174
37
16
15/06/1999
4990
4815
16/06/1999
5186
5009
6.3
3020
157
310
14
9 x 13
15
69
48
1.60
50
1.60
60
180
33
19
17/06/1999
5280
5102
6.2
3030
170
320
14
9 x 13
15
69
48
1.60
50
1.60
63
182
36
14
18/06/1999
5280.0
5102
14
9 x 13
15
1.60
50
1.60
60-68
35
15
19/06/1999
5280.0
5102
14
9 x 13
15
1.60
35
15
20/06/1999
5280.0
5102
35
15
21/06/1999
5280.0
5102
35
15
22/06/1999
5280.0
5102
35
15
23/06/1999
5280.0
5102
35
15
24/06/1999
5280.0
5102
35
15
25/06/1999
5280.0
5102
35
15
26/06/1999
5280.0
5102
35
15
148
174
Page 1
Hydr. sum. F5-12 ¼
FRANKLIN 29/5b-F5 Hydraulics analysis 12¼" hole
29/05/1999
3546
3406
10
1.06
30/05/1999
3555
3414
14
1.06
Maureen
31/05/1999
3596
3452
11
1.06
01/06/1999
3626
3481
12
1.06
02/06/1999
3657
3509
11
1.06
03/06/1999
3698
3550
10
1.06
1.31
04/06/1999
3730
3580
10
1.06
1.31
05/06/1999
3857
3702
10
1.06
1.32
06/06/1999
4081
3918
11
1.06
1.34
07/06/1999
4081
3918
08/06/1999
4128
3965
10
1.06
1.37
09/06/1999
4215
4050
10
1.07
1.38
09/06/1999
4279
4113
11
1.08
1.39
10/06/1999
4394
4223
10
1.19
11/06/1999
4606
4434
10
1.32
12/06/1999
4800
4627
11
1.38
12/06/1999
4824
4650
12
1.39
13/06/1999
4925
4750
11
1.42
4951
4775
11
1.43
14/06/1999
4990
4815
10
1.44
15/06/1999
4990
4815
16/06/1999
5186
5009
11
1.45
17/06/1999
5280
5102
11
18/06/1999
5280.0
5102
15
19/06/1999
5280.0
5102
15
20/06/1999
5280.0
5102
15
21/06/1999
5280.0
5102
15
22/06/1999
5280.0
5102
12
23/06/1999
5280.0
5102
15
24/06/1999
5280.0
5102
15
25/06/1999
5280.0
5102
15
26/06/1999
5280.0
5102
15
Ekofisk
Tor
1.06 Hod
Herring
Page 1
DRILLING FLUIDS RECOMMENDATIONS
12 1/4” Drilling section (+/- 3500 to +/- 5040 m TVD) PARAMETERS
INDICATORS
RECOMMENDATIONS
FIELDS RESULTS
•
Increasing Solids Contents
♦
Use fine shaker screens to remove maximum of solids drilled from the mud.
!
•
ROP
♦
Start section with 1.30 / 1.35 SG instead of 1.55 (mud weight at the end of 17½” section) then adjust the mud weight according to the gas shows.
!
♦
BAROID DFG+ Software used to correct density to 50ºC.
!
Consistent stable density at 50ºC.
♦
Increase SG to 1.60 / 1.62 before reaching the transition zone, then before Casing running, the Mud weight could be adjusted to 1.70 SG. The anticipated maximum mud weight is 1.70 SG although barite stocks should be carried to allow an increasing of SG to 2.15.
!
Good stability of mud Back ground gas <5 %
OK as long as Oil On Cuttings stays compatible with Environmental regulation. ROP increasing by 10%
Specific Gravity
•
Gas Shows
♦
•
Rheology
HP/HT Fluid Loss < 3 /4 cc
YV > = 20
♦ ♦
•
PV > = 35 / 45
•
Yield Stress >7 / 9
•
Increasing
♦
♦ ♦
Due to a significant ROP in the TOP section a YP of 20 /25 is recommended. Keep PV ALAP by addition of EZMUL and adjustment of O/W ratio to 75/25 at the end of section Maintained with RM 63, Suspentone and Geltone II.
Keep DURATONE HT concentration at 14 / 16 kg/m³ with a treatment of 300 kg/day. Add Invermul 2F towards end of section.
!
! ! !
! !
! Lime Excess • > 2/4 kg/m³
PB (Pom) Decreasing
♦
System treatment of 1 to 2 tons/day of Lime.
! !
1
No impact on the ECD No Hole cleaning problems have been reported. Well in good condition
Kept HP/HT = 2.6 to 2.4 cc at 160 °C HPHT at 180ºC at end of section.
Kept Lime excess between 1and 5 kg/m³. No problems of stability E S = 850 V at the end of section
PARAMETERS
INDICATORS •
Treatment to start the section
HYDRAULIC
Rheology and mud weight adjustment
•
Stand Pipe pressure
•
L.O.T / ESD
•
Potentials Losses
•
Differential sticking
•
♦
Gel 30 min increasing
SAGGING
•
•
No Wiper trip at the end of section.
•
No Wiper trip before running casing.
!
Good prediction of ESD & ECD from ECDELF. Good correlation between the predictions and the SPP on the rig. (Ex: Estimated = +/-260 bar, on Rig Site = 259 bar) No differential sticking
Run software to follow trend ESD and ECD
♦
Run PWD. Good relation between Pressure readings and simulated. ECD = 1.41 SG at 4606 m for a mud weight of 1.38 @ 50°C and a flow rate 3240 l/min. ECD = 1.58 SG at 4805 m for a mud weight of 1.55 @ 50°C and flow rate 3030 l/min.
!
♦
Work with minimum mud weight compatible with gas background.
!
♦
Mud treatment with primary Emulsifier / Lime / Geltone / Duratone HT in order to maintain good concentrations in the system.
!
Gels 0/ 10 /30 min: 14 / 26 / 30
!
Overpressure to break gels = 55 PSI after 48 hours before resuming circulation. BHST (Static Temperature) 180 /185 °C at the end of section (correlation with Enertech + drilling data)
!
♦
A sign of SAG was detected after one extended flow check at 5130 m. After treatment with SUSPENTONE no further sag indications were reported.
♦
Mud should be treated with 3-5 kg/m³ Suspentone during this Interval
♦
Same mud formulation and maintenance is recommended for the next well
REMINDER
Well bore Stability
Need space pit Adjust OWR to 75/25
♦
PWD tool interpretation indicates 149°C BHCT at TD
• Density return
! !
♦
Overpressure to break gels
Temperature
FIELDS RESULTS
Need a dilution of 20% to reduce Mud Weight from the previous phase. Mud treatment with Geltone II in order to keep a good rheology.
♦
ECD - ESD
Gellation due to the Temperature
RECOMMENDATIONS
2
! !
Good Stability Run Casing: 10¾” x 9 7/8” without problems.
PARAMETERS
INDICATORS •
Loss of water , OWR increasing
RECOMMENDATIONS • • •
Evaporation
•
•
Run Mud Cooler when mud temperature out reaches 70°C.
!
An addition of 200 / 1000 litres / hour of drill water is recommended during drilling or circulating.
!
Fluid loss up
•
Addition of EZMUL-2F as primary emulsifier is required to replace the emulsifier lost with the evaporating water.
• •
Treatment with DURATONE HT. INVERMUL 2F additions towards end of section for HPHT at 180ºC.
• • • •
Environment
!
HP/HT between 2.6 and 2.4 cc.
Dead volume in mud pits: (See 17 ½” comments).
!
OOC=+/-10.9 %
Solids/mud discharge from the centrifuge / High G Dryer: The use of fine screens on the shakers will prevent the use of the centrifuge. Coarser screens Screens of 200 mesh or finer
!
No centrifuge required.
! !
Lower O.O.C. Poor solids distribution, loss of Duratone, increase in HPHT. No oil spills were reported .The slow rates of penetration produced small cuttings resulting in a high arithme-tical average for the OOC.
Target for 12 ¼”: 8% ( Oil on cuttings ) •
The solids discharge would drop into a screw conveyor to a recovery system supplied by STS to a Skip or Big Bag station, and be sent ashore for disposal in the Future according to the ELF Strategy.
•
Waste Disposal tank should be supplied by ELF.
•
Keep on board 300 m³ of mud to anticipate the risk of transition zone.
•
LCM stocks levels.
LOGISTIC ♦
Stocks and Volumes
SAFETY STOCK
VOLUME
Kept temperature at 50°C in and 60°C out. Maintained OWR at 75/25
Gellation
Pollution
♦
FIELDS RESULTS
3
!
!
XP-07 base fluid: for 150 m3 of mud. ! Chemicals: for 150 m3 mud. ! 50 m³ Kill Mud: 1.95 SG. ! Barite in bulk: 150 tons (then 400 tons at the end of section). ! BARACARB-50: 3 tons. ! BARACARB-150: 3 tons. ! Barofibre / Steelseal: 3 tons.
PARAMETERS
INDICATORS
TYPICAL
END OF SECTION
CHEMICAL •
SG = 1.66
•
OWR = 77 / 23
•
Budget : £
CONCENTRATION
COST
RECOMMENDATIONS ♦ ♦
XP 07 Base oil = 550 litre/m³ Drill water = 160 litres/m³
♦ ♦ ♦
Barite = 700 kg/m³ CaCl2 brine = 19.69 litres/m³ Lime = 39.94 kg/m³
♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦
EZ MUL 2F =45.36 litres/m³ Duratone HT = 11.7 kg/m³ Geltone 2 = 4.5 kg/m³ RM 63 = 3.42 kg/m³ Suspentone = 3.71 kg/m³ Baracarb-150 = 8.5 kg/m³ Baracarb-50 = 14 kg/m³ Baracarb-600 = 1.5 kg/m³ Barofibre = 2.2 kg/m³ Soltex = < 7 kg/m³
♦
Good behaviour of XP07 mud system .Mud specifications in line with the program.
4
FIELDS RESULTS
!
Average Cost : +/xxx £ / m³
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
4.6
10 ¾ “ x 9 7/8” casing and cementing Option N°1 : In the nominal case the 10 ¾” – 9 7/8” casing will be run as a single string and must be cemented up to 200 metres above the X-over 9 7/8” x 10 ¾” installed above the 13 3/8” casing shoe . Option N°2 : If hole conditions dictate there is the option to run the 9 7/8” casing as a liner with a 10 ¾” tie-back casing .The casing string is a tapered of 10 ¾” (110.2#) by 9 7/8” (66.9#) casings ( Liner ). - A temporarily Uncemented 10 ¾” tie back will be run after the cement job of the 9 7/8” Liner after displacing a CaCl2 / CaBr2 brine in the 13 3/8” x 10 ¾” annulus before the reconnection of the Tie-Back . The brine will be treated with corrosion inhibitor and bactericide . - Or the Tie-back will be Cemented up to 500 metres above the receptacle by . For the single string “ HP HT “ Bottom and top plug cementing head will be used . ( supply by ODDCC , see drawings ) Running the Casing. Prior to run the casing, the gel strength and yield point must both be reduced, the yield point + 15 lb/100ft², and the 10’ gel to < 23 to avoid excessive surge pressures when running in. Pilot tests will be completed by the mud engineer to determine the optimum treatment levels. This can best be accomplished by additions of OMC 2 or by addition of base fluid. Care should be taken so as not to over treat the system with OMC 2 that can cause barite sagging or settling. Swab and surge calculations should be run on the actual data of the time to optimise the rheological properties and casing running speeds, to ensure they are well within the limits of the LOT at the 13 3/8” shoe. Cementing job The 9 7/8” casing will be cemented with lead and tail slurries ( 400m of tail slurry ). Fluid design : ! spacer 1: Preflush 0.76 SG. –
Chemical wash
3 to 5 m3 ( Has to be adjusted with Surfactant )
! spacer 2: Spacer at 1.70/1.75. YP/PV 25/40. 9
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
Contractor Spacer Viscosifier Surcactant Barite Defoamer as required
Dowell Mudpush XTO 16 kgs/m³ U66 - 47.6 l/m³ for density
Halliburton Spacer 500E+ 20 kgs/m³ SEM7 - 80l/m3
! - Lead slurry, retarded and extended 1.75 SG – VOLUME = Theoritical + 20%
G cement Silica Fluid loss Extender Bentonite Retarder Drill Water !
Dowell Dyckerhoff 35 % Bwoc D143 – 1% D145 – 7l/T 1.2 % D161 – 84 l/T 681 l/T
Halliburton Lafarge 35% Bwoc Halad 100 - 0.5% Silicalite - 50 l/T 1.5 % HR12 – 0.12% 659 l/T
Tail slurry: gas tight 1.92 SG. - VOLUME = Theoritical + 20%
G cement Silica Fluid loss Extender Retarder Drill Water Dispersant
Dowell Dyckerhoff 35 % Bwoc D143 – 1% D145 – 7l/T D161 – 60 l/T 473 l/T B78 – 3.1l/T
Halliburton Lafarge 35% Bwoc Halad 100 - 0.75% Silicalite - 90 l/T HR12 – 1% 478 l/T CFR3 – 0.5%
Remarks: 1. all the formulations are indicative, they must be confirmed by laboratory tests performed with samples coming from the rig before the cement jobs. 2. For an accurate displacement, the internal diameter of the Casing must be measured on 10% random joints.
10
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
Cement slurry properties : ! Lead slurry
Density Yield Thickening time Fluid loss Free water Compressive strength at BHCT
1.75 SG. 1280 l/t > 12 h < 150 ml 0% > 100bar 48 h
! Tail slurry
Density Yield Thickening time Fluid loss Free water Compressive strength at BHCT
1.92 SG 997 l/t 9h < 40ml <0% >200bar 24 h
11
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
4.7
Experience :
This programme is an example issued prior each cementing operation . Purpose : Set a 10 ¾” x 9 7/8” Casing just above the Base Cretaceous Unconformity ( the transition zone ). The goal of the cement job is to realise a good shoe integrity , obtain 100% Displacement Efficiency by using laminar flow with a synthetic base mud , pressurised and tested the production casing to 863 bars { 12525 PSI } after the bump with ODCC HP/HT plugs. The following are some recommendations for the 10 3/4”x 9 7/8" cement job on G8 well : A - Current Well status : 12 ¼” open hole 5512 m MDBRT Shoe Depth :
5500 m MDRT ( 12 m of pocket )
Float collar :
5464 m MDRT ( 3 joints )
Landing collar :
5320 m MDRT ( 15 joints above the shoe )
Top of cement
+/- 3340 m MDRT ( 200 m above XO 9 7/8” x 10 ¾” @3540 m )
Geology
Top Hod Top Herring Top Plenus marl Top Hidra Top Rodby
4553 m ( 4035 m TVDrt ) 5298 m ( 4756 m TVDrt ) 5437 m ( 4895 m TVDrt) 5440 m ( 4898 m TVDrt) 5520 m
B - Centralisation for this casing must be as per following : Casing Configuration : 1 shoe joint . 2 joints ( Baker locked ) 1 float collar joint 12 joints ( Baker locked )*** 1 landing collar joint .( ODCC) * The aim is to obtain +/- 200 m of shoe track - 2 Solid SpiraGliders ( 9 7/8” x 12” OD ) per joint over the first Five joints. 1 Solid SpiraGliders ( 9 7/8” x 12” OD ) per joint from the float collar to the top of the landing collar - 1 Solid SpiraGliders ( 9 7/8” x 12” OD ) per two joint from the L C to the X-over 10 ¾” x 9 7/8”
12
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
-1 Solid SpiraGliders ( 10 ¾” x 12” OD ) per two joint above the X-over 10 ¾”x 9 7/8”to 3340 m The calculated stand off of the casing is above 85 %. From TD to 5000 m and 64 % above
C - Pre-job preparation : 1) Ensure all pits (to be used for the preparation of spacer) [suggest transfer and slug pit are used for the preparation of this water based fluid], cementing line to the rig floor are thoroughly cleaned out and flushed through with fresh water. 2) The casing was drifted and dimensionally controlled in order to better assess the ID of the joints which will be used for the displacement calculation . 10 ¾” 110.2# Average ID: 8.715“ Volume = 38.49 l/m 9 7/8” 66.9# Average ID: 8.624” Volume = 37.67 l/m Reference : ( G5 = 37.7 l/m -G7 = 37.68 l/m - G6 = 37.57 l/m - F1 = 37.60 l/m - F2 = 37.8 l/m )
3) Check HP/HT plug and cementing head ( ODCC equipment )Note : Installation of the plugs inside the cementing laborious , a special concern to install the bottom plug with the bar in ( risk of damage of the “ O “ ring seal ) . Check the valves .
Note : Back up Option for Cementing Head if not available on time - Dowell “9 5/8” cement Head + X-over 10 ¾” Vam with ODCC Plugs installed see drawing -
4) Tally ( length , composite casing , colour code etc … ) , see appendices Preparation of Spacer : Mud Push XTO or Spacer 500 E+ The spacer consists of 25 m³ of Spacer MudPush XTO ( see Dowell formulation ) weighted to 1.70 SG with a yield point of 17 / 20 @ room temperature. Once the freshwater has been added to the pit the chloride content of this water should be checked, the result noted and a sample of this water retained. Take a sample of spacer when complete, measure rheology at mix + temperature , note result and retain.( compare with the formulation ) Note : Rheology of spacer not in conformity with the laboratory results , adjustment of chemical on the rig site .YV =13
13
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
D - Running procedure and Fluid pumping Sequence Break circulation at the 13 3/8” casing shoe to establish parameters. Circulate 10 / 20 mins at 1500 l/min record weight up & down . Note on G7 : Break circulation with 20 bars at 566 l/min after 37 hours . Note on G5 : Break circulation with 45 bars at 1150 l/min after 36 hours .
Note on G5 : Due to the elevated weight of the casing the running speed has been adjusted to avoid shocks in drilling line drum .( the water cooling hose was replaced on draw works ) Note on F1 : At 4902 m Draw work fail to lift casing due to the clutch slipping - Cool down clutch with air & water . - According to the calculations, at bottom, the string weight should be ± 660 metric tons. ( or 1,455,026 lbs) Note on G7 : Up Weight : N/A - Down weight : 574 tons Note on G6 : Up Weight : N/A - Down weight : 565 tons ( with 300 mof casing empty ) Note on G5 :Up weight : 627 tons - Down weight : 582 tons . Note on F1 :N/A - Down weight : 630 tons .( with 1500 m of casing empty, Differential pressure max on float equip ment = +/- 2500 PSI ) Note on F2 : ran casing with 1500 m of casing empty Note on F3 : ran casing with 1500 m of casing empty – Up weight 570 T , Down weight 540 T Note on F4 : ran casing with 1500 m of casing empty – String weight 475 T Note on F5 : ran casing with 1500 m of casing empty – String weight prior to land 495 T
- Circulate last joint and land casing hanger ( +/- 2 m stick up ) - Install XO + Cementing head . The casing has not to be reciprocated close to the landing shoulder . If we need to pick up to cure a pack off at the casing hanger then pull out inside the riser and circulate ( see VETCO manual ). - Break circulation slowly and check surface pumping pressure at previously established rates Whilst running in the hole with 10 3/4”x 9 7/8”, select 1 high pressure mud pump and check seals , liners . Note on G5 : No circulation to reach the casing depth ( no Fill ) Note on G6 : No circulation to reach the casing depth ( no Fill ) Note on G7 : No circulation to reach the casing depth ( no Fill )-Flow =1700 l/min ,P = 138 bars Fluid pumping sequence : 14
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
Circulation prior to the job should be , at a minimum, 1.5 times complete Annular Volume or entire casing contents (whichever is the largest). The flow rate will be gradually increased while monitoring for losses. The maximum flow rate will be 1700 l/min. G5 : Break circulation with 30 bars after 60 hours F1: Break circulation with 36 bars after 61 hours . G6: Break circulation with 35 bars after 63 hours . F2: Break circulation at bottom @ 1500 l/min - SPP = 124 bars . F3: Break circulation at bottom @ 1500 l/min - SPP = 119 bars . F4: Break circulation at bottom @ 1500 l/min - SPP = 138 bars . F5: Break circulation at bottom @ 1200 l/min - SPP = 110 bars .
E - Cementing Operation : Mix and Pump 1) - 50 m³ of low rheology ( PV=33 , YV = 5 - Gel 10 = 20/25 ) mud at 1.60 SG ahead of spacer . 2) - 25 m³ of Mud Push XTO at 1.70 SG ahead of cement slurry .U66 as surfactant 3) - Pump CHEMICAL wash ( 5 m³) from Dowell displacement tank ( DW + 47.6 l/m³ of U 66 ) 4) - Drop after the Bottom plug . 5) - Slurry formulation as per attached Dowell Fax. The Volumes required are as follows: - Lead Cement Slurry : Volume to fill open hole annular volume + 20% excess , TOC = 3340 m . Estimated volume : Annulus volume Excess 30% + rathole 171/2 ”
45 m3 10 m3
Total Lead :
55 m3 at 1.75 SG
- Tail Cement Slurry : Volume to fill open hole annular volume to 5000 + 20% excess on open hole + FC / shoe track . Estimated volume : Annulus volume : Excess Shoe/FC
14.8m3 2.9 m3 6.78 m3
Total Tail:
25 m3 at 1.92 SG
The tail slurry mixing water will be mixed inside the Dowell batch tank . Monitor density throughout mixing of tail slurry with a pressurised mud balance. Take a sample of the slurry during mixing and check rheology. 15
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
6) Drop Top plug. 7) Displace (RIG Pumps) with SBM mud ( @ 1.60 SG ) at 1500 litres/min reducing the flow to +/- 500 l/min before the bump ( +/- 45 bars ∆P differential pressure) and bump the plug. Note G5 : See Shearing Bottom plug to 3700 PSI instead 2200 PSI Note F1 : See Shearing Bottom plug to 3140 PSI Note G6 : See Shearing Bottom plug to 2100 PSI Note G7 : See Shearing Bottom plug to 2428 PSI Note F2 : See Shearing Bottom plug to 2714 PSI Note F3 : See Shearing Bottom plug to 2771 PSI Note F4 : See Shearing Bottom plug to 3714 PSI Note F5 : See Shearing Bottom plug to 2928 PSI
ECD estimation before bump the plug ECD estimation before bump the plug
: :
EMW at TD ( at 1500 l/min ) EMW at TD ( at 250 l/min )
Surface pressure before Bump
:
± 1300 psi ( at 450l/min )
Surface pressure before Bump on F1 Surface pressure before Bump on G6 Surface pressure before Bump on G7 Surface pressure before Bump on F2 Surface pressure before Bump on F3 Surface pressure before Bump on F4 Surface pressure before Bump on F5
: : : : : : :
1142 PSI at 470 l/min 580 PSI at 500 l/min 571 PSI at 500 l/min 628 PSI at 500 l/min 928 PSI at 500 l/min 1371 PSI at 500 l/min 714 PSI at 500 l/min
NO BUMP
NOTE : If no bump , limit over-displacement to 150 m of the +/- 200 m shoe track . Bottom plug Shearing = 2200 PSI Theoritical TBA DISPLACEMENT : 207 m³ including compressibility of 50% of the Hydrostatic mud column. ( Theoritical displac. :203.306 m³+ 3.595 m³ = 206.901 m³ )
F - Casing Pressure Test : 1)Bump plug to 210 bars ( surface pressure ) and hold for 5 mins . Check floats holding . Pressure up to 450 bars to latch the HP/HT ODCC plug for 5 mins then remove XO and cementing head . 2) Make up HP Circulating head and pressure test casing to 12525 PSI ( 863 bars ) for 15 minutes (stabilised ) Pressure test will be done by step ( 300 / 500 /600 /800 /900 bars , i.e ) ( Note : mud compressibility => 3.08 litre / m³ / 1000 PSI with 1.63 SG) or 4.45 litre / m³ / 100 Bars
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On F1 : volume pumped to reach High pressure = 7.552 m³ . On G6 : volume pumped to reach High pressure = 8.427 m³ . On G7 : INCIDENT : Stop test due to leaking packing on DOWELL UNIT - Repair – Test Positive to 873 bars .Bleed off volume = 8.100 m³ . On F2 : volume pumped to reach High pressure = 7.960 m³ . On F3 : volume pumped to reach High pressure = 8.100 m³ . On F5 : volume pumped to reach High pressure = 8.020 m³ .
3) Remove HP head , disconnect + retrieve hanger r/tool and continue with Vetco wellhead procedure .( flushing tool …etc..), Notes: - All samples of fluids should be 1 litre in size.
Temperature Estimation : BHST 180 ° C
New API BHCT 154° C
Cemcade BHCT 130 ° C
Enertech BHCT 125 ° C
PWD : ( drilling .3100 l/mn at 5500 m) == > 157 ° C at 5500 m . Thickening Time : Tail Slurry : BHCT = 130 °C " 9 Hour 34 min Compressive Strength
at 160 °C" 3650 PSI after 24 hours
Thickening time ; Lead Slurry : BHCT = 130 °C " 12 hours 52 min Compressive Strength at 130 °C " 700 PSI after 24 hours .
17
General note on high pressure testing of production casing strings on plug bump (HPHT wells) Advantages • If the casing design is suitable the casing can be tested in its entirety to a higher pressure than when the cement is set (the back-up pressure in the cemented section is much lower than the hydrostatic pressure of a column of mud and green cement). • The internal and external pressure profiles are known (cement still in a liquid state) • Unlike pressure testing with the cement set, there is no risk of damaging the cement bond. • It can be cost effective by eliminating the time required to make staged pressure testing with a packer. • There is no risk of damaging the casing with a packer (packer slips damaging the inside of the casing). • If the casing is tested after the cement is set the wing valve of that casing annulus is normally left open. If the casing should fail while pressure testing there is a massive shock on this annulus and a high pressure fluid surge through the bleed-off line from the wing valve - this has a potential to damage the well and to shock any un-secure lines from the wing valve.
Drawbacks • If the float equipment fails there is a potential to washout the cement in the shoe track and around the shoe. To avoid this the shoe track volume must be at least equal to the compressed volume of the fluid inside the casing while pressure testing (on our HPHT wells we commonly use 20 joints in the shoe track). • If barite fallout is assumed in the production casing annulus then the pressure differential achieved on plug bump is not normally sufficient to achieve the same differential pressure as a gas to surface load. However, it can be argued that in a gas to surface case the ballooning of the production casing would increase the pressure in the production casing annulus to offset the loss in hydrostatic pressure due to barite fallout.
Equipment To date we have used ODCC high pressure landing collars for our production casing strings: Production String Max surface pre Circ T (appro Number of Comment bump static T 10 3/4” - 9 7/8” prod cs 900 bar 155°C / 185 7 All successfu 10 3/4” tie-back 950 bar 100°C / 125 4 Note 1. 7” - 7 5/8” tie back 932 bar 155°C / 185 2 Note 2 1. One failure attributed to not slowing down sufficiently for the plug bump. 2. One failure when the bottom plug landing was incorrectly interpreted as the top plug landing and failing. Note: • Both of the failures above occurred on early HPHT wells when the displacement volume was not accurately known (no callipering of casing joints or allowance for fluid compressibility). • The tie-back landing collars have a poppet system which allows fluid to pass up through the landing collar after the top plug has landed (other wise the tie-back seal assembly could not be stabbed into the tie-back receptacle due to compression of the trapped fluid). • On most of our wells we normally bring the pressure up to 50% of the final bump pressure and wait 15 minutes before bleeding off to install the high pressure swedge. The casing is then pressure tested to the full bump pressure required e.g. 900bars.
CEMENTING RECOMMENDATIONS
10 3/4” x 9 7/8” PRODUCTION Casing set into Hidra Formation PARAMETERS
INDICATORS
RECOMMENDATIONS •
PRODUCTION COLUMN DESIGN
FLUIDS WEIGHT
Good casing integrity •
Top of cement inside the 13 3/8 x 10¾” annulus
•
Pressure test column to 900 bars.
•
To help displacement, the specific gravity of spacer, lead slurry must be staged with at least 5 points difference. Mud < Spacer < Lead Slurry < Neat Slurry. We finished drilling the section with mud at 1.65sg, the spacer was 1.70sg, lead slurry at 1.75sg and tail slurry at 1.92sgG. These weights have to be compatible with: - Pore pressure. - Fracturing pressure (losses).
Determination •
SLURRIES THICKENING TIME
♦
T.T. depends on the Bottom Hole Circulation Temperature and the pressure.
♦
BHCT estimated with several methods: API table Enectech software Cemcade sofware MWD, PWD…
-
♦ COMPRESSIVE STRENGTH
♦
Obtain a good bond between casing and formation to prevent any influx through the casing annulus in optimising of the slurries placement, through the design of the fluid properties and the flow rate.
RESULTS / Remedial Action § §
§
Founded several values of BHCT for a same BHST (ex: API 140°C, Enertech 120°C, Cemcade 125°C, MWD records 137°C, PWD 142°C for BHST 185ºC). • Check the T.T. of lead and tail slurries at the maximum expected temperature according to the simulation • Control it at the others temperatures (including the circulation temperature estimated at the top of lead slurry). • Adjust T.T. to have a minimum safety margin of 2 hours on the cement job timing.
§
Few formation losses during cement jobs
§
Found top cement above planned depth.
§
Lead slurries: G4: 7h52 at 140ºC G5, G6, G7: 10h15 to 14h27 at 130ºC. Franklin: 9 h 15 to 12 h 15 at 125ºC.
§
Tail slurries: G4: 11h31 at 140ºC G5, G6, G7: 08h10 to 9h18 at 130ºC. Franklin: 8h36 to 9h37 at 125ºC.
§
Tail: 2600 PSI after 24 hours at 125ºC
§
Lead: 1000 PSI after 40 hours
Change in thickening time values of slurry did not have a pronounced effect on the set of cement at BHST.
Check C.S. after 24 hours of WOC
•
Check C S at top of liner
•
For the tail the C.S was checked at the simulated temperature (Enertech) after 24 hours of WOC. For the lead slurry the C.S was checked at the BHST estimated at the TOL (125 °C).
1
All FIT compatible to drill reservoir, 2.30sg. Good CBL in front of lead slurry but bad results in front of tail slurry. Still working on spacer properties. TOC: 500 to 1000 m above planned.
Samples set after 36 hours at room temperature
PARAMETERS
INDICATORS
♦
RECOMMENDATIONS •
A slurry with bentonite (1% BWOC) is recommended and easier to design than a slurry with polymer as extender.
•
To avoid dehydration of slurry in front of permeable formations and prevent any gas influx, reduce fluid loss of tail slurry below 150cc with filtrate reducer as D143, D134 or Halad 100.
•
Adjust the TT to have the safety margin (+40%) for the cement job with retarder (D161 or HR12). The quantity of retarder in mixing water is crucial, so special care must be taken to calculate the quantity required and to measure it.
Lead slurry 1.75sg
SLURRIES DESIGN ♦
♦
Tail slurry 1.92sg
• Spacer design
SPACERS ♦
SLURRY VOLUME
Compatibility with SBM and Cement. ♦ Lead to 200 m above 13 3/8 casing shoe ♦ Tail: 400 above 10 ¾” shoe
♦
DISPLACEMENT
•
Adjust fluid rheology in order to have Mud < Spacer < Lead Slurry < Tail Slurry in well conditions.
•
Check Rheology under high temperature to avoid any settling.
•
Rheology sensitivity test with blends at: 5 / 10 / 20 / 50 / 75 / 100%.
•
Cover the X-over 10 ¾” x 9 7/8” with slurry
Rheology
♦
Ø •
ID from Micrometer typical measurements 10 ¾” casing ID: 8.73” – 38.62 lit/m 9 7/8” casing ID: 8.617” – 37.63 lit/m.
♦
Rig pumps
♦
Check HP/HT ODCC plugs and modified head to avoid top plug to remain in head.
On the first wells we used an emulsified spacer (15m³ oil/water based) pumped just after a pill of base oil (3m³) then followed by lead and tail slurries. Later on, due to the bad quality of the mud removal, we changed: - the pill of base oil by a pill of thin mud (40m³) - the type of spacer, using a 100% water based spacer with surfactant, to help bond between Formation/Cement/Casing.
Typically 10% excess This check is crucial to achieve a good displacement of the slurries. Average on 4 Franklin wells: the difference in volume between the nominal ID and the measured ID accounted for +3.2 m³ on the displacement calculation, this volume is equivalent to 85 m of casing.
•
The extra volume due to the mud compressibility of the fluid can be calculated but must not be included in the displacement. This volume on the 4 wells on Franklin was + 2.4 m³ average, or 63 m of casing.
•
Displacement done with dedicated pump, rig pump efficiency (typically 97%).
•
Do not over displace 50% of the shoe track.
2
§
§ § §
RESULTS / Remedial Actions Due to the large volume required, the lead mixing water has been mixed in a mud pit. Tail mixing water prepared in the batch tank. No use of LAS. NO MAJOR PROBLEMS FOR MIXING. Additives to be supplied in drums.
§
Better quality of displacement on the last wells than the first ones.
§
Still better quality of CBL in front of Lead Slurry than Tail Slurry. Only on F3 well, we notice a good CBL below the landing collar. The cement sheath above the landing collar had been damaged by the pressure test at 900 bars of the column, 2 hours after pumping the slurry. Creation of a micro annulus.
§
Lead 30 to 46 m³
§
Tail 21 to 34 m³
§ Shoe track: 220 m. § All placement: OK Shearing bottom plug: typical 200 bars. Bumped plug: OK, except F4 where the top plug remained in the head. Press. Test to 900 bars: OK except F4.
29/5b FRANKLIN - 12 ¼" OPEN HOLE / 10 ¾ x 97/8" CASING CEMENTATION Well Date Top of cement (real) Casing shoe Height BHST BHCT Type of slurry Theoritical slurry volume Excess Total slurry volume Weight of cement (G+S) Slurry weight Cement Lafarge G Silica flour Water Additives
m m m ºC ºC m³ % m³ ton sg % % type
l/ton or %
Thickening time (70BC) Compressive strenght 12 hr Compressive strenght 24 hr Flow pattern Spacer Plug type Displacement
hr:min PSI PSI type sg type
29/5b-F1 20/04/1998
29/5b-F2 11/08/1998
29/5b-F3 22/11/1998
29/5b-F4 12/03/1999
29/5b-F5 22/06/1999
3400 (2492) 5118 1300 418 183 125 lead tail 34.5 20.6 40 40 46.8 25 84 33 1.75 1.92
3300 (2370) 5002 1282 420 183 125 lead tail 33.2 22.7 40 20 45 28 90 1.75 1.92
3250 (2275) 5146 1250 646 178 125 lead tail 36 28 0 10 30 34 77 1.75 1.92
3762 (3272) 5425 1238 425 179 125 lead tail 34.5 21.5 0 10 35.8 23.85 41 30 1.80 1.92
3258 (2840) 5264 1606 400 178 125 lead tail 42.7 20.2 10 10 46.5 21.3 41 43 1.75 1.92
100 100 100 100 100 35 35 35 35 35 Fresh Fresh Fresh Fresh Fresh 1.5% Bento 1.5% Bento 1.5% Bento 1 lit NF 5 1 lit NF 5 1 lit NF 5 1 lit NF 5 1% HR-12 1.3% HR-12 1% HR-12 1.3% HR-12 0.7% HR-12
100 35 Fresh
0.9% HR-12
0.5% Hal-100 0.75% Hal-100 0.5% Hal-100 0.75% Hal-100 0.5% Hal-100
0.9% Hal-100
100 35 Fresh 1.5% Bento
100 35 Fresh
100 35 Fresh 1.5% Bento
100 35 Fresh
0.85% HR-12 1% HR-12 0.93% HR-12 1.15% HR-12 0.5% Hal-100 0.75% Hal-100 0.5% Hal-100 0.75% Hal-100
50 lit Sil-97L 90 lit Sil-97L 50 lit Sil-97L 90 lit Sil-97L 50 lit Sil-97L 90 lit Sil-97L 50 lit Sil-97L 90 lit Sil-97L 50 lit Sil-97L 90 lit Sil-97L 0.5% CFR-3 0.5% CFR-3 0.5% CFR-3 0.5% CFR-3 0.5% CFR-3 10:45
09:20
11:05
09:37 800 3100 (48 hr) 3600 (48 hr) 1250 (48 hr) 3800 (48 hr) laminar laminar laminar laminar Spacer 500E+ Spacer 500E+ 1.70 1.70 ODCC HPHT ODCC HPHT 2 plugs 2 plugs
09:15
08:36 2800 860 3100 laminar laminar Spacer 500E+ 1.70 ODCC HPHT 2 plugs
12:15
08:36 1800 100 3300 laminar laminar Spacer 500E+ 1.75 ODCC HPHT top plug not realesed.
11:22
09:26
130 2700 laminar laminar Spacer 500E+ 1.70 ODCC HPHT 1.60sg SBM
4.9
Temperature Modelling
Experience from previous wells drilled has shown that drilling the bottom of the 12 ¼” section gives the highest drilling fluid temperature at surface . The real data from 22/30 C - G 4 have been used to validate the results from the thermal model Enertech Wellcat which is become the standard for HP/HT applications . As a guide , the undisturbed formation temperatures can be taken as 194 °C for the Franklin sands and 207°C at TD for the Pentland Formation . 5 5/8” logging No 1 : Temp recorded = 200 °C No 2 : Temp recorded = 199 °C No 5 : Temp recorded = 207 °C ( to be confirmed on the next well ) The table below shows predicted temperature for one typical ( Drilling 8 1/2” ) using the thermal model Enertech Wellcat . Well data : Depth = 5555 m MD ( 5413 m TVD ) - BHST = 184 °C -SG =2.17 - Flowrate = 1000 l/min.
Parameters
Well site
ENERTECH
Bottom Hole Static Temperature ( BHST )
184 ° C
184 ° C
Temperature IN
41 ° C
43 ° C
Temperature OUT
46 ° C
45 ° C
** 147 ° C +/- 2°C
155 ° C
Bottom Hole Circ. Temperature ( BHCT )
** PWD sensor
Bottom Hole mud Temperature Temperature measurement while drilling has not been able to record with a good accuracy . A new downhole PWD tool with temperature sensors has recently been developed to assist drilling of the reservoir section .During the Downhole hydraulics measurements tests after a close analysis were done on the data recover from different sensors installed in the drilling string . It appears clearly that the 3 sensors are given same temperature values .These common values are very close to the temperature of the mud inside the drill string . When using the RTPWD tool in real time mode , the temperature data sent to the surface and available while drilling is not the RTPWD temperature sensor reading but the temperature reading of the sensor located inside the telemetry module of the MWD assembly .
Therefore , in order to get accurate annulus Bottom Hole Circulating Temperature ( BHCT ) for using on Hydraulic calculations and BHCT in cementing , it recommended to use the following correction : Take the real time Temperature sent to the surface ( telemetry module temperature ) = Ta Subtract 2°C to get the internal mud temperature above the bit = Tb = Ta - 2°C Add 7°C to get the annulus mud temperature = BHCT = Tb + 7°C = Ta + 5 °C ! BHCT = T a + 5°C Recommendation : In any case measured BHCT will be cross- checked with the ELF temperature prediction software ( WT-Drill from Enertech )
Safety & Mud cooler : On the previous wells drilled the highest drilling fluid temperature at surface was reported at the bottom of the 12 ¼” section which is not the case on G4 . The installation of Mud Coolers to minimise the temperature was incontestable due to the fact that the maximum temperature recorded was only 61 °C compared to the flow line peak recorded between 76 - 83 °C .The use of mud cooling system during the critical section has been shown to reduce the flow line temperature by 10°C to 15°C , leadind to a better working environment . Wellcat Printouts show predicted temperature for 3 predominate drilling phase using Enertech . ( see attachments )
12 1/4" Temperature Prediction - Elgin / Franklin 200
180
160
Temperature in °C
140
120 Enert. BHST MWD BHCT pred.
100
Temp in °C Temp out°C 80
Mud Cooler Mud Cooler
60
40
20
0 2930 3095 3139 3160 3540 3600 3612 3756 3842 3896 3970 4008 4148 4236 4240 4329 4416 4565 4612 4665 4730 4817 4932 4940 4980 5000
Depth TVD
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5.
8 ½” SECTION ( HP/HT section ) Interval: from +/- 5300 m (MD ) 9 7/8” shoe to +/- 6450 m (MD). Maximum expected BHP: Lower Cretaceous 2.10SG EMW Kimmeridge clay 2.10 SG EMW Franklin sands 2.11 SG EMW Pentland 2.07 SG EMW Expected temperatures: 204°C BHST at 5900 m TVD.
5.1
Purpose: Option 1:
Drill and core 8 ½” hole through the remaining of the Cretaceous, the Upper Jurassic and the top of the Middle Jurassic (Pentland formation) to 60m below the Franklin Sands. Requirement is to cover reservoir(s) and ensure a good isolation between Franklin sands and Pentland. Option 2:
According to results of first wells it could be decided to develop the Pentland. In this case, two options are available: ! Drill 8 ½” to 60m TVD below Franklin Sands, RIH and cement a 7” liner. Then drill 5 5/8” to 50m TVD above Bottom Pentland and set a 4 ½”. ! Drill 8 ½” to 50m TVD above Bottom Pentland and set a 7” liner. In the case of problem when drilling the Pentland reservoir, a 7” liner could be set below the Franklin Sands. The Pentland would be drilled in 5 5/8” and cased with a 4 ½” liner. 5.2
Drilling procedure :
5.2.1
GENERALITY :
Tag the cement. Increase the mud weight to 2.15 SG. Drill out cement, clean rat hole and 5 m. of new formation. Perform the LOT (expected 2.30 SG EMW, limited to 2.40SG EMW). Drill to ± 5m. above Franklin Sands. Coring of Franklin sands as programme . Drill 60 m TVD below Franklin Sands. Run logs. Drill ahead to TD, taking one core in the Pentland. Run and cement 7” or a tapered 7” x 4 ½” liner. 5.2.2
Hydraulic Tests : Reference : “DOWNHOLE PRESSURE & TEMPERATURE Measurements on 22/30 C – G4 “ Gelation tests while tripping in the hole:
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Purpose: Obtain transient pressure data which characterizes the effect of mud gelation on flow properties. Also obtain surge/swab data with no flow. These tests are performed while RIH to exploit the fact that no circulation has occurred for a long period. The effect of pipe rotation on breaking mud gels will also be studied. Drill pipe rotation during these tests will be minimal.
Surge tests while tripping: Purpose: Provide about 25 stands of surge data at varying speeds in hot, gelled up mud while tripping in the hole inside the 9 5/8” casing. Gelation tests on bottom: Purpose: Obtain transient pressure data which characterizes the effect of mud gelation on flow properties. Also obtain surge/swab with no flow. Circulation tests on bottom: Purpose: Obtain temperature and pressure data with time while circulation at different flow rates through stationary drill pipe. Surge/swab tests on bottom while circulating: Purpose: Obtain surge/swab data while circulation at a constant rate and with no flow. Circulation allows a quantitative measurement of return flow after the first surge. Effects of rotation on circulating properties and a shut-in period: Purpose: Obtain temperature and pressure data with time while circulation at different flow rates through rotating drill pipe. Two rotary speeds will be examined. Also monitor temperature build-up and any mud sag phenomena. Swab tests while tripping: Purpose: Provide about 25 stands of swab data inside the 9 7/8” casing during normal tripping operations.
5.3
Expected problems : Mud weight control. The main problems are experienced whilst drilling through the transition zone, when the pore pressure and fracture pressure are close, leaving little room for error in mud weight. The control of the mud weight is of a paramount importance. • Fluctuation ESD (Equivalent Static Density) can be due to: - pressure variation, - temperature variation (from circulating profile to static profile). • Fluctuation of ECD (Equivalent Static Density) can be due to: - flow rate variation - pipe movement, i. e. Rotation . Tripping in or out . All this variation must be quantified to know exactly the pressure exerted by the drilling fluid. Failure to properly control the mud weight can lead to losses and gain instability.
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Differential sticking. Differential sticking into the Pentlands reservoir can occur. The pressure required to control the Franklin sands can be too high in front of the deeper reservoir. Reservoir pressure and formation temperature. • HP 1111 bars at 5364 m. TVD/SS. • HT 205°C BHST at TD. H2S: Hydrogen Sulphide was encountered in the previous wells 30 to 50ppm during testing. None was reported while drilling but over 4000 ppm were measured while recovering a core. Barite sagging (see 12 1/4” section) 5.4
5.4.1
Drilling fluids – Hydraulic : Synthetic base mud at 1.65 SG from the 12 1/4 “ section will be weighted to 2.15 before drill-out of cement and perform the LOT Typical composition of mud (2.15 SG, 85/15 OWR)
XP-07 EZ MUL 2F Lime DURATONE HT Water GELTONE Calcium Chloride Barite RM 63 SUSPENTONE BARACARB 50 BARACARB 150
(Base Fluid) (Primary Emulsifier) (Ca(OH)2) (Fluid Loss Control) (Viscosifier/Gelling Agent) (CaCl2) (Weighting agent) (Rheology Modifier) (Specialised Viscosifier) (Bridging LCM Material) (Bridging LCM Material)
3
418 l/m³ 67 l/m³ 20 kg/m³ 55 kg/m³ 75 l/m³ 3 kg/m³ 57 kg/m³ 1515 kg/m³ 1.5 l/m³ 4 kg/m³ 30 kg/m³ 6 l/m³
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5.4.2
Typical mud characteristics Weight PV YP YS Gels 0/10’/30’ Filtrate API Filtrate HP/HT E.S. Cl-(Water Phase Salinity) H/E Excess of Lime
5.4.3
: 2.15 SG : ALAP, typically 40-55 cPo : 15-20 lbs/100ft³ : 8 - 20 lbs/100ft³ : 16/25/35 : 0 cc : < 3 cc @ 190 °C : > 800 V : 225 g/l : 80/20 - 85/15 : > 1.5 to 2 g/l
Safety stocks Bulk material: Barite Cement G + Silica Flour
: 150 t : 100 t
Material in sacks or drums: BARACARB 50/150 :3t/2t 3 Chemicals to mix 300 m of synthetic base mud Mud / Base oil Kill mud 2.45 SG Liquid mud in surface Base Oil 5.4.4
: 50 m³ : 250 m³ : 75 m³
Recommendations : Mud weight: Continue with the XP-07 system from the previous section, adjusting the oil/water ratio towards 85/15 and the weight to 2.15 SG with Barite before drill-out the cement. A mud weight of 2.15 SG will be required for this entire section. A portion of the above mud may have to be back-loaded to accommodate the volume increase caused by the weighing up and conditioning of the mud system.
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Mud weight measurement: Calibrate the Halliburton balance daily with Calcium Bromide Brine and a Hydrometer. Temperature correction effects should be observed. Record mud weight and temperature at the flow-line and pits. Temperature: Due to expected bottom hole temperatures greater than 200ºC, the emulsifier concentration should be raised to 67 l/m³, and the DURATONE HT added to a concentration of 55 kg/m³ initially. The DURATONE concentration may require to be increased in order to maintain the filtrate to required specification as the interval progresses. Temperature and pressure calculations should be run before and during drilling operations to analyse the effective change in downhole pressure cause by the heating, cooling and circulating of the mud system.
Good ventilation is mandatory at the shale shakers and the pit room. The return mud at the flow-line is likely to have a temperature in the range 60°C - 85°C, where a measure of water and oil evaporation will take place. Seepage/losses/gain : Add 30 kg/m³ BARACARB 50 and 6 kg/m³ BARACARB 150 to the mud system and 1 - 2 sacks per stand while drilling the sands to ensure that enough fresh material is available for bridging purposes. BARACARB will effectively bridge across the porous sands minimising filter cake buildup, filtrate/whole mud invasion, seepage losses and differential sticking. Follow good well control practices by carefully monitoring pit level and background gas. Direct treatment with base fluid and chemical to the active system will not enable accurate pit level monitoring. All treatments to the active system should be to one of the reserve pits then added to the active mud. Pit levels may rise/fall (neither a kick nor downhole losses) due to variances in the generated downhole pressure (annular mud weight) caused by the relationship between pressure and temperature with depth. Increase mud weight only if absolutely sure of increase in pore pressure ( increase in temperature , shut in pressure , well instability , Kick etc.). Pore pressures and pit levels must be monitored carefully at all times due to the low tolerance expected between pore pressure and fracture gradients. Avoid rapid trip/running casing/ pipe movement to minimise swab and surge pressures.
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Hydraulics calculations under temperature/pressure should be used to plan for trips e.g. the requirement to break circulation after trips due to an increase in mud density in the upper hole sections due to the cooling effects of the mud system. The mud in the riser and upper 9 7/8“ casing will be cooler, heavier and thicker than the mud at the section TD after a trip out of the hole. These conditions will result in an increased ECD during initial circulating operations once back on bottom which could breakdown the formation. To avoid this problem, staged circulation will be made while running in the hole to heat up the mud and break the gel strengths of the mud. Induced lost circulation can be caused by: • Surge pressures while running in the hole (BHA/small diameter gauge hole). • High initial pump pressures and ECD required to break circulation (progressive gel strength of the cooler mud). We recommend the drill-pipe is rotated to break the gels strengths prior to starting circulation. • Barite Sag. See Appendix for further discussion. • " Higher annular mud density after a trip, caused by cooler mud and the weighted slug that was pumped prior to the trip. OWR: The OWR should be maintained at ± 80/20 - 85/15. Hydraulic: The yield point should be maintained in the range 15 - 20 lbs/100 ft2 in this interval combined with minimum PV’s and gels in order to optimise hydraulics for minimum ECD’s/surge/swab pressures. The optimisation of rheology will be critically important through this interval to minimise supercharging. A minimum circulating rate of 750 l/min is recommended to maintain adequate hole cleaning. HP/HT Filtrate: Maintain the HPHT below 3.0 cc @ 190ºC by the use of DURATONE HT, and EZ MUL 2F Differentially stuck pipe: It will be beneficial to treat the mud with 2 - 3 kg/m³ of CMO 568, oil mud lubricant. Recent research indicates that the force required to free differentially stuck pipe, is substantially reduced when the filter cake contains BARACARB bridging material and CMO 568.
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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H2S: Maintain excess Lime > 2 - 3 kg/m³, in order to offset any H2S intrusion into the mud system. Solids control: Run the shale shakers utilising the finest mesh screen possible. Shale shakers have to be attended to at all times, and screens changed as circumstances dictate to keep the optimum screen size on the shakers. It is also suggested that both oblong, square and pyramidal screens be available on the rig site and various combinations are tried for optimum performance. The base fluid wash gun should be available to clean the screens. Synthetic Oil on Cuttings: As in the previous section the Mud engineers performs the SOC on a composite sample every 300 metres or daily, whichever is the sooner. The mud engineer also collect all statutory samples while using synthetic oil base mud. Barite sagging: SUSPENTONE can be added to the mud system at 4 - 6kg/m³ in order to protect against Barite settling in the event of a large condensate/oil influx. Cement job: The mud should be treated with 2 kg/m³ DRILTREAT and EZ MUL 2F prior to cementing to minimise the effects of possible spacer contamination.
7
FRANKLIN 29/5b-F3 Hydraulics analysis 8½" hole
m
RT
º
lpm
bars
28/11/1998
5161
29/11/1998
5161
30/11/1998
5174
5091
1085
90
01/12/1998
5249
5166
1125
02/12/1998
5343
5259
1120
03/12/1998
5425
5342
04/12/1998
5595
5511
04/12/1998
5623
05/12/1998
5654
06/12/1998 07/12/1998
m/min
sg
ºC
sg
ºC
ºC
2.15
40
2.15
50
160
45
2.15
37
2.15
74
47
2.15
46
74
47
2.15
47
11
73
46
2.15
11
73
46
2.15
6 x 10
11
74
47
6 x10
11
74
47
9
6 x 10
11
74
9
6 x 10
11
74
200
9
6 x 10
11
200
9
6 x 10
11
9
6 x 10
11
8
3 x 24
10
199
9
6 x 10
11
71
90
199
9
6 x 10
11
90
193
9
6 x 10
11
1110
91
193
9
6 x 10
1110
90
201
9
6 x 10
5539
1120
115
205
9
5571
1124
130
197
9
5709
5626
1124
124
199
5757
5674
1130
130
175
08/12/1998
5807
5721
1100
130
09/12/1998
5807
5721
1100
15
10/12/1998
5807
5721
11/12/1998
5807
5721
12/12/1998
5807
5721
13/12/1998
5807
5721
14/12/1998
5807
5721
15/12/1998
5807
5721
16/12/1998 17/12/1998 18/12/1998 19/12/1998 20/12/1998 21/12/1998 22/12/1998
1100
15
200
10
6 x 10
12
10
6 x 10
12
10
6 x 10
12
m/min
ºC
cPo
lbs/100ft² lbs/100ft² EMW
EMW
EMW
EMW
EMW
EMW
55
15
12
Hidra
43
60
23
13
Rodby/Sola
2.15
51
57
21
15
Valhall/Heather
2.15
54
59
26
19
Franklin 'C'/'B'
47
2.15
51
65
27
16
Franklin 'A'
46
2.15
51
60
23
16
Pentland
2.15
46
2.15
57
26
15
2.15
46
2.15
51
56
22
15
47
2.15
47
2.15
50
51
17
14
47
2.15
47
2.15
52
52
22
15
72
46
2.15
40
2.15
53
51
21
14
72
46
2.15
40
2.15
53
51
21
14
2.15
51
21
14
2.15
51
21
14
51
21
14
69
21
15
2.15
69
21
15
2.15
69
21
15
2.15 72
46
2.15
43
2.15
52
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
5.5
EXPERIENCE
The attached table is a recap of the main lessons learnt .
8
HP / HT Section DRILLING FLUIDS RECOMMENDATIONS
8½” Drilling section PARAMETERS
INDICATORS • Gas level shows • Back ground gas • Well Flowing
DENSITY “ Key Factor “ IT IS IMPORTANT TO RECOGNISE THAT MUD WEIGHT CAN VARY SIGNIFICANTLY WITH TEMPERATURE
• Flow Check instable • Settling of Barite
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action ! All densities must be reported and corrected at 50ºC. ! Anticipated any degradation of mud for an extended static period. Solution: over-treated the mud before the specific operations
! Start the section with 2.15 SG with Low rheology • Increasing of Solids ! Addition of Premix Weighted at 1.85 / 1.95 SG is recommeded (Premix) Content ! see Baroid practices ! Keep LGS < 150 g/litre ! Calibration of Pressurised mud balance with ZnBr2 solution ! Pore Pressure on Fulmar Reservoir results : [ G4 i,e ]
REMINDER • Plastic Viscosity ( PV )
Franklin “ C “ - 2.10 EMW at 5357 m TVD MDT ➝ Franklin “ B “ - 2.06 EMW at 5489 m TVD Franklin “ A “ - 2.04 EMW at 5569 m TVD ANY INCREASING OF DENSITY MUST BE EVALUATED ! A tight control of the PV is essential Range : PV = 45 to 60 @ 2.17 Sg. ➝ Suspentone / Base oil / RM 63 may be used to increase the end Rheology
• YV Fluctuation High Temperature • Gellation
• Degradation at Bottom up after a trip (i.e.)
! Keep Yv at 15/20 under Static/Dynamic Temperature conditions ! No progressive gels have been reported. Flat gels : 29 / 31 / 38 (Gels 0 / 10 / 30 min) ! Bottom up samples must be compared to regular mud . ! Static ageing must be used to predict mud behaviour when the mud is to be static for an extended period.
“RHEOLOGY” • Low shear rheological properties
! The ratio of quality organophilic clay to rheology modified is critical ! Addition of SUSPENTONE as soon as barite sag start to be detected .( 3 to 5 kgs/m³ ) ! Experience :" see Baroid recommendations
• Yield Stress Maintained with RM 63 - YS = 5 - 8 lb/100 sqft²
7
PARAMETERS
INDICATORS
• API Filtrate • Change in HPHT filtrate values after :Bottom up • Hot rolling • Cake quality • “Barite Plug”
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action ! Should be all oil throughout. In the lower sections tight control across the sands may be required, especially if there is significant overbalance. ! HP/HT Filtrate will be checked at 175º C top section , then Filtrate should always be at the maximum BHST (200 ºC) at TD.
HP / HT Filtrate
< 3 cc at 190 °C ! Recommended treatment: >EZMUL 2F + Invermul 2F >Duratone HT >Lime >Baracarb 50 > Baracarb 150
REMINDER • “Low Fluid Loss Pill Practice ”
A “Mud core” has been recovered whilst the first core
10 kgs/ m³ 5 kg/m³ 5 kgs/m³ 10 kgs/m³ 5 kgs/m³
! Prior to tripping for a long extended period, spot an “over -treated” mud pill in front of reservoir: ➝ Specifications: >Ezmul2F + Invermul 2F 15 kgs/ m³ >Duratone HT 10 kg/m³ >Baracarb 50 20 kgs/m³ > Baracarb 150 10 kgs/m³
REMINDER ! Be aware that “Hydrogen Sulphide” has been encountered in Central Graben wells. ! In SBM system maintain lime in system at 3 to 5 kgs/m3. ! H2S procedures have to be initiated before this section ! In SBM mud the increased reaction of lime with surfactants greatly increases with temperature and reductions in mud alkalinity are common.
LIME EXCESS • H2S • CO2
ELECTRICAL STABILITY
FLASH POINT ! 90º C (BASE OIL)
• E.S.
➝ Range 1100.volt > ES > 700 volt Good behaviour of mud system.
➝ • • High temperature at ➝ Usually bottom hole section circulation’s rates are too low to cause a problem in 8½" diameter . Flow line At TD ➝ Temp in = 38º C with Flow rate = 900m l/mn Temp out = 42ºC. • ➝ ➝ A check of flash point must be done weekly in town.
TEMPERATURE
• Max Temperature REMINDER
W.P.S. (WATER PHASE SALINITY)
• Decreasing
➝ Temperature maximum recorded = 205 °C BHST
➝ ➝ This appears to only be important on the upper sections where clay instability can occur at chloride levels above 180 gr/l. ➝ Keep WPS > 190 gr/l
8
PARAMETERS
WELL-BORE STABILITY
INDICATORS
• • • • •
Shale “Cavings” Sticking Core Damage Calliper Losses in transition zone
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
➝In micro fractured shales, use a very low fluid loss mud. ( HPHT < 3 mls ) and add fracture sealing agent. ➝ Addition of Bridging agent is recommended > Baracarb 50 10 kgs / m³ > Baracarb 150 5 kgs / m³ Before drilling the pay zone > One arm caliper has been recorded on this section, giving a hole in gauge. ( 8.7” average )
REMINDER
EVAPORATION
• O.W.R. increasing (loss water phase) • Salinity ↑ • Increased gels
REMINDER
• Mud Behaviour • Thermal Degradation
! An oriented 4-arm calliper is recommended
• Add water: Increased filtrate and surface evaporation reduces the total water of the mud and, if not replaced, will in effect, “dehydrate” the system. Warning Any addition of water must be checked by ageing “pilot test” due to the contamination effect (Rheology affected). An increasing of OWR has been reported without any explanation But no impact on the behaviour of mud and Operations Typical Composition : Drilling Fluids @ 2.15 SG.
CHEMICAL
FONCTION
XP 07
CHEMICALS
Water Ca Cl2 E2 MUL 2F
Base oil
TOP SECTION
END SECTION
470 litres
470 litres
120 litres 30 g/ l 42 g/l
105 litres 20.83 g/l 76.2g /l
1460 g/l
1268 g /l
BARITE
Primary Emulsifier Weighting agent
Geltone IV
viscosifier
3.14 g/l
4.85 g/l/
Invermul 2F Duratone HT
Second. Emulsifier Fluid Loss control
0 g/l 27.67 g/l
9.13 g/l 38.52 g/l
CONCENTRATION
Lime RM 63
18 g/l 0.86 g/l
7.8 g/l 2.28 g/l
Suspentone
Rheology modifier Suspension agent
3.42 g/l
6.28 g/l
Baracarb 150 Baracarb 50
Bridging chemical
8 g/l 27 g/l
8 g/l 27 g/l
9
PARAMETERS
INDICATORS
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
• Anticipated treatment for Specific Operations :
Spot pill mud in the Open Hole , made of Active mud over -treated for fluid loss reduction .Displace in pump out mode . Formulation :
“ Low Fluid Loss Pill over-treated “
Logging/Coring/trippi ng
REMINDER • Kick and Losses simultaneously • Flow check inappropriate TRANSITION ZONE • B.G.G. Levels KIMMERIDGE CLAY
• Free Emission of gas in SBM
>EZMUL 2F >Invermul 2F >Duratone HT >Lime >Baracarb 50 > Baracarb 150
5 litres/m³ 5 litres / m³ 5 kg/m³ 10 kgs/m³ 5kgs/m³ 5 kgs/m³
Products concentration should be reported daily on the current mud. Action: > Anticipated risk of losses by adding Bridging agent in the mud (Baracarb , Duratone HT…) > Start the section with 2.15 SG or less. See reports ( Well Instability Report ) > Reinforce Flow check procedure before coring point. > A well stabilisation must be recovered almost instantaneously after the flow check (see Downhole measurements - Thermal Effect) ! Spot Hi Dens pill must be considered for the tripping. Volume = 20 / 25 m³ - SG = 2.30 ; PV =105 ; YV = 40 @ 50°C
REMINDER Note : Increase of viscosity will come only from barite addition , otherwise heavy treatment will be required to restore the mud. Results: Some Seepage losses were identified whilst this section with 2.17 SG , giving a measured ( PWD ) Equivalent Static Density of 2.18 SG . > Good behaviour of mud during investigation > Observe free gas at surface after long Flow check .. REMINDER
REFERENCE
FANN 70 AT DOWNHOLE CONDITIONS
• Behaviour of Mud under HP/HT • Hydraulic calculations
REMINDER
For further wells it is believed that the use of a slightly lower mud weight to drill through the Jurassic Kimmeridge shales should avoid lost time.( in decreasing the chance of supercharging the formation ) ➾22/30C-c10 “Wellbore pressure instability” ➾ HP/HT Transition zone analysis • Fann 70 tests must be run on the mud on a regular basis while drilling in the HPHT section. “Look ahead” rheologies and gels to be run and the reaction of the current mud to anticipated temperatures. • Established a matrix P, T, depth • No Fann 70 onboard • Fann 70 twice per week / normal operations
10
PARAMETERS
INDICATORS
P.S.D.
• To minimise LGS.
• Screen shakers optimisation , LGS content must be kept to a minimum < 150 g/litre .
FORMATION DAMAGE
• Downhole Pressure measurements (supercharging) • Cake
• See MDT measurements ( No significant Supercharging ) 27 pressures ( good test : 15, seal failure : 3, tight 4, supercharged : 5 ) • No major problems were reported
QA/QC
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
• “Formation damage” may arise in low permeability reservoirs with emulsion blocks or changes in wettability. This can be avoided by using a very High oil / water ration formulation. DIFFERENTIAL STICKING
• During Connection or Coring
• See Contingency Procedure - ( ZnBr2 formulation).
LOGISTIC
• Stocks and Volume
• Onsite keep 300m3 of mud to anticipate any risks in the transition zone. • Keep LCM safety stock as per programme.
POLLUTION ENVIRONMENT
• Oil on Cuttings Daily Reported OOC < 10%
• The issue of the efficiency of the solids control equipment and the allocation of mud losses on site needs to be clearly identified and documented:The balance of the mud lost is a combination of other factors which include: • losses associated with the operation of other down stream solids removal equipment - e.g. centrifuges , mud cleaners • pit losses • tripping losses on the drill floor • interface losses displacing mud into the hole • evaporation losses • leaks from pits and pumps • whole mud losses over the shakers • header box spills • losses while reaming • losses while circulating and conditioning • losses while drilling cement • losses around the moon-pool • losses around the drill floor Results: Target OOC ➾ 11,36% 10% Base oil discharged ➾ 57,4 Tons 35 Tons Need Improvement for further wells with the new Regulations
11
PARAMETERS
INDICATORS
• Hot Rolling • Ageing Tests • Mud Weight WELL SITE PROCEDURES REMINDER
Liner CEMENTING
Mud Conditioning
REMINDER HYDRAULICS • ESD
• ECD
• Influx of formation fluids • L.O.T. • Seepage Losses • SPP • Differential sticking
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action • Hot rolling ovens, bomb and HPHT filtration cells should be used to optimise drilling fluids formulations. • Feedback if problems develop on the rig. • See Mud calibration check list - (Rig crew & derrickman ) • For some treatments 2 - 3 circulation’s may be needed before the effects are seen
See 7” Liner Cementing recommendations
THE FOLLOWING GUIDELINES , BASED ON EXPERIMENTS , MUST RELATED TO THE MUD PROPERTIES AT THE TIME OF THE TESTS .
For 2.17 SG @ 50º with PV = 44 and YP = 12 • ESD ➾ 2.19 (Expression of the static bottom hole pressure) with PV=44 , YV = 12 • ECD ➾ 2.25 (@ 1000 l/mn) and PV=56 ; YV=20 and 2.26 (with 60 RPM) 2.27 (with 120 RPM) • Mud Compressibility Heavy mud ➾ 4.1 litre /100 bar / m3 or 2,9 litre / 1000 psi / m3 • Over Pressured to break Gels: 110 psi after 50 hours without Circulation
REMINDER
ECD values are very dependant of the mud rheology . • Pressure Transmission: @ around 80% of the pressure increment is transmitted nearly instantaneously. @ almost 100% of the pressure increment is transmitted after 30 minutes.
PRESSURE TRANSMISSION
12
PARAMETERS
INDICATORS
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action • Swab & Surge - Tripping Speed: • Main swab effects observed are:
TRIPPING SPEED
✓ ESD variations are directly related to the tripping speed ✓ ESD variations are instantaneous ✓ ESD drop-off is constant during the one-stand trip. ✓ With a “low” tripping speed of 4 minutes per stand, the observed drop-off in ESD is 2 points (0.02 SG) or almost 10 bars ✓ With a “very low” tripping speed of 7 minutes per stand, the observed drop-off in ESD is 1.5 points (0.015 SG) or almost 7 bars ✓ With a “High” tripping speed of 2 minutes per stand, the observed drop-off in ESD is 3 points (0.03 SG) or almost 15 bars • Flow Check
Flow Check & Mud Shrinkage • Several flow checks have been done during the tests with some of them on the trip tank. • Flow checks when monitoring pits volume: ✓ The driller is no longer able to see any pit variations after 30 minutes (his pit volume indicator gives a constant value after 30 minutes)
✓ But detailed analysis of recorded data shows that pit volumes reach a steady state only after almost 120 minutes (2 hours) ✓ After a flow check, the normal procedure is to re-create the previous well situation (same flowrate, same RPM) in order to confirm volume variations ✓ This operation takes around 20 minutes ✓ Volume variations include: flow line and lines volume (instantaneous) + mud pressure drop-off of the mud in the well • Flow check when monitoring the trip tank volume: ✓ Detailed analysis of recorded data shows that trip tank volume reach a steady state very quickly (after 10 minutes) ✓ These tests, performed in cased hole, are not showing any mud thermal expansion (of the mud volume in the well)
13
PARAMETERS
INDICATORS
RECOMMENDATIONS / FIELD RESULTS “RULES OF THUMB”- Remedial Action
• SPP PREDICTION ✓ ECDELF is a new hydraulic software developed by the Elf Exploration Production Fluids Group “ECDELF”
• ESD ✓ Tests, validation and “operational improvements” will be completed by the end of 1997. • Validation of the results given by the present version of ECDELF (1.01 test): ✓ ECD : OK without rotation ( within a range of flowrate ) (the present version of the software does not take into account the effect of rotation on the annulus pressure losses) REMINDER The programme need still developments : today value are corrected in a 1000 - 1200 litre/min range , at low flowrate the ECD predictions are too high and at higher flow rate the ECD prediction are too low . REMINDER
✓ ESD : seems to be slightly under-estimated (the ESD calculated by ECDELF is always 1 point lower than the measured ESD). This will be improved with more accurate PVT equations for the XP07 base oil PWD measurements are still mandatory ✓ Stand Pipe Pressure : are slightly over-estimated (around 3 to 5 %) SPP are strongly affected by the internal string pressure losses; flow regime inside the string is highly turbulent even at 1000 LPM and calculations are based on empirical correlations (it is always the case with turbulent flow); moreover equivalent shear rates seen by the mud are much more important than the 600 RPM measured by classic rheometer. And it is always difficult to know the exact drill string geometry (especially the string ID and the tool-joints ID). However 5 % is a reasonable accuracy in on-going operations. Hereafter is proposed a trick to improve SPP prediction in order to better match with real-time measurements.
REFERENCE: David BERTIN REPORT ( 28 / 08 / 1997 )
REMINDER
** Downhole Pressure & Temperature Measurements on HP/HT well. • For a more efficient use of the present version of ECDELF (version 1.01 test): Do not forget that the current test version of ECDELF do not take into account the effect of pipe rotation on the ECD; just add to the results 0.01 SG per 60 RPM to get accurate ECD predictions
14
PARAMETERS
DENSITY
INDICATORS
Variation with temperature
Overbalance on reservoir
Balance calibration
RHEOLOGY
Plastic Viscosity
Low shear rate viscosity
Plastic Viscosity Low shear rate viscosity Synthetic Water Ratio
BARITE SAG
Wetting agent
SHELL SHEARWATER RECOMMENDATIONS / FIELD RESULTS COMPARISON TO ELGIN-FRANKLIN For the Shearwater project, the density was measured at a standard temperature of 100ºF (37ºC). The standard temperature is defined as the surface temperature, at which the surface mud weight will be exactly the equivalent downhole mud weight, at the top of the reservoir under geothermal gradient. The same approach was made on Elgin-Franklin, but mud weights were reported at 50ºC. A 200-psi (0.03sg) overbalance at the top reservoir is usually used for the design of the mud. However, 120-psi (0.015sg) overbalance was used on one Shearwater well, with a mud weight of 2.26sg. The same 0.015sg overbalance was used on Elgin G8 well. The balance was calibrated with caesium formate brine at a density close to that of the active mud system. Elgin/Franklin: 1.70sg calcium bromide brine was used on first wells, then replaced by 2.10sg caesium formate brine. The plastic viscosity of the mud was optimised with the addition of emulsifiers. As the concentration of emulsifier increases the PV decreases until it reaches a plateau; optimum treatment is then achieved. Undertreatment with emulsifiers is very detrimental and can contribute towards barite sag. Emulsifiers were also used to optimise the rheology of the mud. XP-07 mud (E/F) promoted lower PV than Ultidrill mud (Shearwater) through lower cinematic viscosity of the base oil. The 100-rpm reading was controlled between a maximum of 42 to minimise the ECD and a maximum of 35 to limit the barite sag. Same 100-rpm readings noted on Elgin-Franklin. Optimised low shear rate viscosity, through yield stress. See above See above The optimum SWR to minimise barite subsidence was determined in the lab at 80/20. SWR at 75/25 or 85/15 was found detrimental to the suspension of barite. The SWR was maintained in the range from 79/21 to 83/17 in the HPHT sections. Maximum angle: 30 degree. Elgin-Franklin: SWR from 78/22 to 90/10 were maintained with no barite sag related problems, while drilling the HPHT sections. The lower cinematic viscosity of the base fluid, allowed the use of proper concentration of gelling agent to control the suspension of barite, without impairing the ECD’s. Maximum angle: 40 degree. Slight overtreatment of wetting agents was recommended to maintain the best wettability of the barite, to prevent its settlement. The same approach for the Emulsifier was used: the optimum concentration of wetting agent was reached when the plastic viscosity was not further reduced. Elgin/Franklin: wetting agents were used to oil wet the barite whilst adding weighting materials.
15
PARAMETER S
INDICATORS
HPHT fluid loss Spotting HPHT Low fluid loss pill TEMP. STABILITY
HYDRAULICS
ESD, ECD, Surge and Swab Breaking circulation while running in the hole Mud from 12 ¼” to 8 ½” section
OPERATIONA L PRACTICES Continuity of personnel
SHELL SHEARWATER RECOMMENDATIONS / FIELD RESULTS COMPARISON TO ELGIN-FRANKLIN Maintained below 5 cc at BHST (182 to 193ºC). Maintained below 5 cc at 180ºC. A high viscosity, low fluid loss pill was spotted in the open hole before tripping to minimise the risk of sag and differential sticking, and maximise the mud tolerance to contamination by reservoir fluid. This approach was imposed by SHELL, after ELF presented its successful drilling of the first Elgin well. The HPHT fluid loss pills are still in used in our fields, to prevent long term degradation of mud under temperature and also, to prevent large deposit of cake, prior to core the reservoirs. DOWELL software validated with Sperry-Sun PWD. ECDELF software validated with Sperry-Sun PWD. To minimise the impact of barite sag, circulation while running in the hole was only made at the 9 7/8” shoe. Elgin-Franklin: same approach. Two separate mud systems, one for the 12 ¼” section and one for the 8 ½” section were used. The HPHT mud were backloaded and reconditioned in town before reuse. Elgin-Franklin: generally the mud from the 12 ¼” section were diluted and adjusted offshore for the drilling of the 8 ½” section without any impairment to the fluid nor the rig time. Shell: Dowell mud engineers assigned to the project. Elf: Baroid mud engineers assigned to the project were Graham Bell, Phil Leslie, Dan Blaylock, Roberto Cremascoli, Neil Ross and Ian Cameron. Same approach on both development to promote a continuous improvement of the performances.
16
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
5.6
7” ( or 7”x 4 1/2”) liner and cementing A 7” liner (or a tapered 7”x 4 1/2” if Pentland drilled) liner will be run and cemented to the liner hanger. The goal of a tapered liner is to give us the maximum chance to obtain a good isolation between the two reservoirs to prevent any future water production from the Pentland by channelling behind the liner. Running the liner. Prior to run the liner, the gel strength and yield point must both be reduced, the yield point + 15 lb/100ft², and the 10’ gel to < 23 to avoid excessive surge pressures when running in. Pilot tests will be completed by the mud engineer to determine the optimum treatment levels. This can best be accomplished by additions of OMC 2.Care should be taken so as not to over treat the system with OMC 2 that can cause barite sagging or settling. When running liner, consideration should be given to breaking circulation half way in the hole, to reduce back pressure when breaking circulation on bottom prior to cementing. Swab and surge calculations should be run on the actual data of the time to optimise the rheological properties and liner running speeds, to ensure they are well within the limits of fracture pressure.
Cementing job The liner will be cemented with a gas tight slurry 2.30 SG. he slurry volume will be calculated according with the caliper volume + 20% and an excess corresponding at 100 metres of annulus volume (9 7/8” Csg x 5” DP). Fluid design: ! Spacer : formulate spacer @ 2.25 SG.
Contractor Spacer Viscosifier Surfactant Surfactant Bentonite Stabiliser Fresh water Barite Defoamer
Dowell Mudpush WHT D143 10 kgs/m³ U66 - 47.6 l/m³ B064 – 47 l/m³ D20 – 5 kgs B78 – 8 litres 510 litres 1626 kgs as required
9
Halliburton Spacer 500E+ 16 kgs/m³ SEM7-50l/m3 Pen5–20 l/m³ N/A N/A 538 litres 1622 kgs as required
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
Important : Spacer design becomes more challenging with Oil-base mud . The spacer must be cpmpatible with both the mud and cement while remaining stable at High Temperature . Oil water Emulsions , such as the Dowell MUD Push XEO is not recommended .
A water phase spacer with surfactant is recommended . Specific Lab. Tests : - Static Settling Test at BHCT . - Dynamic Settling test at BHCT - Compatibility with SBM and Slurry under temperature . ! Tail slurry: gas tight 2.30 SG. – ! VOLUME = Caliper + 20% open hole + 100 metres aboveTOL ( 9 7/8” casing )
G cement Silica Fluid loss Stabiliser Retarder
Dowell Dyckerhoff 35 % Bwoc D134 – 310 l/ton D135 – 31 l/T D161 – 173 l/T
Drill Water
37 l/T
Dispersant Weighting agent Stabiliser Retarder
B78 – 7.7l/T Hematite 71% bwoc D153 – 0.2% bwoc N/A
Halliburton Lafarge 35% Bwoc Halad600LE-90 Silicalite 97L-100 l/T HR25L – 122.5l/ton Zero l/T
CFR3 – 0.5% Micromax50% bwoc Microbond Ht – 4% SCR100L – 205 l/ton
Remarks: 1. All the formulations are indicative, they must be confirmed by laboratory tests performed with samples coming from the rig before the cement jobs.
10
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
t
Cement slurry properties: Density 2.30 SG. Yield +/- 1100 l/t Thickening time > 8h00 + 3 Hours Batch mixing Fluid loss < 30ml Free water < 0.0 % Compressive strength at BHCT >300bar 48 h
Additional Tests :
-
Rheology at the BHCT using HPHT rheometer – Settlement Test Static Gel strength Crush compressive strength Sensitivity Tests :Temperature +/- 5°C and Retarder concentration +/- 5 % .
11
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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EXPERIENCE :
Experience shows that advance planning and preparation are vital to the successful completion of cementing operations . Prejob planning and careful consultation also save valuable time . Three weeks or more are needed to ensure sufficient preparation for the cementing operation , including a thorough examination of well conditions , spacer design , slurry qualification , operational mixing procedure . The following pages examines current and evolving HPHT cementing practices which was implemented during the drilling phase .
Example : 7 “Liner BAKER ( 42.5 # - 28% Cr.) Cement Job on 29/5b-F5 Objective: The goal of the cement job is : - to seal the production liner covering the gas and condensate bearing sands of the FRANKLIN reservoir - isolate the GWC and the reservoir . 7” Liner String: Top Liner: 9 7/8” Casing Shoe Landing Collar: Float collar: Shoe Depth: Well TD: Top Franklin “ A “ Sands Pentland
5111 m MD ( 150 m overlap) 5268 m MD 5782 m MD 5879 m MD 5910 m MD 5915 m MD 5691 m MD 5759 m MD
Radioactive markers and Joint markers: To be positioned above C sands (One joint + 1 pip tag one joint above - 1 pip tag in the Liner hanger) [ 8.55 m below top packer liner]
Centralisation for this Liner should be as per following: -2 Spiraglider Spiral Centralisers per joint over the 3 first joint (OD 8 1/4”) -1 Spiraglider Spiral Centraliser per joint over the float collar (OD 8 1/4”). -1 Rotating STT I SL Centraliser per Two joint over the Reservoir.
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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-1 Rotating STT I SL Centraliser per Three joint from top Reservoir to 9 7/8” - 1 Rotating STT I SL Centraliser per 2 joint from 9 7/8” to the top of the Liner. Type of centraliser; STT/I/SL model (OD 8.62”) - Installed over a stop collar (Mid joint)
Pre-job preparation: 1) Ensure all pits (to be used for the preparation of spacer and slurry mix water), cement supply to the Halliburton cement unit and cementing line to the rig floor are thoroughly cleaned out and flushed through with fresh water. Check cement bulk. 2) The 7” Liner will be drifted. It was dimensionally controlled to better assess the ID of the joints which will be used for the displacement calculation. Diameter: 5.788 “ or 16.98 L/metre
3) Check wiper plug and dart for 5” DP - (Drifted + Rabbit the new 5” DP if any) (Shear pins Wiper plug and Dart plug: Shearing value 1200 & 2200 psi -7 pins) Good indication on F1: 122 bars with ENACO hanger. Good indication on F2: 126 bars with ENACO hanger Good indication on F3: 86 bars with BAKER hanger, unable to set hanger, liner set on bottom of the hole.
Good indication on F4: 155 bars with BAKER hanger.Tapered casing 7x5x4½” Good indication on F5: 95 bars with BAKER hanger Mud film thickness inside DP and Liner: Vdp = 958 litres Vliner = 233 litres Total = 1191 litres => 70 metres, 7 joints Preparation of Spacer Spacer 1: Spacer 500E+ (High Temperature Spacer) The spacer to be used consists of 18 m³ of Spacer 500E+ (see Halliburton formulation) weighted to 2.25 SG with a yield point of ± 40/50 (at 21 °C) Mix 50 m³ of spacer to be able to fill the liner behind the cement - Lost suction on F2 Once the freshwater has been added to the pit, the chloride content of this water should be checked, the result noted and a sample of this water retained. Take a sample of spacer when complete, measure rheology at mix + at Halliburton lab temperature, note result and retain (compare with the formulation).
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Preparation of ADDITIVES: Addition of Fresh water, Halad 600LE, Silicalite-97L, Micromax will be mixed while RIH. This mix water can be kept 24 hours without harm to the cement job. F1 - 9 hours to mix the slurry, SEE HALLIBURTON report for details. F2 - 7 hours to mix the slurry - Addition of micromax 10/15 min/ ton but still very messy -Blockage of discharge line of 4” slurry followed by blockage of the 4” slurry suction line on the batch tank - Densitometer line blocked - Total downtime: 2 hours – F3 – Mixing + recirculating slurry: 15 ½ hours. Slow addition of Micromax, it took time to remove the bags from the containers. F4 – 8 hours to mix the slurry – The mix water was started one hour before the liner tagged the bottom of the hole – The micromax took 4 hours to be mixed – the cement addition took 3 hours. The slurry was kept 2 ½ hours circulating while pumping the spacers. F5 – The micromax took 45 min hours to be mixed – The slurry took 90 min .
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Running procedure and Fluid pumping Sequence Recommendations: - A circulation will be performed at the 9 7/8” casing shoe to establish parameters. Circulate 1 bottom up at 750 L/min or less if losses are reported (gas level control, losses). F1 @ 650 l/min F2 @ 680 l/min F3 @ 750 l/min F4 @ 650 l/min F5 @ 750 l/min
SPP = 65 bars at 5118 m SPP = 73 bars at 5002 m SPP = 84 bars at 5126 m SPP = 81bars at 5424 m SPP = 80bars at 5240 m
- RIH and tag bottom - Pick up to liner setting depth according to liner operator. On F5 : Washed down from 5367 m to 5913 m with 400 to 700 l/min & 55 to 90 bars while working string through several tight spots -
-
- Break circulation slowly and check surface pumping pressure at previously established rates. Whilst running in the hole with 7” liner, select 1 high pressure mud pump and check seals, liners and swabs in case it is required during the cement job. At TD, take weight up / down. Tag TD + pull back +/- 2 metres – - # Up / Down F5 : 248 / 212 tons Fluid pumping sequence: 1)- Circulation prior to the job should be, at a minimum, 1.5 times complete annular volume. The flow rate will be gradually increased while monitoring for losses to reach an ECD 2.24 sg. at 700 lpm. F5 at TD : Circ with 700 l/min – SPP = 84 bars . Start the pumping slowly until the mud circulated from the bottom of the well has passed the liner hanger to try to ensure no plugging of the (liner hanger x 7" casing) annulus with cuttings. If losses (> 3 m³ / hour), spot 10 m³ of LCM (BARACARB 50/150/600) 250 kg/m³. 2)- Set liner hanger (see BAKER procedure). INCIDENT : During the circulation after setting the liner hanger , a leak was observed between the plug dropping head and the TIW valve directly below .The string below the connection fell , breaking off the side entry sub thread complete with blanking cap as it travelled through the rotary table .[ see trip report ,and Baker report ] – Lost time : 5 h 00 . 15
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Mix and pump: Example on F5 well 1 - 50 m³ of low rheology ( PV= 66 , YV = 9 Gel 10 = 10 /15 ) mud at 2.15 SG. 2 - 18 .8 m³ of Spacer 500E+ at 2.25 SG ahead of cement slurry. 3 - Slurry, formulation as per attached Halliburton Fax. The Volume required is as follows: volume to fill open hole annular volume + 30% excess on open hole + shoe track + 100 metres of 9 7/8” casing. Estimated volume: Annulus volume: 8.1 m3 Excess 30% or calliper volume: 2.4 m3 Overlap150 m: 1.9 m³ Shoe / FC: 2.4 m³ Excess above top liner 100 m: 3.8 m³ Total: 18.8 m³ at 2.3 SG (119 bbls)- SEE CALLIPER On F1: total slurry pumped -> 19.5 m³, top of cement at 4778 m, cement found 85 metres higher than planned. On F2: total slurry pumped -> 20 m³, top of cement at 4740 m, cement found 4 metres higherthanplanned. On F3: total slurry pumped -> 19.5 m³, top of cement at 4906 m, hard cement 85 m above top of liner F4: total Slurry pumped -> 27 m³, top of cement at 5095 m , hard cement 74 m above top of liner. On F5: total Slurry pumped -> 18.8 m³, top of cement at 5013 m , hard cement 98 m above top of liner.
- No Freash water ( liquid phase coming from the additives ) - Add Halad 600 LE - Add Silicalite 97 L - Add FDP-C533 and allow to hydrate for 30 min - Add SCR-100 L (liquid additive) - Add total Micromax (big bags & sacks) to the mixing water - Add ¼ of total Lafarge G + 35 % SSA - Add HR-25 L - Add remainder Lafarge G + 35% silica - Slurry weight should be 2.29 SG - Add Microbond HT When completed, take a sample of the slurry, measure the rheology & density and retain. Allow slurry to homogenise (+/- 30 min, with paddles and centrifuge pump) prior to pumping downhole .
4 - Release the pump down wiper dart. 16
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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5 - Displace with (Halliburton unit) 12 m³ of Spacer-500E+ at 2.25 SG behind cement slurry (to place the spacer inside the drill pipe above the running tool). 6 - Displace with (Halliburton Unit) with 2.15 SG mud at 700 litres/min until dart is circa 1 m³ from latching into liner wiper plug and slow rate to 200 litres/min to pick up and shear out wiper plug. Increase rate to 300 litres/min to displace cement slurry in the liner, slowing to bump plug. F2: Reduce to 300 l/min on the last 5 m³ to limit ECD @ 2.25 SG (see cimentelf)
Displacement to be calculated with 9 .06 l/m for S135DP & 8.00 l/m for G120 DP ECD estimation before bump the plug: Surface pressure before Bump: CIMENTELF
.26 EMW at TD (300 lit/min) +/- 68 bars (300 lit/min)
On F1: Surface pressure before Bump on the RIG: On F2: Surface pressure before Bump on the RIG : On F3: Surface pressure before Bump on the RIG : On F4: Surface pressure before Bump on the RIG : On F5: Surface pressure before Bump on the RIG :
50 bars (low flow rate ) 55 bars ( low flow rate ) 68 bars ( 430li/min ) 66 bars ( 340lit/min ) 67 bars ( 300lit/min )
Bump plug to 150 bars and then pressure test Liner to 220 bars 7 - After bumping plug, hold pressure (10 min Max) and check float equipment is holding. POOH 4/5 stands and circulation the long way until clean returns monitoring for losses & gas . F1: GAS MAXI after First bottom up 12.2 % - 20 min . F2: GAS MAXI after First bottom up 1 % - 28 m³ spacer contaminated. F3: No gas, reduced flow from 1500 to 1200 lit/min after 1 m³ loss. Recovered spacer returns F4: Recovered 16.8 m³ of spacer contaminated with 11.5 m³ mud. F5: Recovered 22 m³ of spacer contaminated .
Reciprocate and rotate (to avoid gelling effect) whilst circulating conventionally to evacuate spacer and excess cement at 1200 /1500 l/min (depending on pressure). Dump contaminated returns (in a dedicate pit, keep a sample of slurry if any) and increase flow rate to 1500 l/min, maintain this flow rate for one bottom up. Treat mud for suspension. 8 - Gas Migration potential during setting time:
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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W.O.C for +/- 11 hours from start of pumping the slurry before POOH setting tool. Flow rate = 1400 l/min.Pressure = 170 bars. 9 - Timing:
Estimated
Actual
Mixing + Slurries Injection Displacement N° 1 Circulation long way Safety factor Total
: 300 min : 100 min : 60 min : 120 min : 8 hours 40 min
240 min 150 min 90 min 8 hours
Notes: All samples of fluids should be 1 litre in size. Chloride content of Fresh water should be less than 1000 mg/litre. Record temperature of each fluid pumped in the well.
10 - Temperature Estimation: Drilling 8 1/2” ( 1100 l/min) BHST
198°C
New API BHCT
177°C
Hall.Enert. BHCT
Enertech BHCT
182 °C
182°C
PWD BHCT bottom
172°C forecast
Static temperature at top of cement: 175ºC Bottom hole logging temperature on F5 : 193º3 C at T.after 58 h 50 min ; Thickening Time: Tail Slurry: BHCT = 182 °C $ 7 h 37 min + 3 hours surface mixing time Tail Slurry:
BHCT = 187 °C $ 5 h 58 min
Tail Slurry:
BHCT = 177 °C $9 h 25 min
Compressive Strength
at 175 °C$ 4277 Psi after 16 hours
11 - Compatibility test between mud / spacer: 12 - Retarder sensitivity tests (see attachment) : Sensitivity to retarder concentrations: + / - 5 %: Thickening time .
18
Rig Flow line
53°C
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Note: the setting time will be checked offshore with a rig consistometer to forecast the time. F1: Thickening time 9 hours 45 min on site at 16000 PSI and 182°C F2: Thickening time 7 hours 40 min on site instead of 7 hours 26 min at 16000 PSIand182°C F3: Excellent correlation on site versus laboratory. F4: Thickening time 8 hours 23 min on site instead of 8 hours 21 min at 15000 PSI and 182°C F5: Thickening time 6 hours 10 min on site instead of 7 hours 37 min at 15000 PSI and 182°C ** Slurry was kept 2 hours 30 min in the batch tank
19
EXPERIENCE Difference in Cement Thickening Time between lab test and Offshore tests . Advantages • If the Thickening time of the slurry is suitable the cement job can be performed in its entirety without any risk of premature setting . To be more confident and especially with the complexity of the slurry recipe to check on site the T.Time by using a rig site consisto- meter . Few differences in the Thickening time were found between the lab tests onshore and the test done offshore using the same chemicals and additives . Experience To date we have ran 11 Liners under Extreme conditions : Slurry density = 2.30 SG .
Well Name
T.Time Lab.
T.Time on site
Depth
Liner Length
Contractor
HALLIBURTON BHST = 198°C 29/5B - F1 29/5B – F2 29/5B – F3 29/5B – F4 29/5B – F5 ** 29/4D - 4 DOWELL 22/30 C – G4 22/30 C – G5 22/30 C – G6 22/30 C – G7 22/30 C – G8
BHCT = 182°C 07 h 18 min 07 h 40 min 07 h 48 min 08 h 21 min 07 h 37 min 07 h 16 min BHST = 192°C BHCT = 170°C 20 h 00 min 09 h 02 min 10 h 47 min 11 h 26 min 08 h 10 min
09 h 45 min 07 h 26 min 07 h 26 min 08 h 23 min 06 h 10 min 07 h 34 min
5927 m 5787 m 5807 m 6453 m 5915 m 6050 m
960 m 935 m 815 m 1182 m 806 m 1025 m
20 h 30 min 08 h 13 min 10 h 45 min 08 h 25 min 08 h 50 min
5884 m 5672 m 5928 m 5724 m 6147 m
854 m 768 m 704 m 746 m 800 m
Note: ** on F5 the slurry was kept 2 hours 30 min in the batch tank due to a pressure leak at the cementing head .
HP / HT Section CEMENTING RECOMMENDATIONS
7 ” Liner. Shoe depth @ +/- 6100 m MD - Top @ +/-5000 m MD.
PARAMETERS
PRODUCTION COLUMN DESIGN
INDICATORS
♦
Reservoir isolation
♦
Water production prevention
•
Liner lap cemented
•
Shoe track cemented
•
Good CBL
RESULTS / Remedial Actions ! Elgin: all drawdown test (-570 bars) with stable flow checks. ! Franklin: hard cement at top of liner. ! CBL showing good bonding in front of formations.
♦
Determination
To help mud displacement with cement, slurry must have a weight at least 5 points higher than the mud, and this weight must be compatible with the formation pressure to avoid any losses. In this section the mud weight is 2.15SG, so we generally use slurries at 2.30SG.
!
Good mud displacement, and rare formation losses.
♦
Adjustment
Use Big-Bags and sacks of weighting agent (Hematite, Micromax…) to adjust the Final density.
!
NO MAJOR PROBLEMS FOR MIXING.
♦
T.T.Depends on the Bottom Hole Circulation Temperature and the pressure.
♦
! On site thickening times were in good agreement with the testing performed in the lab.
BHCT estimated with several methods: - API table. - Enertech software. - Cemcade software.
These different methods give different results for the same BHST (ex: API: 168°C, Enertech: 182°C, Cemcade: 170°C for BHST=198°C). • Check the Slurry Thickening Time at the highest temperature found. • Control it at the other temperatures (including the circulating temperature estimated at the top of liner). • Thickening time control on site with a Consistometer. • Circulation with drill pipe above the cement to maintain ECD (circulation time: based on compressive strength at the top of liner) and avoid any gas influx. • Have a right angle cement setting profile to avoid any influx during the cement transition period.
SLURRY WEIGHT
SLURRY THICKENING TIME
♦
♦
COMPRESSIVE STRENGTH
RECOMMENDATIONS
Sensitivity Tests: - Temperature - Concentration Safety:
Checked after 24 hours at the temperatures given by Enertech software at the top and the bottom of liner.
•
•
Run tests with + / - 5% of retarder concentration and +/- 5°C of temperature discrepancies.
!
Slurry displacements performed without problems.
!
Generally good CBL.
!
Good response
Adjust the TT to have the safety margin (+ 2 hours) for the cement Job . The quantity of retarder is significant so a special attention is necessary when preparing the mixing water.
Wait until the cement is set at the top of liner.
1
Compressive Strength: 4500 psi after 13 hours at bottom conditions and 2900 psi after 20 hours at top of liner conditions.
PARAMETERS
INDICATORS
RECOMMENDATIONS
FILTRATION
♦
Fluid loss control
•
“Gas block” slurry design to have a tight Fluid loss and avoid dehydration in front of reservoirs.
FREE WATER
♦
Free water control
•
Need zero free water to avoid gas migration or settling
•
In order to have steady and reliable characteristics, all the slurry will be prepared in surface (batch-tank) before being pumped. Quantity of water and additives must be carefully checked. Use pressurised balance to check slurry weight.
RELIABILITY
Slurry homogeneity
• •
SPACER (Critical issue)
♦
Compatibility with SBM and Cement.
Rheology .Sensitivity test with blends at: 5 / 10 / 20 / 50 / 75 / 100 %
♦
Rheology under HP/HT conditions ( run Fann 70 )
Check Rheology under High Temperature to avoid any settling . ( @ BHCT )
•
Laminar Flow Design
Slim margin between Pore Pressure and Fract. Gradient - Laminar flow is recommended.
•
Emulsion design
Don’t Use “Base oil” for Spacer with compliant Surfactant –
•
Volume ahead / behind
Pump spacer behind Slurry, which will be placed inside the drill pipe above running tool after displacement.
REMINDER
SLURRY VOLUME
DISPLACEMENT
RESULTS / Remedial Actions
Slurry on the site in good agreement with lab-test.
! ! !
No channelling was reported. Good interface during reverse circulation No segregation of solids versus liquid phase (oil & water).
!
No problems during disconnection of setting tool
!
Dowell: No tag of hard cement at the TOL. Halliburton: Tag hard cement for each cementing job.
USE A WATER BASED SYSTEM TREATED WITH SURFACTANT.
•
Excess + 30% calliper + 100 metres in 9 7/8”
Increase the volume to get 100 metres above TOL + an excess of 30 % on Calliper
!
•
Volume
Used cementing unit for slurry displacement
!
Better accuracy of displacement volume
•
Flow rate
Used CIMENTELF software to calculate: - ECD and maximum flow rate acceptable during the displacement. - TP and CDP factors (Cleaning and Laminar Displacement Efficiency factors)
!
Losses during cement jobs were rare. Difficult to achieve a CDP > 5 (CDP>10 for a good displacement).
2
!
PARAMETERS
BATCH MIXING / ADDITIVES PREPARATION
DISPLACEMENT VOLUME CALCULATION
INDICATORS
RECOMMENDATIONS
♦
Mixing Water
Special care for Additives mixing – Follow Dowell and Halliburton Mixing procedure (and check chloride in water before any mixing).
♦
Retarder HT
Addition of HT RETARDER done ONCE Liner Hanger is Set
♦
Weighting Agent (Hematite or Micromax) in big-bags.
Need RIG Modification to install a pipe from Upper Deck to the Batch Tank ( Minimum size = 10 /12” Diameter )
♦
Volume
•
Batch Tank Capacity = Minimum 150 BBLS.
♦
Mixing energy
•
Mix water should not be kept longer than +/- 8 hours. Mix water can be kept for 24 hours but thickening time will be reduced by 1 hour .
•
Temperature of the slurry > 30°C
•
Risk of evaporation of water during the recirculating of the slurry with an impact on the thickening time.
!
Request 4 / 5 Hour to mix all Big Bags
!
Reached 2.30 SG without any readjustment.
♦
Efficiency / Yield after ageing
•
Thickening Time checked with Mix Water aged 20 hours at room temperature
♦
7” casing size typical ID 8.617” – 16.92 lit/m.
•
Check Internal diameter with Micrometer recordings This check is crucial to achieve a good displacement of the slurry. Use 9.06 l/metre for S135 DP & 8.00 l/metre for G120DP Mud compressibility not to be added to the theoretical volume. Pumping DP volume + liner volume + mud compressibility + ½ shoe track => Wet shoe
!
Bump the plug : OK
!
Plug shearing OK, typically 100 to 150 bars.
!
Test liner to 150 bars
Problem with CBL tool, risk of damage centraliser in hole. Recommendation must be issued before each log
!
CBL: Generally good results in open hole, bad results in over-lap, even when we drilled hard to very hard cement at the top of the liner.
!
Shoe track: F3z Triassic well deepening, the 150 m shoe track was drill out. The first 40 m was cemented properly, ROP = 10 m/hr with WOB at 5 tons. The 110 m below was a poor cement, 20 to 40 m/hr with 2 to 5 ton WOB.
• ♦
ID of DP volumes
♦
Compressibility
•
• • •
CEMENT EVALUATION
RESULTS / Remedial Actions
•
CBL/VDL Log
Tool calibration needed before each logs. Free pipe for the 7” under well conditions with Mud (SBM at 2.15 SG): DOWELL - 7” 42.7 # CBL ( free pipe with mud ) = +/- 61 mV .TT = 290 µ sec. - Fluid Compensator Factor : 0.466 - Cement bond amplitude-Acoustic impedance with a 2.30sg slurry weighted with Hematite slurry is: 6.5 Mrayl HALLIBURTON - 7” 42.7 # CBL ( free pipe with mud ) = +/- 61 mV .TT = 280 µ sec. - Cement bond amplitude - Acoustic impedance with a 2.30sg slurry weighted with manganese oxide slurry is 6.6 x 106 kg/m² sec .
3
PARAMETERS
INDICATORS •
Liner String Preparation
RECOMMENDATIONS - ACTIONS TAKEN • • •
• • •
Fluid Design
•
• • • • •
CEMENTING
•
MIXING SEQUENCE
• • • •
PRACTICES
• • •
PUMPING SEQUENCE
• • • • •
• • • •
Length of Overlap: 150 metres Length of LC/Shoe: 150 to 200 metres (mud film , dart failure , contamination) Centralization: 2 per /J on 6 first J. then 1 per / 2J Spiralglider ( OD 8 1/4” ) STT/1/SL ( OD 8.62” ) Mechanical Liner Hanger T I W or Baker Rabbit DP 5” + ID measurement on 7” Liner Spacer design : 2.25 SG Laminar flow design , Compatibility tests rheology at BHCT Stability of spacer after adding surfactant . Thin Mud : 2.15 SG with PV= 45 / YV = 10 - +/36 m³ pumped ahead spacer . Excess of slurry = 30 % on Calliper + 100 metres inside 9 7/8”without DP in hole Consistometer on the location Chemicals checks according to the Lab. Test (Reference number) Flow meter with gauge to mix additives. Batch Tank mixing. Additives mixed during circulation at bottom without retarder. Addition of retarder once Liner Hanger set. Mixing cement slurry to 1.90 SG with slurry chief ( temp.= 19°C ). Addition of Hematite with Big Bags (5 min per Bags), to 2.30 SG (temp. = 20 °C) – No recirculating pump (only paddles used). Check rheology / SG / Volume (run consistometre test). Pump 36 m³ of thin mud (2.15 SG). Pump 15 m³ of Spacer (2.25 SG). Pump 18 m³ of Slurry (2.30 SG). Pump 13 m³ of Spacer (2.25 SG) - Fill up liner + 150 m DP. Pump SBM mud for Displacement (2.15 SG). Check dart shearing / Bump plug at the theoretical volume. Pressure Test to 150 bars (10 min). POOH Slowly 4 Stands above TOL. Direct Circulation at low flow-rate (Dumped spacer / traces cement / spacer). Circulation long way twice based on the compressive strength at the top of liner.
4
29/5b FRANKLIN - 8 ½" OPEN HOLE / 7" LINER CEMENTATION 5 5/8" OH / 4 ½ " liner
7 x 5 x 4 ½ " liner
Well
29/5b-F1
29/5b-F2
29/5b-F3
29/5b-F3z
29/5b-F4
29/5b-F5
date
23/06/1998
15/09/1998
17/12/1998
01/05/2000
17/04/1999
24/09/1999
Top of cement
m
4868
4742
4891
5553
5169
5009
Casing shoe
m
5926
5785
5806
6253
6452
5910
Height
m
1058
1043
915
700
1283
901
BHST
ºC
197
197
198
204
198
198
BHCT
ºC
182
182
182
195
182
182
Theoritical slurry volume
m³
18.5
18.4
16.6
6.3
22.3
16.3
Excess
%
25
18 (caliper)
30 (caliper)
50
30
30
Total slurry volume
m³
19.4
20
19.5
7.7
27
18.8
Weight of cement (G+S)
ton
28
26
26
13
36
24.3
Slurry weight
sg
2.30
2.30
2.30
2.30
2.30
2.30
Cement Lafarge G
%
100
100
100
100
100
100
Silica flour
%
35
35
35
40
35
35
type
Fresh
Fresh
Fresh
Fresh
Fresh
Fresh
50% Micromax
50% Micromax
50% Micromax
50% Micromax
50% Micromax
Type of slurry
Water Additives
60% Micromax
90 lit Halad-600 LE 90 lit Halad-600 LE 90 lit Halad-600 LE
130 lit Halad-600 LE
90 lit Halad-600 LE 90 lit Halad-600 LE
l/ton 100 lit Silicalite-97 L 100 lit Silicalite-97 L 100 lit Silicalite-97 L
100 lit Silicalite-97 L
100 lit Silicalite-97 L 100 lit Silicalite-97 L
or
0.1% FDP-C533
0.2% FDP-C533
0.2% FDP-C533
0.2% FDP-C533
0.2% FDP-C533
0.2% FDP-C533
%
4.2% SCR 100
210 lit SCR 100L
210 lit SCR 100L
75 lit SCR 500L
205 lit SCR 100L
205 lit SCR 100L
2.1% HR 25
105 lit HR 25L
105 lit HR 25L
90 lit HR 25L
122.5 lit HR 25L
122.5 lit HR 25L
4% Microbond
4% Microbond
4% Microbond
1.4% Component R
4% Microbond
4% Microbond
20 lit/ton CFR-3L Thickening time (70BC)
hr:min
07:18
07:26
07:25
08:14
08:20
07:37
Compressive strenght 12 hr
PSI
4074
3024
3100
750
3200
4900
Compressive strenght 24 hr
PSI
4392
4600
4640
2700
3000
4600
laminar
laminar
laminar
laminar
laminar
laminar
type
Spacer 500E+
Spacer 500E+
Spacer 500E+
Spacer 500E+
Spacer 500E+
Spacer 500E+
sg
2.25
2.25
2.25
2.15
2.25
2.25
TIW
ENACO-TIW
BAKER
BAKER
BAKER
BAKER
type
dart and plug
dart and plug
dart and plug
wiper plug not sheared
dart and plug
dart and plug
Flow pattern Spacer Plug type Displacement
HALLIBURTON TEMPERATURE SIMULATION
Enertech Software .
Enectech Simulation for 7” Liner To determine BHCT for 7” Liner cementation the following parameters were assumed: 1) As mud pits are enclosed air temp – 20°C and wind speed – 0 2) Slurry inlet temperature – 19°C 3) Spacer inlet temperature – 20°C
BHCT °C 197 197 197 197 197
Mud inlet Temp.°C 50 50 50 60 40
Displacement rate m³/min 0.6 0.3 0.3 0.3 0.3
Slurry rate m³/min 0.6 0.3 0.6 0.6 0.6
BHCT Enertec 178 179 179 180 178
Conclusion: If BHST is 197°C then max expected BHCT is 180°C. API 1992: 176°C
API 1990: 176°C
Tests will be performed at 182°C with additional Thickening Time tests at 172°C and 192°C
TEMPERATURE PROFILE FOR 7" LINER TEMPERATURE degC 0
50
100
150
200
250
0 1000
DEPTH m
2000 3000 4000 5000 6000 7000
Undisturbed Annulus Drill String
8 1/2" Temperature Prediction - 29/5B-F1 197°C Extrapolated
200 190 180
190°C
after 56 hours
186.7°C
187.8°C
Horner plot
195°C
after 55 hours
after 72 hours
170 160 150 140 Geol.BHST
120 110
Logging
Logging
Temperature in °C
130
Enert. BHST BHCT predict. PWD
100
Temp in °C
90
Temp out°C
80
Series7 Series8
70
Series9
60
Series10 50 40 30 20 10 0 4740 5153 5142 5153 5161 5167 5209 5247 5293 5419 5452 5544 5637 5663 5671 5671 5671 5723 5756 5765 5800 5840 5860 5900 5927 5927 5927
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Depth MD
Enectech Simulation for 7” Liner – Well 29/4d-4 To determine BHCT for 7” Liner cementation the following parameters were assumed: 1) As mud pits are enclosed air temp – 20°C and wind speed – 0 2) Slurry inlet temperature – 19°C 3) Spacer inlet temperature – 20°C
BHCT °C
Displacement rate m³/min 0.6 0.3 0.3 0.3 0.3
Slurry rate m³/min 0.6 0.3 0.6 0.6 0.6
BHCT Enertec
198 198 198 198 198
Mud inlet Temp.°C 50 50 50 60 40
185 185 185
40 50 60
0.6 0.3 0.3
0.6 0.6 0.3
157 165 170
Conclusion: If BHST is 198°C then max expected BHCT is 180°C. API 1992: 167°C If BHST is 185°C then max expected BHCT is 170°C. API 1992: 156°C Tests will be performed at 182°C and 170°C.
178 179 179 180 178
8 1/2" Temperature Prediction - 29 / 4 D -4 210
Logging after 59 hours T =195°C
200 190 180 170 160 150
Logging
140
Temperature in °C
130 120 110
Coring
Coring
70
BHCT predict.
Temp in °C
Coring
80
Enert. BHST
PWD
100 90
Geol.BHST
Temp out°C Series7 Series8
60
Series9
50
Series10
40 30 20 10 0 5191 5256 5315 5375 5424 5471 5508 5551 5598 5606 5624 5658 5685 5788 5824 5863 5982 5987 5992 5997 6002 6007 6012 6017 6022 6041
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Depth MD
DOWELL SCHLUMBERGER TEMPERATURE SIMULATION
Cemcade Software .
-------Results of Simulation------------------Temperature simulation API BHCT = 174 deg.C Simulated BHCT = 169 deg.C -Fluid N°:6 – Group:MU-Name:Thin Mud----Simulated MaxHCT = 171 deg.C Mud Type: Oil (Fresh/Sea/Oil) CT at TOC = 163 deg.C Solids : 39% Static Temp. 08:00 24:00 Geo. Temp Volume Fraction: Oil : 50% deg.C deg.C deg.C ----------------------------------------------------------Borttom Hole 184 192 195 op of cmt 163 167 169 Press to proceed -----------------------------------------------------Cumul Time---------Period------------Flow Rate-----------Inlet Temp----Volume Unit--hh:mn:ss hh:mn:ss l/min deg.C Hole volume Mud Circulation --------------------------------------------------------------------------------------03:00:00 03:00:00 400 47 0.388 ………… ………… ……. ……… ………… ………… ………… ……. ……… ………… Slurry/Spacer Circulation --------------------------------------------------------------------------------------04:06:40 01:06:40 600 26.667 Thin Mud 04:31:40 00:25:00 600 26.667 MUDPUSH XEO 04:58:20 00:26:40 600 26.667 Tail slurry -----------------------------------------------------------------------------------------------------------------------Static period after placement: 24:00:00 hh:mn:ss
TEMPERATG4 Chart 4
8 1/2" Temperature Prediction - 22/30 C-G4 210 200 190 180 170 160 150
Temperature in °C
140 130
Geol.BHST
120
Enert. BHST
110
BHCT prediction PWD
100
Temp in °C
90
Temp out°C
80 70 60 50 40 30 20 10 0 4740
5029
5118
5214
5332
5371
5412
5600
Depth TVD
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5657
5717
5740
5740
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6.
5 5/8” SECTION (G4 + F3.z triassic ) Interval:
6050 m (MD) 7” shoe to 6400 m(MD)
Max expected BHP: Expected temperature:
Pentland 2.10 SG EMW. 195°C BHST at 5800m TVD BRT. 205°C BHST at 6130m TVD BRT.
6.1
Purpose: Drill (and core) 5 5/8” hole through remainder of the Middle Jurassic (Pentland formation). The shoe will be set 50 TVD above the prognosed Bottom Pentland formation. Requirement is to cover reservoir(s) and ensure a good isolation between Franklin Sands and Pentland.
6.2
Drilling procedure: Run in hole with 5 5/8 bit and tag the cement. Decrease the mud weight to 2.12 - Drill out the cement and 5 m in the formation. LOT: LOT expected 2.30 SG (limited to 2.40 SG EMW). Perform a cement squeeze at the 7” shoe if LOT is lower than 2.15 SG EMW. Drilling and coring to the TD. Run and cement at 4 1/2 liner.
6.3
Expected problems: • For the 8 ½” section .Control the mud-weight is however problematic, as a result of fluctuations of ECD (Equivalent Circulation Density), ESD (Equivalent Static Density) and the main problems is the narrow drilling window which in this phase should be larger than thermal expansion of the mud. • Swabbing • Loss/Gain problems • Same others potential problems than in the 8 ½” section.
6.4
Drilling fluids This phase will be drilled with the mud from the previous section lightened to 2.12 SG.
6.4.1
Typical composition of mud (see 8 1/2 section)
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6.4.2
Typical mud characteristics
Weight PV YP YS Gels 0/10’/30’ Filtrate API Filtrate HP/HT E.S. Cl-(Water Phase Salinity) H/E Excess of Lime 6.4.3
: 2.12 SG :ALAP, typically 40-55 CPo : 15-20 lbs/100ft³ : 8 - 20 lbs/100ft³ : 8/25/35 : 0 cc : < 5 cc : > 600 V : 225 g/l : 80/20 - 85/15 : > 1.5 to 2 g/l
Safety stocks Bulk material: Barite Cement G + Silica Flour
: 150 t : 100 t
Material in sacks or drums: BARACARB 50/150 :3t/2t 3 Chemicals to mix 150 m of synthetic base mud Mud / Synthetic Base Oil: Kill mud 2.45 SG Base Oil
: 50 m³ : 75 m³
Recommendations (see 8 1/2 section)
6.5
First Experience Gained on 22/30 C – G4 Well
5 5/8” Section: Drilled from 5,884 metres to 6,103 metres ( 219 metres ) Mud System: XP-O7 Synthetic Base Mud.
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SUMMARY OF MUD PROPERTIES Programmed Range Mud Weight Funnel Viscosity Plastic Viscosity Yield Point Yield Stress Gel Strengths Filtrate API Filtrate HPHT Filtrate HPHT Electrical Stability Chlorides (WPS) Base fluid/ Water Excess of lime
SG sec/ltr lbs/100 ft2 lbs/100 ft2 lbs/100 ft2 lbs/100 ft2 ml/30 min @ 190 °C ml/30 min @200 °C ml/30 min volts g/l (H/E)
2.12 na ALAP = 40 to 55 15 to 20 8 to 20 8/25/35 0 < 6.0 na > 600 225 80/20 to 85/15
Properties during coring 2.06 69 47-52 10-19 5-7 8-24-30 0 4.0 3.8-4.0 >600 145-190 80/20 to 84/16
> 15
2.8-13.7
g/l
SUMMARY OF MUD CONSUMPTION Distance drilled, metres Initial mud volume at start of interval, m3 Volume built including maintenance, m3 Volume at end of section, m3 Volume used on interval, m3 Volume left in hole (suspension mud) Consumption, m3/m Dilution (consumption less hole vol.), m3/m
219 609.5 177.7 242.1 69.5 197.7 0.317 0.303
3
Properties after coring 2.06 80 58-60 15-26 5-7 11-26-33 0 3.0-4.0 550-600 146-195 80/20 to 83/17 2.0-11.5
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Objectives The objective of the section is to core and drill 5 5/8” hole through the remainder of the Middle Jurassic Pentland formation (which lies immediately under the Franklin sands). The goal is to take cores in the sandstone that is interbedded with siltstones and claystones for laboratory analysis. The total depth of the well is planned at fifty feet above the true vertical depth of the prognosed bottom of the Pentland formation. Depending on the results of the cores, the E-logs, etc. a decision will be made whether or not to run a liner for further tests of the formation. If a liner is run, it must cover the reservoir or reservoirs and ensure good isolation between the Franklin sands and the Pentland sands. Discussion. After the cementation of the 7” liner, the pipe was pulled above the calculated top of the cement and the hole circulated with 2.17 SG mud. The circulation of the mud was to provide an equivalent circulating density to the cement that was higher than the static pressure of the drilling fluid. The pipe was pulled from the hole and an 8 1/2” bit run in the hole to drill the cement in the 9 5/8” casing to the top of the liner. The drilling assembly took weight at approximately 4,956 metres, washed to 5,026 metres, and hard cement was drilled to the top of the liner at 5,035 metres. The weight of the mud was maintained at 2.17 SG while drilling the cement by the addition of pre-mix. Scrapers were included in the string when running the mill to clean out the polished bore receptacle. The mill was laid down and the ENACO isolation packer was run in the hole, set, and tests made as per programme. At this time forty seven cubic metres of pre-mix were prepared to reduce the density of the XP-O7 synthetic mud from 2.17 SG to 2.06 SG to drill the Pentland formation. The programme specified a 2.12 SG drilling fluid to drill the formation, but the programme was revised to the lower mud density. The pre-mix consisted of 10 m3 of XP-O7 Base fluid, Duratone HT at 24.1 kg/m3, EZ MUL 2F at 48.5 kg/m3, INVERMUL 2F at 16.2 kg/m3, Lime at 10.6 kg/m3, RM-63 at 4.0 kg/m3, and SUSPENTONE at 7.2 kg/m3. After diluting the active system with pre-mix, Baracarb ‘50’ and Baracarb ‘150’ was added to the system at 2.8 kg/m3 and 0.9 kg/m3 to restore the concentrations of bridging material in the mud. The concentrations of the emulsifiers EZ MUL 2F and INVERMUL 2F were increased to counteract the contamination of the mud by the spacer incorporated into the system during the trip into the liner. (Note: The contamination of the XP-O7 synthetic based mud by agents in the spacer meant that regular additions of GELTONE IV, SUSPENTONE, and RM-63 had to be made for rheology/suspension.) The 5 5/8” bit was run to 5,427 metres and washed to 5,690 metres, the plug and collar were drilled and cement drilled to 5,871 metres where the integrity of the liner was checked. The shoe was drilled, formation drilled from 5,884 metres to 5,890 metres and a formation integrity test (FIT) performed. The FIT yielded a 2.35 SG mud weight equivalent that was more than adequate for the expected formation pressures in the Pentland formation. One hundred seventy five cubic meters of reserve mud was diluted from 2.17 SG to 2.06 SG. Calcium chloride, Duratone HT, EZ MUL 2F, INVERMUL 2F, and Lime were added to the dilution to 4
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maintain the concentrations of Calcium chloride at 39.0 kg/m3, Duratone HT at 69.0 kg/m3, EZ MUL 2F at 60.0 kg/m3, INVERMUL 2F at 25.0 kg/m3, and Lime at 92.0 kg/m3. Coring. At 5,890 metres the core barrel was run into the hole to cut core #6. The core jammed at 5,902 metres after cutting twelve metres of core. The coring assembly was pulled at this depth. Recovered 10.75 metres of core. Core #7 was cut from 5, 902 metres to 5,928 metres. Recovered 13.84 metres of core. Core #8 cut from 5,928 metres to 5,944 metres before the core jammed. XP-O7 was added to control the density at 2.06 SG and EZ MUL 2F added to increase the electrical stability from 503 volts to the programmed six hundred volts or more. The decrease in electrical stability, increase in water percentage, increase in plastic viscosity, etc. was caused by rain water getting into the system. The water was incorporated into the mud because the 3 1/2” pipe was pulled “wet” and in the absence of a functional mud bucket for this size of pipe it was necessary to take the run off into the drains from the entire surface area of the drill floor instead of the normal area of the bell nipple during a heavy rain shower. Recovered 3.57 metres of core. Cut core #9 from 5,944 metres to 5,950 metres. While circulating bottoms up, two drums of RM-63 and approximately 0.9 kg/m3 of SUSPENTONE was added for maintenance of the system. The addition of rheology modifier and suspension agent was made because the bottom’s up weights after cores were consistently 0.04 SG higher than the 2.06 SG of the active mud. There was no indication of sag because the mud weight did not drop below 2.06 SG when circulating. Recovered 3.5 metres of core. Core #10 was cut from 5,950 metres to 5,965 metres. Before starting to core, 10 m3 of high viscosity mud (159 seconds/litre) was pumped ahead of dropping the ball. The purpose of the high viscosity mud was to try to fill the core barrel with thick mud to preclude the possibility of barite from settling out on top of the core. Before pulling out with core #10, twenty cubic meters of low filtrate mud (1.8 cc/30 minutes at 200º Celsius) was spotted on bottom. The purpose of the low filtrate mud was to reduce the possibility of filter cake build up in the open hole. Recovered 15 metres of core. When the core was removed from the well, the bottom portion of the corehead was found to be twisted off. A taper tap (spear) was used to try to engage the fish. During circulation of bottoms up after fishing, eight drums of EZ MUL 2F and six drums of INVERMUL 2F were added to the system. The emulsifiers were added because the well would be static during intermediate logging if the fish was not recovered. The bottom of the corehead was not retrieved and two E-log suites were run problem free. The Schlumberger wireline logs indicated good gauge hole and a bottom hole temperature of 193º Celsius was recorded.
Milling operations. A mill was run in the hole to mill the fish. The hole was conditioned for a possible cement plug and side-track operation with 3.44 kg/m3 Lime, 5.24 kg/m3 EZ MUL 2F, 2.62 kg/m3 INVERMUL 2F. The first mill run was substantially worn out when it was pulled. A quantity of cutters and identifiable corehead parts were recovered in the junk basket on the first run. A second mill was run to mill on any 5
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remaining junk. Only minor wear was recorded on the mill with little recovery in the junk basket. Drilling operations were resumed after the second run with a PDC bit.
Mud weight. The original programme specified 2.12 SG density for the drilling fluid in this interval. The mud weight was revised to 2.06 SG based. Evaporation / mud cooler. The mud cooler was not required because of the low flowline temperatures. The maximum flowline temperature recorded was 47º Celsius. The temperatures are low because of two factors. Firstly, the low circulation rates mean that a small volume is being circulated through the area where the high bottom hole temperatures are extant. Secondly, the cooling effect of the mud passing through the riser which is in contact with 92 metres of cold sea water acting as a heat sink. Alkalinity. As in the previous interval, the constant addition of lime was required to maintain the alkalinity of the system. Levels of treatment were high and resulted in an increase to 58.32 kg/m3 of lime added over the section. To maintain the alkalinity, treatments while coring/drilling of 3.0 to 5.0 kg/m3 were required. Even these additions did not substantially improve the recorded alkalinity. Low levels of shear and long circulation times tend to make mud treatments less effective. Sag. Sag of barite was not detected in this interval of the well. A minimum of five kg/m3 of SUSPENTONE was maintained in the system at all times to help preclude the possibility of sag. When circulating bottoms up the mud weights from inside the cased hole were constant. The mud from the open hole section was heavier - typically 0.04 to 0.06 SG above the original mud weight. This change in mud weight was attributed to filtration to the hole. Given the amount of barite in the system the amount of filtrate that would have to be lost is very small, a loss of 2% would account for a change in the weight from 2.06 to 2.12 SG. Based on the volumes of heavy mud returned a filtrate loss of 1.0 m3 would account for the increase in the returning mud weights from the open hole. The 14 - 15 m3 of open hole volume was spread over about 50 m3 by the time it had travelled the 6 kilometres to surface. During the returns from the cased hole the mud weight was constant. The only variation being the change in weight with increasing temperature - at the reference temperature the weight was constant. The only change in the weight was from the open hole section and were in the ranges described above. The increase in weight did not appear to be time dependent as similar increases in the mud weight were seen after a short trip or after a trip following 6 days of no circulation during the logging program. This would indicate a high degree of stability in the mud system at the elevated temperatures recorded on this well. The highest bottom hole temperature recorded during the final phase of the logging programme was 203 degrees Centigrade (401 degrees Fahrenheit)
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Low Gravity Solids. The profile of the particle size distribution showed that low gravity solids were not a problem in this interval. Geology.
FORMATION Middle Jurassic: Pentland Formation Total depth
Predicted Top Actual Top TVD RTKB TVD RTKB TVD RTKB TVD RTKB m m m m 5,923 5,776 5,842 5,700 6,323 6,176 6,103 5,960
Formation related problems. No mud related problems were experienced while using Baroid’s XP-O7 mud system in this interval. The presence of water sensitive formations does not seem to be a problem because the formation was predominately sandstone with stringers of siltstone and claystone and coal. The siltstone and claystone stringers were adequately stabilised by the mud. Liner. No liner was run due to the absence of commercial hydrocarbons in the Pentland formation at this location. Following the logging programme the open hole section was plugged and abandoned. The Pentland formation was cemented up. Solids control. The primary solids control are the two BRANDT and five SWECO shakers. The BRANDT’s were fitted with 10 mesh screens on the top deck and by 30 mesh screens on the bottom. Due to the small size of cuttings when coring, virtually no cuttings were removed by the BRANDT shakers. Three of the SWECO shakers were initially fitted with 185x185x120 mesh screens, and the remaining two SWECO shakers were fitted with 150x150x120 mesh screens. At the first opportunity after the mud sheared and heated up, two of the five SWECO shakers were shut down and kept on standby. Of the remaining three shakers, finer screens were put on shaker number four and number five. The set of 185x185x150 mesh screens on shaker four was replaced by 250x250x185 mesh screens. The set of 150x150x120 mesh screens on shaker five was replaced by 250x250x185 mesh screens.
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The Santa Fe ALFA LAVAL centrifuge was removed from the Galaxy I because it could not process the 2.17 SG XP-O7 from the 8 1/2” hole section to reduce it to 2.06 SG. The plan is for the centrifuge to be serviced before being returned for the next well.
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Recommendations: 1.
TYPE OF MUD.
Type Used XP-O7 - synthetic based mud 2.
Recommended XP-O7 - synthetic based mud
DENSITY.
An initial density of 2.06 SG provided sufficient over balance to the formation pressure initially. There were no centrifuges to run when required in order to control the mud weight so that dilution was required to maintain the weight required. Density Used 2.06 SG at 50° C 3.
Density Recommended 2.06 SG at 50° C
CONTINGENCY STOCKS.
Barite, lost circulation material, and base fluid stocks should be reviewed with the Elf supervisor prior to starting each section. It is recommended to continue to keep these minimum contingency stocks for each future 5 5/8” section.
Starting Stock Minimum Contingency Stock 4.
Barite
LCM
341 MT 150 MT
17.6 MT 6 MT
Base Fluid 125 m3 75 m3
RHEOLOGY.
Yield points of 10 lb/100 ft2 gave adequate hole cleaning properties. A yield stress of 7 was adequate for the low hole angles in this section. No tight hole attributable to cuttings beds or poor hole cleaning was seen. Gel strengths were seen with flat 30 minute gels. Gels were typically 14/26/30 to 15/32/37. Used Recommended
PV
YP
Yield Stress
ALAP
10 to 15
7 to 10
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5.
EMULSIFIERS and HPHT.
There was minimal evaporation rates in this section, water additions were not required to maintain the base fluid to water ratio (H/E).
6.
Electrical Stability
Used Recommended
Primary Emulsifier EZ MUL 2F EZ MUL 2F
Used Recommended Used Recommended
HPHT, ml. 3.0 < 6.0 4.0 < 6.0
Temperature deg C. 200 200 190 190
> 600
ALKALINITY.
Continue to use lime to maintain an adequate alkalinity. ARCOSOLV produces results that are typically three quarters to half that of Xylene / IPA solvents. Excess lime kg/m3. Used Recommended, engineers Recommended, program 7.
5.0 to 10.0 2.0 to 3.0
EVAPORATION.
No evaporation detected or recorded on this section. No water additions required because of water addition to the system during a trip during a down pour. 8.
BASE FLUID TO WATER RATIO AND WATER PHASE SALINITY.
The base fluid to water ratio was decreased whilst wet tripping with the drains lined up to return to the pits. The mud bucket has been modified for use on the 3.1/2” pipe so that it is no longer necessary to line up on the pits when wet tripping. The programmed water phase salinity was 250,000 mg/l chlorides. The actual salinity used was 175,000 - 190,000 mg/l chlorides. The hole was stable with the lower figure because the formation was primarily sandstone, claystone, and siltstone with occasional stringers of coal. Sandstone and coal are stable irregardless of the water phase salinity. The claystone and siltstone were stable as demonstrated by a hole that was in gauge on the caliper logs.
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Base fluid/ Water ratio Used Recommended 9.
80/20 to 84/ 16 80 / 20 to 85 / 15
LOW GRAVITY SOLIDS.
Low Gravity solids kg/m3. < 150 < 150
Used, corrected Recommended 10.
Water Phase Salinity. mg/l Chlorides 145-190,00 225,000
SOLIDS CONTROL.
Used at start. Used at end. Recommended at start. Changing to :
Scalper
Scalper
12/30 12/30 12/30 12/30
12/30 12/30 12/30
No. 1 250 250 250
N0. 2 185 250 250
No. 3 185 185 185
No. 4 250 185 185
No. 5 150 325 185
12/30
250
250
250
250
325
The last screen, out of 3, was a 185 mesh screen on each of the main shakers. This is to minimise mud losses and to lower base fluid on cuttings figures. 11.
BASE FLUID ON CUTTINGS.
Interval average Well average
92.71 gm/kg 73.28 gm/kg
The low rates of penetration with coreheads produced fine cuttings resulting in a high arithmetical average for the Base Fluid On Cuttings. Data from QTEC. 12.
CEMENT DRILL OUT.
Drill out of cement. Use the XP-O7 mud to drill out the cement. 13.
KILL MUD USED.
Type & Weight Used XP-07, 50+m3 0.3 SG above mud weight, up to kill weight of 2.35 SG 14.
Recommended XP-07, 50 m3 0.31 SG above mud weight at 50º C
PIT MANAGEMENT.
Minor problems were encountered with the pits due to the large quantities of mud in the pits. These large quantities were maintained on site due to the possibility of losses in the Pentland. This reduced the flexibility of the pit system. For example, the slug pit was filled with pre-mix 11
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to control the weight after a trip. Remaining premix had to put into a pit of mud so that a slug could be mixed during a trip. After the trip the slug pit was again used filled with pre-mix. 15
WELL SUSPENSION
On completion of the 5 5/8” hole abandonment programme 179 m3 (one hole volume) of XP07 @ 2.17 sg was conditioned with 6.09 kg/m3 GELTONE IV, 13.45 kg/m3 INVERMUL-2F, 13.90 kg/m3 Lime, 7.58 kg/m3 SUSPENTONE and 8.51 kg/m3 RM-63. This high viscosity temperature stable mud was displaced into the well above a bridge plug which had been set at 5,030 metres and after running a debris cap the well was left suspended for future production.
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6.6
4 1/2” liner and cementing A 4 1/2” liner will be run and cemented to the liner hanger. Running the liner: Prior to run the liner, the gel strength and yield point must both be reduced, the yield point + 15 lb/100ft², and the 10’ gel to < 23 to avoid excessive surge pressures when running in. Pilot tests will be completed by the mud engineer to determine the optimum treatment levels. Cementing job: The liner will be cemented with a gas tight slurry 2.30 SG. The slurry volume will be calculated according with the calliper volume + 20% and an excess corresponding at 100 metres of annulus volume (7”liner x 3 1/2” DP). Slurry volume calculations (indicative, G4 Well ), 4 1/2” liner not set. 5 5/8” hole volume 5 5/8” x 4 1/2” annulus 7” x 4 1/2” annulus 7” x 3 1/2” DP annulus 4 1/2” inside volume 5” DP inside volume 3 1/2” DP inside volume
16.03 l/m 5.73 l/m 6.39 l/m 10.08 l/m 6.68 l/m 9.14 l/m 3.82 l/m
Slurry volume Spacer volume
± 4 m3 10 m3
Displacement
± 52 m3
Fluid designs. - spacer : Mud push WT DOWELL formulate spacer, 2.25 SG. Fresh water D144 D020 D143 D135 D031 F075N
Defoamer Bentonite FLAC Temp. Stabilizer Barite Surfactant
13
385 l/m3 3 l/m3 8 kg/m3 3.9 kg/m3 10.6 l/m3 1676 kg/m3 47 l/m3
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! Tail slurry: gas tight 2.30 SG.
G cement (Dyckerhoff) D066 Drill water D144 D134 D135 D121 D161 D076
Silica Antifoam Gasblok Temp.Stabilizer Dispersant Retarder Hematite
350 kg/t 105 l/t 4.4 l/t 310 l/t 31 l/t 10 kg/t 160 l/t 840 kg/t
Remarks: 1. all the formulations are indicative, they must be confirmed by laboratory tests performed with samples coming from the rig before the cement jobs. 2. For an accurate displacement, the internal diameter of the casing must be measured on 10% random joints.
Cement slurry properties: Density Yield
2.30 SG. 1231 l/ton.
Thickening time Fluid loss Free water Compressive strength at BHCT
14
± 8h00 < 50ml. < 0.1% >300 bar 48 h
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7.
Mechanisms of Wellbore Instability in the Transition Zone
Operational Considerations Symptoms and Remedial Action Foreword The intention of this chapter is to present the experience get during the first development well drilled on ELGIN / FRANKLIN field with GALAXY 1 and MAGELLAN . This is done in order to make it available to the people in charge of such particular well , but also to generate discussion on this up to date topic within drilling people with similar experience . Reservoirs in the Upper Jurassic Franklin sands and the Middle Jurassic Pentland sands are hot { 200°C } and deep { 5800 m}. The pressure gradient exhibits a marked increase below the Kimmeridge claystone with reservoir pressure of 1200 bars . These considerable drilling challenges are compounded by the small margin – approximately 100 bars between fracture and pore pressure in the lowermost intervals . 7. 1
Well Instability :
Introduction : The Kimmeridge Clay + Heather which is a known hydrocarbon bearing source rock , exhibits a mode of behaviour when exposed to mud weights at or close to the fracture gradient variously described as Loss / Gain situation ; Ballooning ; Supercharging ; Thermal Effect or Plastic Shales . Essentially the effect is for partial mud losses to occur to the claystone during circulation /drilling followed by an apparent influx when the pumps are off .With the well shut in on an apparent gain preceded by losses , the annulus pressure recorded will be the difference between the static mud weight ( ESD ) and the dynamic friction losses ( ECD ) , i.e the additional back pressure applied to the formation while drilling . This type of behaviour could be described more graphically as well Instability . Rig Crew’s experience shows Well Instability can be the beginning of a process with HPHT well which can ultimately lead to a Well Control situation .The essential difficulty when faced with the loss / gain behaviour is the ability of rig crews to recognise and quantify the effect , thereby gaining the necessary confidence to drill ahead . Guidelines need to be prepared which lead the crew through a logical process of Flow checking , Shut in , Recording , Calculating , Venting and Circulating . ( see Attachment “ Flow charts decision “ ) Coupled with the loss / gain problems the increasing background gas levels experienced within the Kimmeridge which can be misinterpreted to indicate a balance or underbalance drilling conditions and lead to :
Unnecessary Increases in Mud Weight .
1
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7. 2
How to recognise a well instability?
The well is considered unstable when: 1. A flow check is unstable ( well flowing ) 2. No pressure readings are shown at the annulus pressure gauge or at the stand pipe pressure gauge 3. Free gas ( gas degassing at the bell nipple ) are shown at the bottom’s up of the circulation or in dynamic conditions without affecting the mud parameters . 7. 3
Reasons for well instability:
Two main reasons can lead to a well instability. Firstly the pore pressure in the reservoir is locally higher than the hydrostatic pressure applied by the mud , but due to a low permeability formation , we are not in a kick situation : No pressure readings at surface. Secondly , the equivalent circulating density applied to the formation lead to seepage losses ( losses of filtrate and possibility of losses of small quantities of whole mud to the borehole ). Theses small losses are difficult to detect on surface , but will generate a small gain of fluid when the circulation is stopped . A kind of circulation through this formation can be conceive in dynamic conditions .( see drawing ) Manifestation of well instabilityHigh formation pressure : the flow check shows mud returns , with no signs of stability (steady flow). The circulation of the bottom’s up will show high gas readings with a possibility free gas at surface. Gain and losses situation: ( known also as supercharging the formation ) the flow check shows mud returns, with a tendency of the flow check to decrease with time. Again the circulation of the bottom’s up will show high gas readings with a possibility of free gas at surface, this is due to the large surface area of the mud in contact with the gas bearing formation. Both manifestations can be the same and trends are of a paramount importance to understand in which cases we can classify the instability. Here some of the parameters we need to focus on : Early detection of losses. Annulus pressure losses ( PWD ) and , or Hydraulic simulation (ECDELF or BAROID DFG). From the above manifestations it is difficult to conclude if the well was unstable due a compartmentalised high pressure zone , from a losse and gain situation or from a natural depletion due to a minor-supercharging generated in drilling conditions.( high ECD’s )
2
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7.4
GUIDE - LINES - EXPERIENCE
Nevertheless, all steps must be taken to avoid any supercharging of fluid to the formation , so to reduce the ECD. • Maintain the ECD ; 5 points (0.05 sg) below the fracture pressure in any case • Use of a lower mud weight to drill the upper part of the transition zone (2.15 sg mud weight at 50ºC similar to 22 / 30c-G5 well i.e ) • Use of low plastic viscosity and a yield point as low as possible without impairing the suspension of the weighting material. • Expand flow check at the top of sands until reaching the stability of the well . • Bleed off process of Liquid and Mud influx with a maximum volume acceptable , repeat the operation until stability . • Also, to better analyse an unstable well, it is recommended to increase the number of flow checks while drilling through the Kimmerigde and Heather formations to spot any high pressure zone at once. A compromise must be found between the Time Factor ( see experience on wells drilled with the new XP07 mud system ) , the rheology of the fluid , the back ground gas detected , the flow back volume acceptable and Drilling practices such as systematic extended flow checks before pulling out of the hole .
Pulling out of hole : A long series of flowchecks , short trips between bottom hole and shoe and bottom up circulation had to be made before the whole drill string could be pulled out of the hole with the well stability judged satisfactory enough by the Elf and drilling contractor’s supervisory personnel . [ The details of these Flow charts are shown on a schematic in appedix ]
3
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7.5
Matrix :
See attached a recap of the Indicators which are linked with a probably well instability .
4
8 1/2" Section - TRANSITION ZONE
INDICATORS
Well Instability Analysis 22/30C -G4
22/30C -G5
22/30C -G6
29/5B - F1
29/5B - F2
Back ground Gas >= @ 5 to 6%
No
No
Yes
No
No
No
Gas freeing at bell nipple - Gas Alarm on
Yes
No
Yes
Yes
No
No
Free gas after Bottom up
Yes
Yes
Yes
Yes
No
No
Intermediate Flow Check stable
No
Yes
No
No
Yes
Duration of Connection Gas ( short )
Yes
Yes
Yes
Yes
Yes
Seepages Losses reported > 0.5 m³/hour
No
No
No
No
No
Yes
No
ECD >>or = @ 2.27 EMW
Yes
No
No
No
No
No
No
Gas at the end of 12 1/4" phase-Caprock
Yes
Yes
No
Yes
Yes
No
No
Trend of mud losses >> @ 100 litres / drilled meter
Yes
No
Yes
No
No
No
No
Mud Weight @ 50°C
2.17
2.15
2.15
2.14
2.15
2.15
2.15
INSTABILITY PROBLEMS
Yes
No
Yes
Yes
No
No
No
Page 1
29/5B - F3
Yes
22/30 C -G7
Yes Yes
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7.6
Strategy : A strategy has been decided before drilling through the transition zone [ see attachment ]
5
HT/HT Transition Zone on ELGIN STRATEGY 1 - Start drilling with SG=2.15 @ 50°C 2 - Rheology => A.L.A.P with low gels (Gels 0/10/30 = 28/30/35) + Bridging agent 3 - One connection gas by stand 4 - Three Flow-Checks (base C.K, Kimm., Heather) - 1 hour or (5 to 10 bbls of mud flowback) - Note: well does not have to be stable to resume drilling. 5 - Flow rate = 1500 l/min, ROP controlled to 5 m/hour 6 - Gas monitoring with respect to G4 7 - HP/HT procedures according to JDM
HP/HT TRANSITION ZONE 22/30c - G4 well (example) LEGEND POTENTIAL EXPLANATION PORE PRESSURE SUPERCHARGING PERCOLATION / DIFFUSION Liquid - Condensate CONTAMINATION
PARAMETERS PP = 2.10 SG Mud Weight = 2.17 @ 50°C ECD @ 1500 L/MIN = 2.26 SG ESD = 2.18 SG Rheology: PV/YP > 45/17
OVER-PRESSURE / SUPERCHARGE SAGGING EFFECT BALLOONING THERMAL EFFECT
KIMMERIDGE CLAY
FRANKLIN SANDS
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7.6.2
HP / HT Tripping Procedures :
6
LOSSES/GAIN WHILE DRILLING HP/HT SECTION
Consider reducing : flow rate, RPM, mud weight, rheologie
DRILLING
Dynamic losses while drilling
Flow check : well flow ?
No
See losses while drilling
Yes No
Monitor well on trip tank. Has well flowed > 800 l (5 bbls) ? Yes Shut in well Record pressure
Compare with trends/volume lost since last stability situation
Review situation No Supercharging suspected ? Yes No
Bleed off 800 l (5 bbls). Well flow continues ? Yes Shut in well. Record pressure
Pressure < previous
No
Yes Circulate bottoms up No
Yes Flow check : well flow ?
DRDE9435.PPT
Follow well control procedure
LOSSES WHILE TRIPPING Flow Check
Losses < 130 l/min (0.8 bbls/min) No
Yes RIH to last casing shoe or stay in same level in OH
Consult Aberdeen operation
Observe while circulating
Losses < 65 l/min (0.4 bbls/min)
Yes
RIH to bottom
No Spot LCM pill
Losses < 65 l/min (0.4 bbls/min)
Yes
No Consider options with Aberdeen operation
Cement plug and squeeze
Wash to bottom
Follow losses/gain while drilling DRDE9435.PPT
HP/HT PROCEDURE WELL FLOWING Operation
Drilling
Tripping
Raise kelly cock above RT
Stop pump and RPM
Out of hole
Install open kelly cock
Close B/S
Weight > 25 KLBS
Analyse situation
Yes
No
Close annular Close annular Open choke line
Close PR above tool joint
Open choke line Record time and pressure
Install and test Top drive
Close Kelly cock
Equalise pressure and open kelly cock
Install and test kick assembly
Observe pressure
Equalise pressure and open kelly cock
Analyse situation
Analyse situation
DRDE9435.PPT
Case 1 (JDM)
Stripping
Case 2 (JDM))
Bullheading
Case 3 (JDM)
Off bottom kill
LOSSES WHILE DRILLING
Flow check
Static losses
No
Yes Adjust flow rate, RPM and parameters, … etc. ...
Reservoir pressure known Yes No
Reduce mud weight until optimal
Observe while circulating No
Cure losses with LCM
Losses < 35 l/min (0.2 bbls/min)
Observe while circulating
Losses < 35 l/min (0.2 bbls/min)
Yes Yes
No Consider option with Aberdeen operation
Cement plug
Drill plug
Losses < 35 l/min (0.2 bbls/min)
Yes
No Consider option with Aberdeen operation
Liner
DRDE9435.PPT
Continue operation with action to avoid further losses
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7. 7
Fluid Simulator :
ECDELF Software
7. 7. 1
Drilling Fluid Properties :
Conventional calculations of downhole pressure, which assume constant drilling fluid properties , are both practical for day to day use and accurate enough for routine wells. Downhole static pressures are easy to to calculate from mud weight measured at surface , while aditional pressures due to circulation can be calculated using established relationships between pump rate and drilling fluid rheological properties . However , mud properties do vary with downhole pressure and temperature , affecting the accuracy of both surface measurements and downhole estimations of mud weight and viscosity . In HPHT wells these variations can be significant because of the limited safety margins existing . 7 . 7. 2
Computing Downhole Fluid Pressure :
Instead of using EMW and ECD when calculating pressure in HPHT wells , it is more accurate to consider static , dynamic and cuttings pressures as components of the total downhole fluid pressure . Static Pressure : Static pressure is computed by integration of hydrostatic pressures at each depth .To achieve this , pressure – volume- temperature ( PVT) analysis is usually performed on the mud or the base oil . Many base fluids used for oil- base muds have high compressibility compared with water based muds. By starting at the surface where the pressure and temperature are known , the local density of the fluid can be computed. The predicted hydrostatic pressure and temperature permit the density at the next deeper level in the well to be computed .At the wellsite , the measured mud weight is used as the starting point , increasing the accuracy of the initial conditions . With PVT data , static pressure at each depth can be computed with ECDELF software . Dynamic pressure : The dynamic pressure term is more comprehensive compare to the concept of ECD . It can account for annular pressure losses due to moving fluids , pipe velocity ( swab & surge ) and initial pressure from string acceleration when tripping and excess pressure required to break thixotropic gels . Predicting the dynamic contribution to the total pressure requires accurate modeling of the mud rheology . Depending on the fluid , the mud engineer selects an appropriate rheological model on the basis of fitting a curve to data from HPHT viscometer tests ( FANN 70 ). Alternatively , the mud properties may conform to established relationships , such as Bingham plastic mode or an empirical power law model with parameters chosen to represent the specific mud behaviour . Modeling software such as the ECDELF program incorporating the algorithms for computing dynamic pressure. The advantage of these (over more complex models) is that the rheology parameters derived from them can be easily compared to wellsite measurements made using viscometer readings.
6
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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Total Pressure : The total pressure is the sum of static , dynamic and cuttings pressure . Expressing the downhole pressure in this general form covers all phases of the operations . The total pressure can be balanced between the lowest safe static pressure and the highest acceptable circulating pressure by achieving a compatible balance of the different terms . The ability to compare actual behaviour to ECDELF sotfware and the PWD measurements at the wellsite is of great benefit in accurately predicting ECD ‘s. In practice the ECDELF program routinely achieves average differences of less than 4 % between predicted and measured standpipe pressure . 7.8
Field Results - Conclusions :
No drilling related problems occurred during the ten HP/HT sections . Stable mud system , detailed drilling program, correct execution on field and depth determination of the 9 7/8” casing shoe are fundamental. The following main conclusions and recommendations about fluid engineering and management in HPHT wells derived from the experience obtained . 1. An accurate hydraulic program coupled with a temperature simulator is a critical tool . 2. A methodology is required to accurately predict both a Constant hydrostatic overbalance when the well temperature profile is the geothermal gradient, and also a minimum acceptable hydrostatic overbalance in transient or steady state temperature conditions . 3. Once the minimum overbalance is determined , the standard temperature for surface mud weight must be defined . { 50 °C } Thereafter the mud weight is maintained within a matrix which references the standard temperature. 4. Field execution involves rigorous execution of procedures for evaluating mud characteristics , measuring mud weight , breaking circulation and tripping . 5. The rig crew should be briefed by the fluid engineers on procedures that differ from previously accepted practice and the role that they have to play in management of the Bottom – Hole pressure . 6. The mud temperature must be reported with any mud weight measurement . 7. Due to the reduced hydrostatic overbalance , particular care must be exercised immediately after stopping circulation .Any operations which have the effect of reducing the bottom hole mud pressure must be carried out carefully . 8. The difference between the equivalent circulating density ( ECD ) while breaking circulation and ECD during normal circulation should be understood . 9. Pump rate should be optimized , and a maximum set refined on an on-going basis . 10. Any mud degradation must be anticipated before a long static period ( logging , tripping etc..) see Recommendation practices in HPHT . 11. Continuity of key personnel is also important with a good communication . Attachment : Measured ESD and ECD versus predicted are presented in this document . A recap per well has been done for each HP HT section .
7
Bottom hole pressure gradients on 22/30 C - G6 @ 5929 m Based on 2.16 sg mud, PV / YP=69 / 22 - to be updated according to new mud properties 2.400
Fracturing pressure
2.380
2.39 sg
2.360 2.340 2.320
Static period
Tripping
Circulat. / Drilling
2.300
Supercharging ? 2.280
surge
900 LPM 120 RPM
900 LPM 95 RPM
900 LPM 65 RPM
1100 LPM 98 RPM
1100 LPM 85 RPM
2.180
2.182
920 LPM 85 RPM
2.200
ESD
2.220
ESD
2.240
4 min / STD
PWD
2.20
ESD
swab
3 min / STD
ECDELF 2.260
2.1 82
2.1
2.160
2.16 (mud density @ 50ºC)
2.16 SG
2.15
2.140 2.120
Reservoir pore pressure
2.10sg
2.100 2.080
Elgin Well 22/30C G6 - 8 1/2" drilling section 13/07/2000
ELGIN 22/30c-G7 Hydraulics analysis 8½" hole Report nº
Date
Depth Depth Hole TVD angle m m º
Flow rate lpm
RPM
1500
80
Pump press bars
Bit nº
Jets
248
9
2 x 20
BHA nº
Ann vel Ann vel Mud DC DP Wt in m/min m/min sg
Temp Mud Temp in Wt out out ºC sg ºC
Temp MWD ºC
PV cPo
rheology Pore YP 0 gel press bs/100ftbs/100ft EMW
145
51
15
12
50
17
12
53
15
53
17
ESD ELF EMW
ESD PWD EMW
ECD ELF EMW
ECD PWD EMW
2.167
2.241
2.231
12
2.167
2.228
2.229
14
2.165
2.230
FIT press EMW
Formation comments
5128
5040
54
23/09/1998
5142
5058
0.1
55
24/09/1998
5142
5058
0.1
56
25/09/1998
5165
5081
0.1
1100
120
174
10
6 x 12
10
65
47
2.15
40
2.15
45
57
26/09/1998
5259
5175
0.2
1100
120
171
10
6 x 12
10
65
47
2.15
49
2.15
51
58
27/09/1998
5357
5273
0.1
1100
120
172
10
6 x 12
10
65
47
2.15
48
2.15
50
53
16
13
2.164
2.230
Heather
59
28/09/1998
5463
5379
0.1
1100
120
168
10
6 x 12
10
65
47
2.15
50
2.15
52
53
16
15
2.166
2.232
Franklin C sand
60
29/09/1998
5622
5538
1100
120
169
10
6 x 12
10
65
47
2.15
51
2.15
53
61
21
15
2.166
2.232
Franklin B sand
61
30/09/1998
5724
5640
1100
125
181
10
6 x 12
10
65
47
2.15
51
2.15
52
65
23
17
2.167
2.249
Franklin A sand
62
01/10/1998
5724
5640
2.15
70
22
16
2.167
63
02/10/1998
5724
5640
2.15
70
22
16
2.167
64
03/10/1998
5724
5640
2.15
70
22
16
2.167
65
04/10/1998
5724
5640
1150
20
190
10
6 x 12
10
68
49
2.15
76
24
17
66
05/10/1998
5724
5640
1100
30
190
10
6 x 12
10
65
47
2.15
71
20
12
67
06/10/1998
5724
5640
70
21
13
68
07/10/1998
5724
5640
69
08/10/1998
5724
5640
2.35 9
89
64
2.15
46
2.15
51
153
2.15 50
2.15
54
152
Hidra "
2.09
2.171
2.243
" Kimmeridge
2.241
Equivalent Circulating Density on 22/30 C - G7 8 1/2" Section 2.36
Fracture gradient 2.35EMW
2.34 2.32
Supercharging
2.3
ECD ELF 2.28
Equivalent mud weight
Pore pressure 2.26
PWD
2.18 2.16
Pentland @ 5700m
2.2
Heather @ 5357 m
2.22
Kim. @ 5259 m
2.24
Franklin C@ 5463 m
Supercharging area 2.25 EMW ?
MW@50°C ESD Series7 Series8 Series9 Series10
2.14 2.12 2.1
Pore Pressure 2.09 EMW 2.08 5142 5143 5165 5259 5357 5463 5622 5640 5724 5724
Depth MD
Page 1
Sheet2 Chart 1
Bottom hole pressure gradient trends at 5530 metres, 5035 m TVD Well unstability with 2.15sg mud.
2.450
Frac pressure 2.400
2.350
2.300
Supercharging pressure 2.235
2.135
POOH 1 min/std
2.150
ESD
2.16
2.20 800 LPM 0 RPM
2.200
Valhall pore pressure o z ne 2.205
1500 LPM 60 RPM
1500 LPM 130 RPM
2.22
POOH 5 min/std 800 LPM
2.250
2.100
2.050
Franklin sands pore pressure 2.000
Page 1
- 03/02/99
2.450
Frac pressure 2.400
2.350
Supercharging pressure 2.287
2.291 1200 LPM 90 RPM
2.150
2.100
2.050
2.000
Franklin sands pore pressure
2.245 2.225
Spot 420 m at 2.45sg
Valhall pore pressure o z ne??
2.26 POOH 1 min/std 800 LPM
1200 LPM 60 RPM
2.283
ESD
2.200
ESD
2.225
2.279
1000 LPM
2.250
800 LPM
2.274
1200 LPM
2.300
FRANKLIN 29/5b-F1 Hydraulics analysis 8½" hole Report nº
Date
67 69 70 70 70 70 70 70 70 70 71 72 73 74 80 83 84 85 86 87 92 95 96 99 100 102 105 106 108 109 110 111 112 113 114 115 116 117 118 119 120 121 122 123 Total
26/04/1998 28/04/1998 29/04/1998 29/04/1998 29/04/1998 29/04/1998 29/04/1998 29/04/1998 29/04/1998 29/04/1998 30/04/1998 01/05/1998 02/05/1998 03/05/1998 09/05/1998 12/05/1998 13/05/1998 14/05/1998 15/05/1998 16/05/1998 21/05/1998 24/05/1998 25/05/1998 28/05/1998 29/05/1998 31/05/1998 03/06/1998 04/06/1998 06/06/1998 07/06/1998 08/06/1998 09/06/1998 10/06/1998 11/06/1998 12/06/1998 13/06/1998 14/06/1998 15/06/1998 16/06/1998 17/06/1998 18/06/1998 19/06/1998 20/06/1998 21/06/1998 22/06/1998 23/06/1998 24/06/1998
Depth m 5138 5138 5138 5138 5140 5142 5143 5153 5161 5167 5209 5247 5293 5357 5418 5419 5452 5544 5637 5663 5677.5 5701.0 5701.5 5707.0 5710.8 5718.0 5723.0 5756.0 5756.0 5765.0 5765 5765 5770 5820 5879 5927 5927 5927 5927 5927 5927 5927 5927 5927 5927 5927 5927
Depth TVD RT 5016 5016 5016 5016 5018 5020 5021 5031 5037 5043 5087 5125 5171 5235 5294 5295 5329 5422 5514 5540 5555 5578 5579 5585 5589 5595 5600 5632 5632 5641 5641 5641 5647 5697 5756 5804 5804 5804 5804 5804 5804 5804 5804 5804 5804 5804 5804
Hole angle º 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.0 3.5 3.5 3.5 3.5 3.5 3.8 3.8 3.8
3.1 3.1
Flow RPM Pump Bit rate press nº lpm bars 1500 100 300 10 RIH @ 4479 m at 2.75 min/STD RIH @ 5118 m at 2 min/STD 900 20 150 11 1000 50 155 11 1000 100 175 11 1100 15 183 11 1000 105 180 11 1100 105 202 11 1100 108 202 11 1100 110 196 11 1127 140 191 11 1120 139 194 11 1100 98 210 11 915 100 149 12 1090 101 195 13 1115 100 181 13 1100 100 180 13 1100 130 193 13 1100 129 210 13 900 120 155 12R1 920 130 146 14 900 130 148 14 900 120 155 14 900 120 155 14 1030 80/120 180 14R2 1040 120 206 15 1100 140 233 15 16 1000 130 198 16 16 17 1155 142 240 17 1120 141 240 17 1155 140 233 17 1170 140 231 17
Jets
3 x 20 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 2x16 2x18 TFA 0.75 4x10+4x12 4x10+4x12 4x10+4x12 4x10+4x12 4x10+4x12 0.76in² 0.76in² 0.76in² 0.76in² 0.76in² 0.76in² 4 x 13 4 x 13 0.76in² 0.76in² 0.76in² 4 x 14 4 x 14 4 x 14 4 x 14 4 x 14
BHA nº 11 12 12 12 12 12 12 12 12 12 12 12 12 12 13 14 14 14 14 14 15 16 16 17 17 18 19 19 20 20 20 21 21 21 21 21
Ann vel DC m/min 99
Ann vel DP m/min 64
59 66 66 72 66 72 72 72 74 74 72 68 72 73 72 72 72 59 61 59 59 59 68 68 72
38 43 43 47 43 47 47 47 48 48 47 39 47 48 47 47 47 38 39 38 38 38 44 44 47
66
43
76 74 76 77
49 48 49 50
Mud Wt in sg 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.14 2.15 2.15 2.15 2.14 2.14 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15
Temp in ºC 53 24 26 35 38 39 42 44 45 46 46 46 46 47 38 35 44 48 49 50 37 37 40 40 40 45 42 53
Mud Wt out sg 2.14 2.14 2.14 2.14 2.14 2.15 2.15 2.14 2.13 2.14 2.14 2.15 2.15 2.15 2.14 2.14 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15 2.15
Temp out ºC 56 18 19 32 39 41 44 46 48 49 50 49 52 52 46 39 49 52 55 56 40 40 44 45 45 50 47 59
43
2.15
44
41 51 53 56
2.15 2.15 2.15 2.15
43 56 56 60
Temp PWD ºC 153 157 139 144 146 146 146 150 150 152 154
157 158 162 165 167
Temp BHST ºC
158 159 161 163 167 170 170 171 177 182 183
163
164 171
190 195 198
PV cPo 70 70 67 67 67 67 67 67 62 62 54 54 50 52 53 53 50 62 62 63 60 61 61 63 64 69 71 67 64 63 65 67 66 66 64 65
rheology YP 0 gel lbs/100ft² lbs/100ft² 33 18 33 18 26 10 26 10 26 10 26 10 26 10 26 10 21 10 21 12 22 10 21 13 21 12 18 11 17 10 18 12 16 14 18 14 19 12 19 10 18 10 18 9 18 9 19 12 20 14 19 12 18 13 20 13 20 13 19 12 19 12 20 13 20 15 18 14 21 14 19 13
Pore press EMW
2.16 2.18 2.16 2.14 2.13 2.11 2.11 2.06 2.07 2.04
ESD ELF EMW 2.153 2.211 2.229 2.168 2.162 2.160 2.158 2.157 2.155 2.154 2.154 2.155 2.153 2.164 2.166 2.166 2.158 2.155 2.167 2.163 2.173 2.173 2.171 2.170 2.170 2.167 2.171 2.162 2.170 2.170
ESD PWD EMW
2.173 2.163 2.162 2.162
n/a n/a n/a n/a
2.19 2.20 2.162 2.162 2.162 2.165 2.170 n/a 2.17 n/a n/a n/a n/a n/a 2.15 n/a n/a n/a
ECD ELF EMW 2.253
ECD PWD EMW
2.242 2.242 2.246 2.237 2.243 2.242 2.240 2.236 2.233 2.231 2.237 2.226 2.235 2.216 2.216 2.238 2.240 2.245 2.254 2.251 2.251 2.228 2.226 2.234 2.228 2.233 2.233
2.200 2.223 2.230 2.220 2.235 2.240 2.237 2.237 2.227 n/a n/a n/a n/a 2.197 2.210 2.223 2.223 n/a n/a n/a n/a n/a n/a 2.240
2.247 2.236 2.236 2.245
2.25 2.24 n/a n/a
FIT press EMW 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33 2.33
2.33 2.33 2.33 2.33
195 2.166 197 1150
50
177
17R
4 x 14
22
76
49
2.15
40
2.15
42
70
26
9
2.17
2.244
Sola Heather Franklin C
Franklin A Pentland Pentland Pentland Pentland Pentland Pentland Pentland Pentland Pentland Pentland
2.04 2.03 2.03 1.98 1.97
Formation comments
2.33
MEASURED AND CALCULATED ANNULAR PRESSURE
2.340
2.320
BHCT @ MWD : 164°C 2.300
Temperature out : 43°C
2.280
2.260
Supercharging ?? PWD
2.240
ECDELF
2.180
2.173
ESD
2.200
ESD
2.220
2.173
2.160
2.140
2.120
Franklin Well 29/5B-F1 8 1/2" drilling section 09/07/2000
Equivalent Circulating Density on 29/5B - F1 8 1/2" Section Fracture gradient 2.33EMW
2.32
2.3 Supercharging 2.28
ECD ELF Pore pressure
Supercharging area ?
2.24
Pentland @ 5637m
2.16
Franklin C@ 5293 m
2.18
Heather @ 5209 m
2.2
Sola @ 5167 m
2.22
ESD with MDT 2.172 @ 5876 m MD
PWD
Seepages Losses 200l/hour
Equivalent mud weight
2.26
MW@50°C ESD Series7 Series8 Series9 Series10
2.14
2.12
Pore Pressure 2.13 EMW
2.1 5140 5143 5161 5167 5209 5247 5293 5357 5418 5452 5544 5637 5677 5701 5701 5707 5710 5718 5723 5756 5770 5840 5850 5860 5900 5937
Page 1
Depth MD
Hydrau Chart 1
29/2b-F2 - 8 ½ - Pressure
Pore Press. - MDT ESD - ECDELF ECD - ECDELF
Hydrau Chart 1
Pore Press. - MDT ESD - ECDELF ECD - ECDELF LOT
Pore Press.well design ECD - PWD LOT Mud weight at 50ºC
Equivalent Circulating Density on 29/4D - 4 8 1/2" Section 2.39
Fracture gradient 2.40EMW
2.37 2.35 Supercharging
2.33
ECD ELF
Seepages Losses 1 bbl / hour
Core #2-flow=1000l/min
2.15
Core #1-flow=750l/min
2.17
Fulmar @5591 m
2.19
Valhall @ 5330m
2.21
Sola @ 5271m
2.23
Heather @5473 m
2.25
Kimmer @5430 m
2.27
Drilling
Equivalent mud weight
2.29
Core #3/4/5-flow=1000l/min
2.31
Pore pressure PWD
Supercharging area !
MW@50°C ESD Series7 Series8 Series9 Series10
2.13 2.11 2.09 2.07
Pore Pressure 2.06 EMW
2.05 5175 5256 5315 5375 5424 5471 5508 5550 5598 5606 5613 5658 5712 5824 5863 5943 5982 6024 6028 6032 6036 6040 6044 6041
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Depth MD
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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7 .10
8 ½” Section P.W.D Interpretation :
Foreword: A massive data base of valuable information were recorded on this run. The PWD memory gauge gave the same information than the real time ECD’s data. In addition static densities and surge & swab were recorded. While we drilled from 5284 to 5687 metres MD, real time data were pulsed from top to 5654 m (92 % of metrage). 100% of the run was recorded on a memory gauge. 7.10.1
SURGE and SWAB PRESSURE Surge & Sw ab Pressure 0.12
0.1 PWD surge ECDELF surge PWD Swab ECDELF swab PWD Pump out 200 lit/min
0.08
0.06
EMW
0.04
0.02
0 0
1
2
3
4
5
6
7
8
-0.02
-0.04
-0.06
-0.08 M in/stand
Swab pressure are totally in accordance with the ECDELF simulation: Swab versus Tripping speed. Note this pressures are calculated or recorded at the bit. Therefor, only part of the this negative pulses are transmitted to the bottom of the hole. Surge pressure are within one point of density
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7.10.2.
EQUIVALENT STATIC DENSITIES EquivalentStatic densities
2.21 PWD recorded ECEDELF PWD on line 2.19
ESD (sg)
2.17
2.15
2.13
2.11 5200
5300
5400
5500
5600
5700
5800
M easured depth
The ESD predicted by ECDELF are 0.01sg.higher than the recorded PWD measurements. The temperature modelling on ECDELF must be improved to better match the recorded data. This is now possible with the recorded temperature while pulling out of the hole. The average ECD showed an ESD at 2.155sg, when the dispersion of data showed the difficulties to maintan a 2.15sg at 50ºC in the pit, mud weight IN varying from 2.14 to 2.165sg. The information was used to reinforce the communication between the MWD engineers, loggers and rig crew on the necessity to maintain a specific and accurate mud weight. PWD on line data are difficult to pick up by the engineer and must be used with care.
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7 .10.3
EQUIVALENTCIRCULATING DENSITIES :
2.24
2.23
80 rpm 80 rpm 60 rpm
2.22 ECD increase
PWD
80 rpm
40 rpm
80 rpm
ECDELF 2.21
2.2
2.19
2.18 0
200
400
600
800
1000
1200
1400
Flow rate (lpm )
The values of the PWD are in line with the ECDELF at the flow rate of interest 900 to 1200 lit/min. The heating regime of the well must reach a stable phase, before ECDELF is fully accurate. For this graph, the temperatures were adjusted to obtain the same static densities, so flow rate and RPM are the only parameters. The software predict too high values at low flow rate, certainly due to the difficulties to measure the rheology accurately in the laboratory at low shear rate. This is not of a great concern in our wells, as this flow rate will develop low ECD’s in the well.
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7 .10.4
TEMPERATURE : 29/5b-F5 -8 ½ -Tem perature
200 PWD recorded POOH BHST
150 Temperature (º
t
100
50
0 0
1000
2000
3000
4000
5000
6000
M easured depth
Maximum BHCT: 167ºC at 5687 m RKB while drilling, this temperature increased to 171ºC after 2 hours of flow check.
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7 .10 . 5
LEAK-OFF TEST PW D leakofftest
2.32
2.3
2.28
EMW sg
2.26
2.24
2.22
2.2
2.18
2.16
2.14 26/08/99 01:12
26/08/99 01:19
26/08/99 01:26
26/08/99 01:33
26/08/99 01:40
26/08/99 01:48
The values of the leak-off test reflects the surface data.with a static density at 2.162sg, maximum at 2.306sg (Leak-off), and a stabilized value at 2.282sg. All the pressure is transmitted trough the mud.
12
Pressure While Drilling data and software. 1. Conclusions The annulus pressure losses are of a paramount importance in the 8 ½ section where the pore and the
fracturing pressure converge. The PWD tool, measuring the Equivalent Circulating and Static Densities (ECD and ESD) is a precious guide to define the flow rate to drill the high pressure zone. Unfortunately, the tool stop working soon after we started drilling. The coverage is only 12% of the metrage drilled in the 8 ½ section, which is detrimental to the success of the whole operations. It is important to keep using the PWD tool to measure the annulus pressure losses, because many hidden parameters can be detected from this tool, i. e. gelation of the drilling fluid, annulus blockage, barite sagging,… that will adversely affect the ECD. SOFTWARE: ECDELF and BAROID DFG were able to forecast the ECD within 0.01sg (1 point of density) at the nominal flow rate but became inaccurate at higher flow rates and when the pipe rotation was on. Here is some of the lessons learned while drilling the first appraisal well , followed by a typical example of the use of the PWD. 1.1 Equivalent Circulating Densities Be aware of high ECD when restarting the circulation after a round trip, with additional pressure losses in the annulus ( + 0.02 / 0.03 sg ) due to: • heavy mud used to slug the drill pipe while pulling out of the hole,. • a viscous and gelled mud due to lower temperature in the well plus heat degradation of the mud products at the bottom of the well, • a higher mud weight due to overall decrease in temperature in the well, • the sagging or the settling of barite in the lower part of the well. Therefor a special care must be taken when resuming the circulation after a round trip and depending on the extent of the above manifestations, flow rate must be adjusted. Pit levels and flow out are the keys parameters. For a rule of thumb, flow rate had to be decreased by 30% or rotation left at 20 RPM until the first bottom up was out of the hole. Rotation: The rotation of the pipes induces a turbulent component in the flow leading to an higher annulus pressure losses. With a rule of thumb of: 0.01sg for 60 RPM, 0.02sg for 120 RPM, 0.03sg for 180 RPM. Equivalent Circulating Densities measured (PWD) must be compared to ECDELF and BAROID DFG simulations to clarify the validity of the software. 1.2 Surge and Swab Running In the Hole at a controlled speed (1.5 min per stand or below) induces a surge with an equivalent mud weight of 2.25sg.
Pumping out of the hole: the flow rate (250 lit/min when POOH at 5 minutes/stand) applied a pressure that compensates the swabbing effect of the removal of the drill pipes. A too high flow rate is not necessary. Pulling out of the hole: the swab pressure are controlled with very low to ultra low speed of pipes motion. The decrease in pressure brings the hydrostatic to a level which is still very comfortable in front of the reservoir. Nevertheless, the unknown pore pressure of the transition zone (higher pressure?) must be treated differently. Software like ENERTECH WFSURGE can help in defining the optimum tripping speed. The impact in time savings is forecast to be above 24 hours per well. 1.3
PWD utilisation
SPERRY-SUN must improve the reliability of the tool, which is functioning for a too short period of time while drilling the high pressure, high temperature zone (only 12% of the metrage drilled). See table here below. Drilling bit SMITH M 37 P HYCALOG DS56JNV HYCALOG DS56JNV rerun TOTAL
Metrage from to 5183 to 5523 m 5555 to 5560 m 5692 to 5884 m
PWD data from to 5183 to 5185 m 5555 to 5560 m. 5692 to 5750 m
Coverage 1% 100 % 30 %
537 m drilled
65 m of data
12 % coverage
2. PWD run 03/09/97 to 05/09/97
1.1 ECD while drilling 03/09/97 22:30 Circulation at 5533 metres of 25 m3 heavy mud 2.31sg at 50ºC. Flow RPM MW in Temp In BH temp ESD ECD lit/min sg at 50ºC ºC ºC sg sg 800 30 2.19 30 168 2.225 2.29maxi The maximum of the Equivalent circulating density was recorded when circulating with : • a cold mud (higher mud weight and higher rheology) • circulating out the 25 m³ of heavy mud spotted to control a well instability.
04/09/97 02:00 Heavy mud out of the hole Flow RPM MW in Temp In BH temp ESD ECD lit/min sg at 50ºC ºC ºC sg sg 800 20 2.19 44 140 2.205 2.245 As soon as the heavy mud was out of the hole the ECD decrease rapidly, and the flow rate can be adjusted to higher values. 04/09/97 02:30 Drill out core, circulate bottom up Flow RPM MW in Temp In lit/min sg at 50ºC ºC 1000 80 2.19 43 1000 120 2.19 43
BH temp ºC 147 152
ESD sg 2.205 2.205
ECD sg 2.27 2.27
1000 20 2.19 46 150 2.21 2.25 The annulus pressure losses are greatly affected by the rotation of the drill pipes (refer to David Bertin report). The ECD increases circa 1 point of density (0.01sg) per 60 RPM
04/09/97 02:30 Circulate bottom up at 5050 m. Flow RPM MW in Temp In BH temp ESD lit/min sg at 50ºC ºC ºC sg 1000 0 2.19 35 143 2.205 1100 0 2.19 43 142 2.205 1200 0 2.19 44 141 2.205 1300 0 2.19 45 140 2.205 The above values were compared to the ECDELF and BAROID software.
EC D PW D versus sim ulations 2.32 y = 8E-05x + 2.1681 2.3
ECD sg 2.245 2.255 2.263 2.27
ECDELF and BAROID DFG software still need developments. In this particular example, ECD values are corrected at 1000 to 1200 litre/minute, but at lower flow rate, the ECD simulations are too high and at higher flow rate the ECD simulation are too low which can be dangerous when applied to the well: start of a losses and gain instability.
2.28
After theses measurements, the flow rate was kept at 1000 lit /min until reaching the end of the section. This low flow rate in 8 ½ section proved to be adequate for both cleaning the hole and cooling down the core barrel or the PDC bit and had no adverse effect on the performance of the drilling bits.
2.26 2.24 2.22 2.2 400
900
1400
2.1 Surge pressures 03/09/97 Running in the hole, shoe at 5179 metres. Depth Tripping speed Flow surge press. ESD at depth ESD at shoe m min/stand lit/min sg sg sg 2740 uncontrolled 0 + 0.13 2.34 2.28 4500 2 0 + 0.02 2.23 2.23 5020 1.5 0 + 0.04 2.25 2.25 5200 3 0 + 0.03 2.24 2.24 5400 5 0 + 0.02 2.25 2.25* • * 25 m3 heavy mud 2.31 sg at 50ºC on bottom. All measurement are showing that we are far from the fracturing pressure at 2.31sg, specially when we are controlling the descent of the pipes inside the hole.
2.2 Swab pressures 04/09/97 POOH Depth m 5200 4700 3400
Tripping speed min/stand 5 5 3
Flow lit/min 250 0 0
swab press. sg 0.00 - 0.02 - 0.035
ESD at depth sg 2.21 2.19 2.175
ESD at shoe sg 2.21 2.19 2.19
All theses measurements are again showing that we are far from the equivalent pore pressure at 2.09sg (EMW at RKB) maximum measured. The ultra low speed to pull out of the hole could be increased slightly without impairing the well stability.
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8.
COMPLETION - Non - Perforated Well :
8.1
Purpose
The main aim is to safely and successfully run a completion string into the well which can subsenquently be used as an ELGIN/FRANKLIN gas condensate producer . The following procedure described the preparation to turn the well over kill mud to inhibited fresh water . 8.2
Well Clean up Procedure :
Prior to running the clean-up string a mud conditioning trip will be carried out. Inflow Testing General One of the key areas associated with using an underbalanced annular fluid, is the well integrity. It is therefore of paramount importance that the integrity of the well be fully proven prior to running the completion string in a 1 SG annular fluid. The following areas are key:• • • •
Good cement job on the liners Casing / liner pressure tests are good Cement bond logs have been made and show a good cement job Inflow test to the full underbalance of 1 SG fluid.
The only true representation of the well integrity test will be when the final clean up circulation has been made and the well bore has been fully displaced to 1 SG water. This represents the final hydrostatic that will be left in the well. Therefore the primary method for the well integrity check will be to run the clean up string as described below. One of the major benefits is that there will be pipe on bottom at all times during the inflow test hence the well can be better controlled in the event of any influx. This string design will also be enhanced with the following:• • • • •
A pressure/ temperature measurement tool will be run ( PWD tool ). Use of a Multi - Function circulating tool. A float will be run above the circulating tool. Sub run for a drop in check valve. The well will be monitored until the bottom hole temperature returns to the original undisturbed temperature prior to pulling the string.
During the well clean up/ inflow test the following points need to be carefully noted and addressed:•
The fresh water used in the well bore will be underbalanced to the reservoir by 575 bars.
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•
•
The clean up string will be left on bottom after the final circulation has been made, until the well temperature returns to the un-disturbed BHT prior to pulling the string out of the hole. ( 1 SG fluid in the well bore ) Pressure and temperature PWD tool will be run to confirm the bottom hole conditions.
•
The BOP and well head cavities will be jetted to ensure all traces of mud solids are removed.
•
The rig choke and kill lines and the rig choke and kill manifolds will have to be fully flushed in order to ensure that the no mud contamination takes place with the 1 SG fluid.
Displacement to Completion fluid To displace the heavy XP07 mud ( 2.12 SG ) to freshwater it will be necessary to displace initially to an intermediate XP 07 mud of 1.60 SG due to pump pressure limitations. The first 50 bbls of the lighter mud should be viscosified to minimise any channelling. Once the well is stabilised with the 1.60 SG mud it will then be displaced to seawater by pumping a sequence of pills ahead of the seawater to ensure the well is cleaned up as efficiently as possible in the minimum amount of circulating time. The well will then be turned over to the inhibited fresh water completion fluid. Objectives 1. 2. 3. 4. 5.
Displace the XP07 based mud of the well with a minimal interface. Change the wettability of all downhole surfaces from XP07 wet to water wet. Prevent the discharge of mud and/or contaminated water to the environment. Minimise the requirement for backloading “oily” water for onshore disposal. Remove pipe scale, solids, mud solids and other contaminants from the wellbore.
Initial Rig Preparation All rig pits, ditches and lines should be cleaned using degreasing solvents and detergents. They should be rinsed out and squeezed dry. If it is practical, lines should be opened to check for any mud solids that might have settled in them. All the pits, sandtraps and under the shale shakers should be cleaned out and washed down using high pressure cleaning equipment. All fluid transfer lines should be circulated to remove compacted mud from bends and fittings. In the pit room, all gratings should be cleaned, all the lights and beams should be washed down. The success of the well clean-up will be influenced by the cleanliness of the surface equipment. It is therefore, important to ensure that the pits and surface lines have been thoroughly cleaned. Below is a list for the mud engineer and derrickman. To ensure cleanliness of these items after normal pit cleaning a sweep of 200 bbls seawater containing four drums of Detergent should be circulated throughout the above system and any other areas / equipment where completion fluids will be stored as fast as is possible. 2
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All dump valves should have the seals and valve seats checked to ensure that they are in good order. They should be greased to ensure a good seal and if possible be manually guided and checked when being closed to ensure a perfect fit. All ditch gates should be sealed with silicon on each side of the gate. This will need to be replaced if the gate is opened. UNDER NO CIRCUMSTANCES SHOULD BARITE, BENTONITE OR POLYMER BE USED TO SEAL ANYTHING. All pump packing should be examined and if necessary replaced. Any suspect packing is best replaced ahead of time. Packing should be lubricated with grease. Water can all too easily leak into the system and can obscure brine leaks. Packing should be lubricated on a regular basis to ensure minimal losses. The clean-up fluids will be most effective if pumped in turbulent flow. An MFCT (Multi-functional circulating tool) is included in the string and positioned above the top of the 7” liner. Consideration should be given to functioning the BOP’s after displacing the XP07 mud to clean out the cavities if practicable. 8.1 1
Mud Conditioning :
Barriers in place : Tubing
Annulus
Liner
Liner
Kill Weight Fluid ( SBM )
Kill Weight Fluid ( SBM)
BOP
BOP
1. Make up Bottom Hole Assembly and run in hole on 3-1/2” WT-31 drill pipe. BHA to be based on 1 PDC 5 5/8” + 1 Bit sub 4 3/8” + 2 Drill Collars 4 3/8” + 1 jar 4 ¼” + 2 Drill Collars + x Drill Pipe 3 ½” + 1 Crossover + 1 Drill Pipe HW 5” + 1 DHCV + Drill Pipe HW 5”+ Drill pipe 5”. 2. Run in hole with 5” Drill Pipe to top of liner packer. 3. Slowly enter liner and run in hole to 5830 m. 4. Circulate and condition mud until mud properties are acceptable .The treatment consists to add premix mud to reduce rheology and Gels .( SG = 2.12 , PV = 45 / 50 , YV = 20 / 25 , Gels = 18 / 25 / 35 5. Pull out of hole with mud conditioning string. 6. Clean-up and displace to Completion fluid 7
Make up Bottom Hole Assembly and run in hole. Clean up string to be based on 1 PDC 5 5/8” + 1 Bit sub 4 3/8” + x Drill Pipe 3 ½” + 1 Crossover + 1 MFCT tool + 1 9 7/8” SPS Eliminator + 3
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1 float collar + x Drill Pipe 5” + 1 PWD tool + x Drill Pipe 5” + 1 DHCV + 1 10 3/4” SPS Eliminator + Drill Pipe 5” to surface. 8
Run in with the clean out assembly and position circulating valve above the top of the 7 “ liner top.
9
Circulate the well to an intermediate weighted mud system. The first 20 m3 of 1.60 SG mud should be viscosified to prevent channelling. Circulating rates will be determined by pump pressure limitations. As the light mud reaches the bit the highest mud weight differential will be seen (- 225 bars ). When the light mud passes into the 9 7/8” casing the circulating sub should be opened (set down weight on liner top to open the circulating tool) and the circulating rate increased to a maximum of 1000 / 1200 ltrs/min dependent on pump pressure limitations.
10 Inflow test the well. Activate the PWD tool periodically to gain a true indication as to the bottom hole responses 11 Make a final circulation and monitor for any abnormal returns. When the 1.60 SG mud has been circulated around and the well is stable a series of pills, will be circulated ahead of the seawater. Before any of the pills are pumped the circulating system to be used should be checked and cleaned as necessary. As the first pill reaches the bit the pressure differential will be at the maximum, in the region of - 575 bars in hydrostatic alone. When the tail of the last pill passes into the 9 7/8” casing the circulating sub should be opened (set down weight on liner top to open the circulating tool) and the rate increased to a maximum of xx ltrs/min dependent on pressure limitations. It is important to ensure turbulent flow is induced for a successful clean up. See Pill formulation & procedure - Attachment n°1 . Displace with seawater at maximum rate with reciprocation and occasional rotation. NTU and PPM readings should be taken during the displacement. Once NTU and PPM readings are acceptable, stop pumping and inflow test the well. Activate the PWD tool periodically to gain a true indication as to the bottom hole responses Make a final circulation and monitor for any abnormal returns. Displace the seawater with the inhibited fresh water completion fluid. Inflow test the well. Activate the PWD tool periodically to gain a true indication as to the bottom hole responses. Make a final circulation and monitor for any abnormal returns. Pull out of hole with the clean up string carefully monitoring hole volumes.
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Well Technical data - Attachment 1 1.
Well data and Casing string :
1 . 1 Well Data : Liner 7” 42.5 # set at 5883 m MD , top liner Packer at 5038 m MD BRT . Bridge Plug at 5830 m Depth : 6103 m MD BHST = 197 °CPressure = 1162 Bars ( 2.05 EMW ) at TBA top sand A. 1 . 2 Casing : Interval ( m RKB ) 3512 m
Burst ( Bar ) 1296
Collapse ( Bar ) 1337
Drift (“) 8.5
ID (“) 8.74
9 7/8 “ VAM Top - Q125 66.9#
5038 m
1021
890
8.5
8.58
7 “Liner VAM Top 25% Cr 42.7#
5830 m
1347
1402
5.625
5.78
10 ¾” HWST 1 - P110 110.2#
String composition Tubing - Drill pipe
N/A 3 1/2" 15.8# Hydril PH6
Collapse resistance 22,330 psi Min. Burst 22,610 psi resistance Tensile capacity 430,000 lbs Drift 2.423in ID coupling 2.548 in ODcouplings 4.500 in Body ID 2.548 in Capacity Optimum make-up ft.lbs torque Maximum make-up torque ft.lbs Torsional Yield = 10400 ft.lbs
5
31/2"17.05 Hydril 24,410 psi 25,180 psi 470,000 lbs 2.315in 2.440 in 4.563 in 2.440 in
27/8" New10.40 # S135 29716 psi 29747 psi
ft.lbs
386,000 lbs 2.151in body 1.5 in 3.125 in 2.151 in 2.36 l/m ft.lbs
ft.lbs
6000 ft.lbs
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2 - Well Bore Clean -up programme : 2 . 1 . Purpose : To displace the heavy SBM mud ( XP07 ) in the hole with chemicals washers + Inhibited Drill Water 2 . 2 . Overview of Objectives : The displacement recommendations are designed to achieve the following objectives : a ) remove mud , mud solids , rust and others contaminants from the wellbore . b) perform an inflow test under water . c ) clean the well before running the DST string . There are differents objectives that must be met to obtain a successful casing cleaning operation . First , one must choose wash pills that have good mud dissolving properties . Secondly , the velocity of the washing/displacing fluids are of vital importance , this means that the cleaning efficiency of the wash pills are a function of the velocity ; higher velocity , better cleaning . Third , reciprocating the drill pipe during the displacing and cleaning operation will reduce the possibility of mud settling on the drill pipe and casing at the lower side of the well . 2. 3 . Check List for casing cleaning operations : This check list contains a brief description of the design parameters that the casing cleaning procedures are based upon . Mud properties : ( at the suspension ) Mud Type : Density : Plastic Viscosity : Yield point : Gels : % solids :
SBM ( XP07 ) mud . 2.17 (SG) 87 @ 50°C 43 @ 50° C 39 / 70 36 %.
Hydraulic considerations : It’s a critical issue . An optimum flow rate is required to ensure a turbulent flow for each spacer in the annulus . But , the maximum flow rate is limited by the maximum allowable pressure losses supplied by the rig pumps . Then ,the displacement of the SBM ( 2.12 SG ) will be facilitated by circulating an intermediate SBM with 1.60 SG in the hole .Once the well is stabilised with 1.60 SG mud it 6
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will be displaced to fresh water by pumping a sequence of pills ahead of the water to ensure the well is cleaned up as efficiently . Circulation to be performed with well closed in and returns taken through a wide open choke . A SPP schedule will be followed as per well control . Hydraulic calculations are not completed , the present table is to give the range of pressure and the limitation at TD .
TD = 5830 m - TVD = 5688 m
Mud 2.17SG
Mud 1.60 SG
Pore pressure ( 2.05 EMW )
1165 bars
1165 bars
1165 bars
Hydrostatic pressure with Mud or Water Differential pressure / Pore pressure
1222 bars
949 bars
568 bars
+ 57 bars
- 216 bars
- 597 bars
N/A
+ 273 bars
+ 381 bars
+/- 200 bars at 400 l/min
+/- 160 bars at 900 l/min
U-tube effect to displace the fluid P-additional to U-tube effect to displace the fluid
Water 1.00 SG
Pipe movement : Reciprocating and Rotation ( 20 RPM ) .. Use of Rig pumps will be limited to the maximum pressure allowable and the final displacement will be done with Halliburton cementing pump. 2 . 4 Displacement Procedure : Once the well has been displaced to 1.60 SG mud with an acceptable flow check . 2.4.1
Flushing of surface equipment : ( Key of success during clean up )
Prior to start casing cleaning operation , ensure that all mud pumps ( suction lines ) , relevant circulating lines , stand pipe manifold , RISER and mud return system ( degasser , trip tank , flow line , gumbo box and mud ditch ) are completely clear of mud by using seawater with drilling Detergent / Washers or high pressure water guns as required Typical Cleaning Procedure for BOP area : Wellhead / BOP / Riser : • • • •
Run wash tool into the wellhead / BOP / Riser to +/- 60 m . Run Well patroller 2 stands below wash tool. Drain BOP and riser prior jetting BOP cavities and wellhead with freash water / Baraclean ( rig wash ). Jet BOP’s and riser . Pull back until rams are across the drillpipe and function pipe rams twice . Do not function shear rams . 7
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• • •
Run in hole and jet BOP’s and riser . Run +/- 60 m and displace to filtered fresh water . Pull wash tool assembly out of hole . Check Well patroller for debris .
2.4.2
Condition the Mud ( at 195°C BHST )
The Intermediate drilling mud will be conditioned after displacing. When circulation will be established , adjust mud rheology to be sure to remove and disperse solids from the casing wall , tanks , and drill pipe into the mud . • - Tubing string downhole . • - Establish circulation while reciprocating the tubing . Circulate the drilling mud through available solids control equipment to remove large contaminants . • - Reduce the PV and YP to minimum acceptable levels .( See Fann70 prediction ) 2 . 4 .3
Displacement Objectives :
Hydraulic parameters will be adjusted after simulations with final rheology and tubing string configuration . Spacer should cover a minimum of 200 m in the annulus at its widest diameter , and must be more viscous than the drilling mud . Chemical Washers , provide chemical cleaning action in combination with mechanical scraping action , contain surfactants or solvents to remove inorganic contaminants . Pumping Sequence No 1 and SAFETY A - Pump XP07 fluid pill - 8 m³ ( 0.77 SG) B - Displace mud by pumping a High Viscous sweep ( 25 m3 ) , using XC Polymer as a primary viscosifier + 10 % of RX-03 Flocculant ( SG = 1.30 ) C - Pump Sea Water in the well STOP ONCE the Sea water is return to the surface SAFETY : - At this Stage after the first bottom up with drill water a WELL OBSERVATION MUST BE DONE .Duration 6 hours Note :During this time the Rig installation will be cleaned ,( clean up preparation logistic , supply boat ) A close monitoring of volume pit ( Trip tank ) levels is required . - In case of any doubt on pit volume , flowing back etc… ,the situation must be evaluated . The Rig pump + the Dowell Unit must be ready to pump kill mud.
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Pumping Sequence No2 - SAFETY A - Displace Sea water by pumping a High Viscous sweep ( 25 m3 or 157 bbl ) , using viscosifier ( SG = 1.05 ) + 10 % of RX-03 B - Pump Chemical washers : “Final Clean up “ at maxi Flow rate ( 1200 /1500 l/min ) MFCT in closed Position ( allowing flow into liner ) B1 - Sea water + 6% of RX-16/1or RX-6BD Water wetting detergent ( 15/20 m³ ) B2 - Sea water + 3% of RX-03 (5 m3 ) Flocculant B3 - Sea Water pill ( 20 m3 ) B4 - Sea water + 6% of RX-16/1 or RX –6BD Water wetting detergent ( 30 m³ ) B5 - Sea water + 3% of RX-03 ( 30 m3 ) Operate MFCT to allow flow into 9 7/8” casing C - Sea water until the well is clean DO NOT STOP ONCE SPACERS ARE IN THE WELL .( segregation in the well ) SAFETY : - At this Stage after the first bottom up with Sea water a WELL OBSERVATION MUST BE DONE . A close monitoring of volume pit levels is required .{ HORNER Plot } - In case of any doubt on pit volume , flowing back etc… , the situation must be evaluated . The Rig pump + the Dowell Unit must be ready to pump kill mud. After this flow check if levels are stable , the wellbore will be displaced with 1,00 SG drill water treated with ! 1.4 kg/m³ BARASCAV L ( Ammonium Bisulphite ) ! + 1 kg/m³ of Biocide until clean return . ! + 3 to 5 kgs/ m³ of Baracor 450 corrosion inhibitor . ! + 5 kgs/ m³ of Sodium Bicarbonate ( galvanic coupling ). 3.
Inflow test :
A special care should be taken during this Inflow Test ( see SHELL Experience on Commander well ) Duration for the final Flow check . { HORNER Plot } Temperature Effect ( see Enertech simulation ) The cementing unit shall be used for the well killing
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4.
Chemicals Preparation :
Due to the logistic problems and the large volume involved during this operation a special effort must be done to reduce the Pollution to the sea . 4.1 Filtration Unit : POD unit with filters - Specification NTU = < 30 / 35 - Solids particules < 0.03% 5.
Recommended safety stock
Bulk material - Dykerhoff G +S - Baryte
50 tons 250 tons .
Material in sacks or drums : - Baracarb ( Fine & Medium ) 10 tons - CaCL2 brine 100 m³ - Drilling Detergent 1600 liters ( Rig Wash ) - LCM ( Fine/Medium ) 10 tons - Biocide 500 liters - Baracor 450 200 liters - Ammonium Bisulphite 500 Kgs - Sodium Bicarbonate 500 Kgs - All chemicals necessary to built 100 m³ of SBM . - Roamex Chemicals RX-03 - RX - 16/1 – 06 BD ( 100 % of back up volume ) Cement Additives for squeeze of cement . 6.
Balance Volume and Chemicals :
Hole Volume Annulus String
: 209 m³ : 136.8 m³ : 49.26 m³
Active Mud and Kill Mud Intermediate Mud or CaCl2/CaBr2 brine Drill Water
300 m³ @ 2.15 SG 150 m³ @ 1.60 SG 750 m³ ( stock on board )
7.
Environment Rig cleanliness .
In order to keep the working environment on the rig clean and safe , it will be useful to use a rig detergent with a steam cleaner or high pressure water cleaner. Chemicals allowed to be discharged to the sea : Check MSDS for each chemicals . All the contaminated spacer or water must be recovered in a dedicated pit and send to shore . 10
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8.3
Inflow Test – Horner Plot : The horner plot technique can be used as a confirmation that we are in a steady state system i.e. the inflow is only being caused by thermal expansion . The use of the “ Horner Plot “ is based on a reservoir analysis build up technique where the pressure is plotted against horner time Ln ( T +dt ) / dt and the straight line portion of the plotted points indicates when we are in a steady state phase ( reservoir effects only ) with the extrapolation of the line tending towards initial reservoir pressure . In our specific case we can treat the well as a reservoir and modify this technique such that we are plotting flowrate against horner time , with the straight line portion indicating a steady state condition . Added to this is that extrapolation of the line should trend to zero , thus indicating that only thermal expansion is taking place within the well . Using this plot will give us a fairly quick indication that no abnormal effects are occuring and it will also give us a high degree of confidence in our inflow test . The flowing time T that should be used is : The cumulative volume flowed during the final circulation The average pump rate during the final circulation .
See Example attached .
11
inflow~3.xls
Liner lap inflow test Production Casing displaced to 1.00 SG drill. water Start time : 11:00 T= 1120 mins
Well : 22/30c-G4 Date : 30/12/98
Time (min) Flow (ml/min) Flow (USG/hr) Cum. Total (bbls) Ln((dT+T)/dT) Flow (l/min) 20 7500 118.9 0.23589 4.0431 7.5 40 6666 105.7 0.44556 3.3673 6.7 60 6666 105.7 0.65522 2.9789 6.7 80 6000 95.1 0.84393 2.7081 6.0 100 5000 79.3 1.00120 2.5014 5.0 120 5000 79.3 1.15846 2.3354 5.0 140 4615 73.2 1.30361 2.1972 4.6 160 4615 73.2 1.44876 2.0794 4.6 180 4286 67.9 1.58357 1.9772 4.3 200 4286 67.9 1.71837 1.8871 4.3 220 3750 59.4 1.83632 1.8068 3.8 240 3750 59.4 1.95427 1.7346 3.8 260 3333 52.8 2.05910 1.6692 3.3 280 3333 52.8 2.16393 1.6094 3.3 300 3333 52.8 2.26876 1.5546 3.3 320 3158 50.1 2.36809 1.5041 3.2 340 3158 50.1 2.46742 1.4572 3.2 360 3000 47.6 2.56177 1.4137 3.0 380 2875 45.6 2.65220 1.3730 2.9 400 2727 43.2 2.73797 1.3350 2.7 420 2500 39.6 2.81660 1.2993 2.5 440 2400 38.0 2.89209 1.2657 2.4 460 2308 36.6 2.96468 1.2340 2.3 480 2222 35.2 3.03457 1.2040 2.2 500 2143 34.0 3.10197 1.1756 2.1 520 2069 32.8 3.16704 1.1486 2.1 540 1818 28.8 3.22422 1.1230 1.8 560 1935 30.7 3.28509 1.0986 1.9 580 1818 28.8 3.34227 1.0754 1.8 600 1875 29.7 3.40124 1.0531 1.9 620 1818 28.8 3.45842 1.0319 1.8 640 1818 28.8 3.51560 1.0116 1.8 660 1765 28.0 3.57111 0.9921 1.8 680 1667 26.4 3.62355 0.9734 1.7 700 1538 24.4 3.67192 0.9555 1.5 720 1538 24.4 3.72029 0.9383 1.5 740 1463 23.2 3.76631 0.9217 1.5 760 1463 23.2 3.81232 0.9057 1.5 780 1429 22.7 3.85727 0.8903 1.4 800 1429 22.7 3.90221 0.8755 1.4 820 1333 21.1 3.94414 0.8611 1.3 840 1333 21.1 3.98607 0.8473 1.3 860 1224 19.4 4.02456 0.8339 1.2 880 1250 19.8 4.06388 0.8210 1.3 900 1224 19.4 4.10238 0.8085 1.2 920 1200 19.0 4.14012 0.7963 1.2 940 1177 18.7 4.17714 0.7846 1.2 960 1154 18.3 4.21344 0.7732 1.2 980 1132 17.9 4.24904 0.7621 1.1 1000 1091 17.3 4.28336 0.7514 1.1 1020 1071 17.0 4.31704 0.7410 1.1 1040 1071 17.0 4.35073 0.7309 1.1 1060 1000 15.9 4.38218 0.7211 1.0 1080 984 15.6 4.41313 0.7115 1.0 1100 968 15.3 4.44357 0.7022 1.0 1120 952 15.1 4.47352 0.6931 1.0 1140 938 14.9 4.50302 0.6843 0.9 1160 896 14.2 4.53120 0.6758 0.9 1180 896 14.2 4.55938 0.6674 0.9 1200 857 13.6 4.58634 0.6592 0.9 1220 896 14.2 4.61452 0.6513 0.9 1240 845 13.4 4.64110 0.6436 0.8 1260 800 12.7 4.66626 0.6360 0.8 1280 822 13.0 4.69211 0.6286 0.8 1300 789 12.5 4.71693 0.6214 0.8 1320 750 11.9 4.74052 0.6144 0.8 1340 698 11.1 4.76247 0.6075 0.7 1360 833 13.2 4.78867 0.6008 0.8 1380 741 11.7 4.81198 0.5942 0.7 1400 741 11.7 4.83528 0.5878 0.7 1420 625 9.9 4.85493 0.5815 0.6 1440 714 11.3 4.87740 0.5754 0.7
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8.0
7.0
6.0
5.0
4.0
3.0
2.0
1.0
0.0
4.5000
4.0000
3.5000
3.0000
2.5000
2.0000
1.5000
1.0000
0.5000
0.0000
elf exploration U.K. Clean-up Summary Report
b 85F is Version 2.0 8/96
Date :01/05/99
Clean-up Company :
Drilling contractor :
16:20 16:30 16:37 16:40 16:53 17:12 17:21 17:30
Rig :
16:30 16:35 16:40 16:53 17:12 17:19 17:30
06:00 06:00
07:42
RATE
MFCT
2830 3019 1490 1547-1604 1604 1547 3020 3020
open open closed closed closed closed Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open Open closed closed Open Open Open Open Open Open Open
ELGIN
Field : Mud Company :
Well number :
VOLUMES
22/30 C - G5 COMMENTS
NTU of RETURNS
Pit 1
Dump
25
25
N/A
N/A
N/A
Pit 2
Dump
15
40
RX-06BD 6%
Seawater
N/A
N/A
N/A
N/A
Pit 7
Dump
5
45
Rx-03 3%
Seawater
N/A
N/A
N/A
N/A
Slug
Dump
20
65
Seawater
Seawater
N/A
N/A
N/A
N/A
Pit 2
Dump
29
94
RX-06BD 6%
Seawater
N/A
N/A
N/A
N/A
Pit 7
Dump
11
105
Rx-03 3%
Seawater
N/A
N/A
N/A
N/A
Pit 7
Dump
20
125
Rx-03 3%
Seawater
N/A
N/A
N/A
N/A
Slug/Sea chest Dump
Seawater
Seawater
N/A
N/A
N/A
N/A
Slug/Sea chest Dump
Seawater
Hi-vis Rx-03 10%
N/A
N/A
N/A
Sample 1- 17:50
Slug/Sea chest Dump
Seawater
Hi-vis Rx-03 10%
N/A
N/A
N/A
Sample 2- 17:53
Slug/Sea chest Dump
Seawater
Hi-vis Rx-03 10%
N/A
N/A
N/A
Sample 3- 17:56
Slug/Sea chest Dump
Seawater
RX-06BD 6%
N/A
N/A
N/A
Sample 4- 17:59
Slug/Sea chest Dump
Seawater
RX-06BD 6%
N/A
N/A
N/A
Sample 5- 18:01
Slug/Sea chest Dump
Seawater
Rx-03 3%
N/A
N/A
N/A
Sample 6 - 18:02
Slug/Sea chest Dump
Seawater
RX-06BD 6%
N/A
N/A
N/A
Sample 7 - 18:04
Slug/Sea chest Dump
Seawater
RX-06BD 6%
N/A
N/A
N/A
Sample 8 - 18:07
Slug/Sea chest Dump
Seawater
RX-06BD 6%
N/A
N/A
N/A
Sample 9 - 18:09
Slug/Sea chest Dump
Seawater
RX-06BD 6%
N/A
N/A
N/A
Sample 10 - 18:11
Slug/Sea chest Dump
Seawater
Rx-03 3%
N/A
N/A
N/A
Sample 11 - 18:14
Slug/Sea chest Dump
Seawater
Rx-03 3%
N/A
N/A
N/A
Sample 12 - 18:18
Slug/Sea chest Dump
Seawater
Rx-03 3%
N/A
N/A
N/A
Sample 13 - 18:23
Slug/Sea chest Dump
Seawater
Rx-03 3%
N/A
N/A
N/A
Sample 14 - 18:26
Slug/Sea chest Dump
Seawater
Rx-03/ Seawater
N/A
N/A
N/A
Sample 15 - 18:29
Slug/Sea chest Dump
Seawater
Seawater
N/A
N/A
N/A
Sample 16 - 18:33
Slug/Sea chest Dump
Seawater
Seawater
666
N/A
N/A
Sample 17 - 18:38
Slug/Sea chest Dump
Seawater
Seawater
840
N/A
<0.05
Sample 18 - 18:45
Slug/Sea chest Dump
Seawater
Seawater
205
29
<0.02
Sample 19 - 18:55
Slug/Sea chest Dump
Seawater
Seawater
42
10.5
<0.02
Sample 20 - 19:05
Slug/Sea chest Dump
Seawater
Seawater
229
91.5
<0.02
Sample 21 - 19:15
Slug/Sea chest Dump
Seawater
Seawater
Sample 22 - 19:30
Seawater
Seawater
48 42
<0.02
Slug/Sea chest Dump
223 241
<0.02
Sample 23 - 19:45
Slug/Sea chest Dump
Seawater
Seawater
Sample 24 - 20:00
Seawater
Seawater
38 13.7
<0.02
Slug/Sea chest Dump
108 115
<0.02
Sample 25 - 20:15
Slug/Sea chest Dump
Seawater
Seawater
Sample 26 - 20:30
Seawater
Seawater
34 33
<0.02
Slug/Sea chest Dump
123 146
<0.02
Time 22:30
Slug/Sea chest Dump
Seawater
Seawater
Time 00:30
Seawater
Seawater
34.2 31
<0.02
Slug/Sea chest Dump
128 73.4
<0.02
Time 02:30
Slug/Sea chest Dump
Hi-vis Rx-03 10% Seawater
N/A
Seawater
Seawater
Filtered drill water
Seawater
34.8 47.4
Time 04:00
Dump
66.6 83.8
<0.02
Pit 7/8/2/1
<0.02
Time 06:30
Pit 7/8/2/1
Dump
Filtered drill water
Seawater
91.3
39.4
<0.02
Time 07:00
Pit 7/8/2/1
Dump
Filtered drill water
Seawater
290
220
<0.02
Time 07:10
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
116
69
<0.02
Time 07:15
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
196
143
<0.02
Time 07:22
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
99.4
65
<0.02
Time 07:26
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
77.4
48.6
<0.02
Time 07:30
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
30.6
14
<0.02
Time 07:35
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
38.6
16
<0.02
Time 07:40
Pit 7/8/2/1
Dump
Filtered drill water Filtered drill water
29
15
<0.02
Time 07:42
Casing Size
Casing Weight
Lenght
Base Fluid
Volume
9 7/8"
66.9 pptf
4,895 m
Eqpt. Description
Type
m³
Type
Additives Concentration
7"
42.7 pptf
628 m
Hi-vis Seawater Seawater
25 42 6
Rx-03 RX-06BD Rx-03
10% 6% 3%
Density
Rheology @ 50°C
(SG)
600/300/200/100/6/3
YP 48
5,560 m Geometry 9 7/8" 7"
Volume (m³) 168 13 181
Length 4,895 628 m 0
Comments / Job Summary
The clean-up operation was aided by detailed and thourogh pit and topsides cleaning. This allowed all pills to remain free of contaminants prior to pumping. All pills were pumped on the run and at high rates adding turbulent flow. Pipe rotation was only possible after the operation of the MFCT. Initial pills showed large amounts of solids which reduced in following samples. Sea water samples contained a large amount of rust which was removed with HCL.
ELF supervisors : Phillipe Brossard - Fabian Lemesnager roemex~1.xls,09/07/2000,13:05
Mud Engineers: Stephen Cooper, Philip Leslie, Lee Campbell. Elf Fluids Group - Aberdeen
350.00
Inhibited filtered fresh water returns.
Sea water returns.
300.00 Returns from surface lines
250.00
NTU with out acid NTU with HCl acid Target NTU
200.00
150.00
100.00
50.00
0.00 18:45
20:00
21:30
00:00
03:00
07:10
07:35
22/30c-G5
50
45
40
35
30
25
20
Temperature Out
15
10
5
0 3:51 4:01 4:11 4:21 4:31 4:41 4:51 5:01 5:11 5:21 5:31 5:41 5:51 6:01 6:11 6:21 6:31 6:41 6:51 7:01 7:11 7:21 7:31 7:41 7:51 8:01 8:11 8:21 8:31
Sperry Sun Logging Systems
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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8.4
Well Control – Pipe light scenario during completion of 22/30c-G4 with 1.00SG fluid :
The issue of Well Control with freshwater in the well was raised.It had made a quick review of the position we have at the moment.It was suggested that based around this we can meet and discuss whether we need to make any further contingency plans (unable to strip in, unable to bullhead, access through the drillpipe with DISV and inside BOP, etc.). Recommendations • The section covering Stripping, snubbing, migrating gas, bullheading and top kill (lubrication) should be transferred from the old Well Control Manual (1993) to the Well Control Manual issued in June 1997 (the new manual does not contain this information). This section should be reviewed to ensure it is in line with procedures we would use if we had to perform any of these operations with water in the well in HPHT conditions. • The results listed below should be included in the Completion Programme to make people aware of the limitations of stripping if we have a leak with water in the well. Results / Conclusions • In the event of a gas influx the situation is very different to a kick with SBM in the hole because: - An insignificant volume of gas will dissolve in the water- Water is 1.8 times less compressible than oil - the surface pressure build up will occur more quickly- The gas will migrate rapidly to surface due to the low fluid viscosity (rapid increase in surface pressure as the bubble migratesThe coefficient of thermal expansion of water is 5 times greater than base oil which, without viscosity means the water is very sensitive to the thermal changes. • Given the scenario: -The well is displaced to water -We have the highest formation pressure (2.15SG) giving a shut-in surface pressure of 650 barsThe drillstring is displaced to 2.15 SG mud We will not be able to strip into the well (using the 2 ram method of passing tool joints) if the 5” drillstring is shallower than 2000m MD (upward forces exceed downward forces - pipe-light (Refer to the graph on page 3). • Given a pipe light situation with the drillstring partially in the well the upper portion of the well can be displaced to SBM. .The advantage of this are: - It will allow limited gas percolating through the water to be taken into solution in the SBM (assuming we can displace deep enough to be below the bubble point i.e.; deeper than 1500m). - It will reduce the surface pressure (this does not help us with the pipe light condition for stripping the pipe body as the pressure acting on the area at the base of the drill string remains unchanged) Refer to the drawing below.The disadvantages are: - A potential for fluid inversion with heavy fluid over light fluid- A potential for barite dropout at the fluid interface
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Annular displacem entto heavy m ud w ith the drillstring partially in the w ell Surface pressure reduced 315 Bars
651 bars Tool joint Rams Drillpipe No change in pressure (upward force on Drillpipe body OD) with water or mud above this point Net 44 MT upward force
2.15 SG Drilling Fluid
3100m MD, 2975m TVD RT
943 bars
Depth
Water Gradient
Water Gradient
5923m MD, 5776m TVD RT
566 bars
1217 bars
Pressure
2.15 SG EMW Formation pressure
22/30c-G 4 Pipe LightC ondition (2.15 SG in string -2.15 SG EM W Form P) 200
150
Minimum string depth to strip tool joint. After disp ann to 2.15SG fluid
MT Net String For
100
Minimum string depth to strip pipe body.
50
Force on Pipe OD Tonnes Force on Pipe TJ OD Tonnes 0 0
1000
2000
3000
4000
5000
6000
-50
Minimum string depth to strip tool joint. With 1.00SG in annulus -100
-150 MD M
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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In the graph above the negative Net string force indicates a pipe light condition Well Control with Freshwater in the well Our primary approach to this issue is to ensure there is no influx by:• Make-up the 10 3/4”, 9 7/8” and 7” casing connections using torque turn equipment with quality control review of the make-up. • Review the quality of the 7” cementation and the cement bond log. • To have set and positively pressure tested a 7” liner top packer. • Ensure the well is stable with freshwater prior to pulling the displacement string. (To do this we plan to underbalance the well in 2 stages on 22/30c-G4; firstly SBM at 1.60 SG and then to freshwater. We will allow the well temperature profile to return to undisturbed (+/-24 hours) before pulling the displacement string). Our second approach is to have a contingency plan prepared should an influx occur. • The well can be circulated back to a kill weight fluid should the well fail during the initial displacement to underbalanced fluid (drillpipe on bottom). • If the well flows while we are out of or partially out of the well we will strip in to bottom or as deep as we can get. Should there be a pipe light situation we would not be able to strip further and have to stop with the well shut-in on the rams. This attached graph identifies the period in which we would be unable to strip into 22/30c-G4 if there is an influx with water in the well. Calculation of forces The forces taken into account for this calculation are: " Pipe weight in air (5” drillpipe 19.5ppf nominal, 22.6ppf with tool joint) " Hydrostatic pressure of fluid inside the drill string acting on the pipe body ID cross sectional area " Weight of HWDP (40 joints 5” HWDP at 50ppf) - if they are available and can be picked up. # Hydrostatic pressure and shut-in well pressure acting on the cross sectional area of the pipe body OD # Shut-in well pressure at surface acting on the tool joint cross sectional area (as the tool joint is stripped through the BOP) This force is excluded when the tool joints are passed through the BOP by alternately opening and closing 2 rams and balancing the pressure. # Friction while stripping through the BOP (Pipe friction through annular used is 5MT on pipe body and 14MT on tool joint - based on Franklin annular stripping data) There are no safety margins taken into account in the calculations.
Sensitivity graphs on the next 2 pages The following graphs are sensitivities assuming different formation pressures and fluid densities inside the drillpipe:
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ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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2.15SG - pressure from the overpressured shales in the transition zone 22/30c-G 4 P ip e L ig h t C o n d itio n (1.00 S G in strin g - 2.15 S G E M W F o rm P )
200
MT Net String For
150 100 Forc e on Pipe OD Tonnes
50 0 0
1000
2000
3000
4000
5000
6000
Forc e on Pipe TJ OD Tonnes
-50
-100 -150
M D M
2.01 SG based on RFT data from the Fulmar reservoir 22/30c-G 4 P ip e L ig h t C o n d itio n (2.15 S G in strin g - 2.01 S G E M W F o rm P ) 200 MT Net String For
150 100 Forc e on Pipe OD Tonnes
50 0 -50
0
2000
4000
6000
-100 -150 M D M
15
Forc e on Pipe TJ OD Tonnes
Volume 1
ELGIN / FRANKLIN HP/HT BEST PRACTICES & GUIDELINES DRILLING FLUID ,CEMENTING & HYDRAULIC REVISION 00
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2.01 SG based on RFT data from the Fulmar reservoir
22/30c-G 4 P ip e L ig h t C o n d itio n (1.00 S G in strin g - 2.01 S G E M W F o rm P )
200
MT Net String For
150 100 Forc e on Pipe OD Tonnes
50 0 0
1000
2000
3000
4000
5000
-50
-100 -150
M D M
16
6000
Forc e on Pipe TJ OD Tonnes