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SPE Managed Pressure Drilling


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SPE 2006 -2007 Distinguished Lecturer Series

Managed Pressure Drilling g g
A “new” way of looking at drilling hydraulics… …Overcoming conventional drilling challenges

Don M. Hannegan, P.E. , g g g Director, Emerging Technologies Controlled Pressure Drilling & Testing Services Weatherford International Ltd.

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Generic definition

Managed Pressure Drilling
MPD is an advanced form of primary well control typically employing a closed, pressurizable fluid system th t allows greater and more precise t that ll t d i control of the wellbore pressure profile than mud weight and mud pump rate adjustments alone. g p p j As opposed to a conventional open -to-atmosphere returns system, MPD enables the circulating fluids system to be viewed as a pressure vessel. Influx not invited - Conventional Well Control

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Pressure Vessel?
RCD

Enabling Tools ?Rotating Control Device ?Drill String Floats ?Dedicated Choke
Automatic Choke Preferred for Several Variations of Managed Pressure Drilling
? 2006 Weatherford. All rights reserved.

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New way of looking at the hydraulics of drilling?
? Well, maybe to the rest of the world, but not so new in the Arkoma Basin – MPD was being p g practiced decades ago g ? A rotating control device is required to practice MPD ? Manufactured in Fort Smith since 1968, availability of the tool facilitated: – Drilling with compressible fluids (gas, air, mist, foam) – Underbalanced Drilling – And over time, “necessity being the mother of invention”, spawned other uses – I e “I’m drilling conventionally but can’t get through this zone with the mud I’ve I.e., I m can t I ve got in the hole unless I make jointed pipe connections with casing backpressure.” ? Those “other uses” identified as a technology within themselves in 2003 and labeled Managed Pressure Drilling – Introduced to offshore drilling decision-makers – And to land programs globally… ? Where MPD is being seen and accepted as “new and innovative”

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Connecting the dots – An extension of logical reasoning
1. U.S. Rig Count 1750, 600 RCD’s on locations – majority of land programs drilling at least one section with a closed mud return system on rig floor 2. 2 Of those with closed systems more than half are MPD systems, ? ? ? Dealing with “drilling trouble zones” Shorten the number of days from spud to TD Drill otherwise un-drillable prospects

3. Because MPD addresses NPT - Value to offshore operations much greater 4. Does not invite influx of hydrocarbons but one is tooled up to better deal with any incidental to the operation with less interruption to the drilling program 5. Equipment “kit” for all Variations of MPD fits aboard most offshore rigs 6. Drilling offshore with a closed mud returns system vs. open-to-atmosphere drilling or bell nipples is making uniquely good sense on many fronts 7. Conventional Well Control principals apply 8. UBD-type preplanning, training, discipline applicable to several Variations 9. “Real time Well Control” mentality also important to several Variations y p 10. Onshore applications not capturing the full potential of the technology
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Formal Definition (IADC developed – SPE adopted)
“MPD is an adaptive drilling process used to more precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic g y pressure profile accordingly. Technical Notes 1. MPD processes employ a collection of tools and techniques which may mitigate the risks and costs associated with drilling wells that have narrow downhole environment limits, by proactively managing the annular hydraulic pressure profile. MPD may include control of backpressure, fluid density, fluid rheology, backpressure density rheology annular fluid level, circulating friction, and hole geometry, or combinations thereof. MPD may allow faster corrective action to deal with observed pressure variations. The ability to dynamically control annular pressures facilitates drilling of what might otherwise be economically unattainable prospects. MPD techniques may be used to avoid formation influx. Any flow incidental to the operation will be safely contained using an appropriate process.” process

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3.

4.

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“Controlled Pressure Drilling” Family of Technologies
Common Equipment RCD NRV’s Choke

RCD NRV Choke

View circulating fluids system as one would a pressure vessel
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MPD

“More Productive Drilling” - “Make Problems Disappear”

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Problem Incidents -- GOM Shelf Gas Wells
Wellbores Drilled 1993-- 2002; Water Depth = <600 feet
Impact of Trouble Time
Drill Days Lost to Trouble y Time ? 22% of 7,680 total drill days from spud date to date TD was reached Trouble Time Cost Impact – GoM Sh lf G W llb G M Shelf Gas Wellbores ? Deep wells average dry-hole cost per foot = $444. Average impact = $98 ? ‘Shallow well average dryhole cost per foot = $291. Average Impact = $ g p $71

More precise wellbore pressure management can address a significant amount of the NPT

22% of total drill days lost to NPT

Source James K Dodson Company Study
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Cost implications of NPT
Ultra-Deep GOM Well Cost ~60% More Than AFE
$MM
10

$20
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$40

$60

$80

$100

$120

Ave. AFE - $44MM
Ave. AFE - $44MM Ave. Cost - $71MM
Pre-drill AFE Actual Cost

TD 1000’s Ft. BML D, F

16 18 20 22 24 26 28

ConocoPhillips DEA Presentation, 1st Quarter 2004
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Categories of MPD
? Reactive – Tooled up to more efficiently react to downhole p y surprises. (Common to U.S. land programs, using surface backpressure to adjust EMW, enhance well control, etc.) ? Proactive – Fluids and Casing programs designed, from the start, to drill with ability to: – Adjust EBHP/EMW with minimum interruptions to drilling ahead – Achieve a deeper open hole p p – Lowest hanging fruit when practiced onshore – Greatest savings when p g practiced offshore

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Variations of MPD
? PMCD (Pressurized Mud Cap Drilling) – Offset wells have experienced total or near total losses p ? CBHP (Constant Bottomhole Pressure) – Offset wells have experienced narrow margins, kick loss scenarios, ballooning, breathing high ECD scenarios ballooning “breathing”, “high ECD”, wellbore instability ? HSE (Returns Flow Control) – Closed vs. Open-to-atmosphere mud returns at rig floor ? RC (Reverse Circulation) ? DG (Dual Gradient, several methods) – Li ht fluids or solids injection i t casing or marine riser Light fl id lid i j ti into i i i – Riserless example – Demo 2000 Deepwater RMR Field Trials JIP

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MPD – The Value Proposition
MPD Method
Value Proposition

MPD as a Solution to Real Drilling Challenges

CBHP (Constant Bottom Hole Pressure) )

PMCD (Pressurized Mud Cap Drilling) g)

DG (Dual Gradient)

HSE (Health, Safety, Environment) )

Drill "Undrillable" Ultra-tight Pore/Frac Pressure gradients Drill "Undrillable" Vuggy/Fractured carbonates where OB circulation is impossible Drill to target depth in wells with high insitu stresses. Extend the Reach of ERD Wells Increase ROP - drilling closer to balanced. Increase ROP - drill throuh HP LV nuisance gas zones. Reduce Number of Loss/Kick Occurances Reduce Time Spent Dealing with Well Control Events. Detect kicks earlier. Reduce pressure cycles that cause fatigue-related borehole instability. Reduce severe overbalanced pressure induced borehole instability. Reduce open hole exposure-time induced borehole instability. Reduce mud costs. Set casing deeper. Reduce number of casing strings. Reduce required rig size. Trip faster in HPHT environments environments. Remove H2S Hazard from Rig Floor Remove HPHT Hazard from Rig Floor Positive Fluid Containment at Surface in Marine or other Environmentally Sensitive Locations

Drill to the target…

….while saving money

…and improving safety.
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Key tools for most Variations of MPD
? Rotating Control Device – Floating Rigs (wave heave) – External Riser RCD – S b Subsea RCD – Internal Riser RCD (IRRCH) - Fixed Rigs (no wave heave) – Passive & Active annular seal design “land” models – Marine Diverter Converter RCD – Bell Nipple Insert RCD – IRRCH (in marine diverter or surface annular) ? NRV’s (Wireline Retrievable is an option worth considering) ? Choke Options (dedicated recommended, except perhaps for HSE Variation) – Manual – Semi-automatic – PC Controlled Automatic

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RCD’s are Key MPD Enablers
? Passive annular seal design shown ? 7/8-in. interference when new ? High pressure capable models have redundant stripper rubbers on a common inner race of the bearing assembly y ? Requires no external-to-tool source of energy to function g p ? Higher the differential pressure, tighter the annular seal ? Does not require a dedicated technician ? This design is most commonly used on MPD applications ? Best rubber performance ? RCD friendly drill string ? Good stack alignment
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API 16 RCD

For Rigs with little or no wave heave
“Passive and active annulus seal designs, designs single or redundant barrier, low or high pressure Capable RCD’s
Marine Diverter Converter RCD – converts typical marine diverter to rotating diverter, also 2nd annular BOP.

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Bell Nipple Insert RCD
?Single Stripper Rubber - 500 psi dynamic ? DNV Certified, COP Norway, Ekofisk
? Self Lubricated Bearing Assembly ? No hose connections required ? Remote latching, unlatching ? 8.75” I.D. for large Tool Joint O.D.’s

No Wave Heave

?Dual Stripper Rubber – 5000/2500 psi i
?Requires lubrication & coolant hose connections to remove heat from thrust and radial bearings when drilling under high differential pressure conditions
? 2006 Weatherford. All rights reserved.

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5000 psi static/2500 psi dynamic Bell Nipple RCD
Bearing Assembly

Bottom Stripper Rubber

Remote Operated Hydraulic Latch

Upper Marine Riser Seal Area pp

Flowline Outlets

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M7800 on Field Trials, Pemex HT/HP well

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External Riser RCD for Floating Rigs
All Variations of MPD - PMCD, CBHP, HSE, DG, RC
PMCD Shown
Model 7100 – 2500psi rated Rotating Control Device 6” HCR 6” Line for circulating well to Flow Line

2” Fill-up Line from Trip Tank Pump 4” HCR 4” PMCD Line from Mud Pump

4” Kill Line to Choke Manifold 4” HCR

Riser Tensioners support full riser weight and PMCD equipment Riser Slip Joint is used in th i the collapsed position ll d iti

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Other Tools
? Downhole Casing Isolation Valve (Downhole Deployment Valve) ? Nitrogen Production Unit ? ECD Reduction Tool ? Real time Pressure & Flow Rate Monitoring ? UBD technology & mentality (except for the HSE Variation) – Training – Planning, HazId/HazOp’s – Project Management – Real time decision-making ? Continuous Circulating “Valve” or “System” Valve System ? ECD Reduction Tool
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Conventional vs. Constant Bottomhole Pressure Variation

Uniquely Applicable – Narrow, Inconsistent, or Unknown P/F Margins
? 2005 Weatherford. All rights reserved.

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Conventional Drilling - GoM
0 500 1,000 1,500 2,000 Depth (ft) TVD Sub bSea 2,500 3,000 3,500 4,000 4 000 4,500 5,000 5,500

Open Mud Returns System

26" 1,300'

25 mud changes to TD

11-3/4 2,740 11-3/4" 2 740'

7-5/8" 5,001'

Can t Can’t drill in narrow margins without exceeding fracture gradient Classic Kick-Loss scenario

5-1/2" 5,930'

6,000 8.0

9.0

10.0

11.0

12.0

13.0

14.0

15.0 Frac Sh l F Shale

16.0

17.0

18.0

EMW (ppg) Pore Pressure C P P Conv Pl Planned MW S d d F Frac Sand FIT - OFFSETS LOT in Design Conv EMW (MW + ECD)
? 2006 Weatherford. All rights reserved.

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MPD Example - GoM

Proactive CBHP Variation

EMW = MWHH + ΔAFPCIRC + ΔBPSURFACE C C SU C

Only three mud density changes to TD

Surface backpressure applied during connections No losses upon resuming circulation

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Onshore Value Case - Proactive CBHP
Wild River/Cecilia Drilling Performance
$1,600,000 30

Increase ROP, Reduce NPT (kick-loss scenarios)
$1,400,000 25

20 $1,000,000

$800,000

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$600,000 10 $400,000 $400 000 5 $200,000

$0 2002 CFS* 2003 DFS 2004

0

D Days from Spud..
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C Cost from Spud.. m

$1,200,000

Offshore Value Case – Proactive CBHP
CBHP Managed Pressure Drilling Reduces Drilling Time by 83%, Provides Operational Savings of $1 Million
Location: Formations: Depth: Pore pressure: Well type: Hole size: No. of wells: Chuc 172, southwest Gulf of Mexico Medium Cretaceous, Lower Terciary 12,457 ft (3,797 m) 2,844 PSI (196 bar) Deviated 8-1/2 in. 1

Objectives
? Drill the well without the total circulation loss experienced in a previous well. ? Drill the well in less time than the 30 days allowed.

Results
? The well was drilled with no loss of circulation, using the constant bottomhole pressure (CBHP) variant of managed pressure drilling (MPD). ? Drilling time was reduced from 30 days to 5 days (83 percent).

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PMCD on Fixed Rigs

? Photo – Jackup for Chevron p Angola, drilling conventionally ? Upon encountering severe losses, RCD Bearing & Stripper Rubber Assembly is pp y installed, mud cap spotted… ? …Drill ahead with seawater & no returns

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External Riser RCD w/Subsea BOP
? Riser telescoping slip joint locked, seals pressured 500 psi riser system i i t ? X-over spool connect to p p proprietary flange of slip j y g p joint Inner Barrel ? Note importance of hoses clearing riser tensioner cables in catenaries swing ? Taller spool or swivel flange may be required on drill ships to accommodate changes in heading

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External Riser RCD w/Surface BOP
Pressure containment capability usually determined by that of flexible flowlines
? R Remote operated valves on manifolds? d l if ld ? ? Length of hoses to compensate for heave and reach hard piping? ? Number and size of hoses to accommodate returns rate and desired redundancy? ? Annular BOP size? ? Drill pipe size and tool joint O.D.? ? Overpressure relief device to diverter dump line? ? Hose flush by-pass to prevent cutting settling when not circulating for extended periods? ? Secondary spills containment device? ? Will drill string stabilizers be used? ? Maximum temperature of returns? ? Moored Semi or DP Drillship?
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PMCD & CBHP MPD - Floater w/ Surface BOP
? Santos Indonesia ? PMCD - Drilling with seawater and no returns to deal with near total losses in cavernous voids ? After casing is set below that trouble zone, CBHP with mud in deeper open hole to deal with narrow margins

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Asia Pacific Region MPD Activity – June 2006
MPD Type HSE HSE/CBHP PMCD PMCD PMCD PMCD HSE CHBP PMCD PMCD PMCD PMCD-DDV Country Vietnam Vietnam Malaysia Malaysia Malaysia Malaysia y Malaysia Malaysia Indonesia Indonesia Indonesia I d i Indonesia Operator Cuu Long (ConocoPhillips) JVPC (Japan Vietnam) Sarawak Shell Sarawak Shell Sarawak Shell Sarawak Shell Petronas Carigali Petronas Carigali Santos KNOC KNOC Pearl Oil Project Duration 5 year program 6 month program 3 wells 8 wells on 3 fields 2 wells 2 wells 1 well 1 well 11 wells 1 well 5 + 2 wells ll 4 wells Formation Type Fractured Granite Basement Fractured Granite Basement Carbonate Carbonate Carbonate Carbonate Fractured Schist Basement Fractured Schist Basement Carbonate Carbonate Carbonate C b t Carbonate Rig Type Jack Up GALVESTON KEY & ADRIATIC 11 Jack Up TRIDENT 9 Semi-Submersible STENA CLYDE Semi Tender WEST ALLIANCE Semi-Submersible OCEAN EPOCH Jack Up DEEP DRILLER 2 Jack Up ENSCO 52 Jack Up ENSCO 52 Semi-Submersible SEDCO 601 Semi-Submersible SEDCO 601 Drillship p FRONTIER DUCHESS Jack Up SHELF EXPLORER
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Asia Pacific MPD Activity to-date (March 2007)
? 84 drilling programs ? F From all t ll types of rigs; l d j k f i land, jackup, platform, moored l tf d semi-submersibles, dynamically positioned drillships ? Variations practiced safely and with good results – HSE – PMCD – CBHP ? 13 operator companies ? 11 otherwise un drillable wells >recoverable assets un-drillable wells,
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Riserless Dual Gradient - Demo 2000 Deepwater Riserless Mud Recovery JIP

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Integrated Riserless Top Hole Drilling Package

Subsea Rotating Control Device w/ Guide Funnel

ROV Hose connection Class 4 Cl Torque Tool bucket

AGR Norway Suction Module

SMO Running/Retrieving/Testing Sub Vetco E H-4 Connector

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Conclusion
? The challenging hydraulics of the world’s remaining prospects indicate MPD will evolve to become a key enabling technology. ? Adds technical, economic and HSE viability. ? Increases recoverable assets. ? Step-change technology. ? Synergistic with DwC and several other emerging technologies. ? Following U.S. example, onshore MPD is growing globally. ? Proactive MPD is lowest hanging fruit for U.S. land operations ? All “first adopters” of MPD offshore plan future wells. ? A candidate technology to deal with the Boyles Law challenges of gy y g drilling for commercial quantities of methane hydrates
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