controlled pressure drilling

8/7/2019 Controlled Pressure Drilling

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A better way to drillControlled Pressure DrillingDecember 06, 2007

Presented by JOSE DANILO MORALES

Drilling Hazard MitigationControlled P ressure DrillingCPD


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Hazards Causing Non-productive Time (NPT)

Conventional Drilling Operation

Hazard Non-Productive Time (NPT)

Tight Hole Conditions Reduced ROP, mechanically stuck pipe, LIH,sidetrack or abandon well

Directional Deviation Pull back, set whipstock or cement, sidetrack

Well Control Reduced ROP, HSE concern

Hard Formations Reduced ROP

Wellbore Ballooning Uncertain flow conditions lead to multiple wellcontrol events

Lost Circulation Differential sticking, LIH, cementing time, sidetrackor abandon well

Hole Cleaning Reduced ROP, stuck pipe, jarring time or LIH,cementing time, sidetrack or abandon well

Equipment and/or Tool Failure Reduced effective ROP

Reservoir Impairment Loss of well, reduced reservoir productivity andultimate recovery

Excessive Mud Weight Reduced ROP

Nuisance Gas Well control

H2S Well control


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CPD Drilling Operation

Hazard Non-productive Time (NPT)

Tight Hole Conditions Reduced ROP, mechanically stuck pipe, LIH,sidetrack or abandon well

Directional Deviation Pull back, set whipstock or cement, sidetrack

Well Control Reduced ROP, HSE concern

Hard Formations Reduced ROP

Wellbore Ballooning Uncertain flow conditions lead to multiple wellcontrol events

Lost Circulation Differential sticking, LIH, cementing time, sidetrackor abandon well

Hole Cleaning Reduced ROP, stuck pipe, jarring time or LIH,cementing time, sidetrack or abandon well

Equipment and/or Tool Failure Reduced effective ROP

Reservoir Impairment Loss of well, reduced reservoir productivity andultimate recovery

Excessive Mud Weight Reduced ROP

Nuisance Gas Well control

H2S Well control

CPD Optimization Mitigates Hazards


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Redefined Time to Drill Well

DrillingHazards

Perfect Well TimeInvisible Lost

TimeConventional Drilling

NPT

Conventional Well

Time to drill a wellwithout any lost time

Lost ROP intrinsic toweight drilling fluid

Unplanneddrilling events

Lost time due tounplanned events


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Redefined Time to Drill Well

DrillingHazards

Perfect Well TimeInvisible Lost

TimeConventional Drilling

NPT

Technical Limit

CPD RedefinesNormal Well Times

CPD Can Remove

Removable TimeConventional Normal

Well Time

Conventional Well


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Controlled Pressure Drilling

(CPD) Wheel


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What is Underbalanced Drilling?

Underbalanced reservoir drilling is defined by the IADC UBO committee as:

A drilling activity employing appropriate equipment and controls wherethe pressure exerted in the wellbore is less than the porepressure in any part of the exposed formations with the intention ofbringing formation fluids to the surface.

The hydrostatic head of the fluid may naturally be less than theformation pressure or it can be induced.

The induced state may be created by adding natural gas, nitrogen or air

to the liquid phase of the drilling fluid.

Whether the underbalanced status is induced or natural, the result maybe an influx of formation fluids which must be circulated from the well

and controlled at surface.

intentionally


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Underbalanced Drilling

Underbalanced Drilling P reservoir > P bottomhole = P hydrostatic + P friction + P surface


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Managed Pressure Drilling

Managed Pressure Drilling is an adaptive drilling process used tomore precisely control the annular pressure profile throughout the

wellbore.

The objectives are to ascertain the downhole pressure environmentlimits and to manage the annular hydraulic pressure profile

accordingly.

It means that we control the annular pressure profile in such a way

that we balance the well at all times


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An adaptive drilling process used to precisely control the annular pressureprofile throughout the wellbore. The objectives are to ascertain thedownhole pressure environment limits and to manage the annular hydraulicpressure profile accordingly.

MPD is intended of formation fluids to thesurface. Any flow incidental to the operation will be safely contained usingan appropriate process.

Technical Notes

MPD process employs a collection of tools and techniques which may mitigate the risksand costs associated with drilling wells that have narrow downhole environmentallimits

MPD may include control of back pressure, fluid density, fluid rheology, annular fluidlevel, circulating friction, and hole geometry, or combinations thereof.

MPD may allow faster corrective action to deal with observed pressure variations. Theability to dynamically control annular pressures facilitates drilling of what mightotherwise be economically unattainable prospects.

to avoid continuous influx



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Reactive or Contingency MPD

Tool up with closed & pressurizable returns system

The technique is effectively on Stand-by as enhanced form of wellcontrol to manage unexpected pressures.

Attempt drilling with conventional casing & fluids program

Apply backpressure to control kicks, keep drilling when circulating out,e.g., drill through kicks, reduce drilling flat time

Enhanced HSE (required by some underwriters)

Proactive MPD

Design fluids program around ability to apply backpressure, e.g.,

nearer-balanced than conventional Design casing program (deeper set points, maybe eliminate a size)

The technique is used to its maximum effectiveness to mitigate a widerange of drilling hazards.


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The goal of managedpressure drilling (MPD)is to use a closed andpressurizable mud-

return system tocontrol bottomholepressure (BHP) in away that eliminates

many of the drilling andwellbore stability issues

that are inherent toconventional drilling

Pressurized mud-cap. Mitigate extreme losses andreduce associate NPT when drilling highly depleted zones,avoiding well control issues resulting from the inability tomaintain a full column of mud in the annulus

Constant bottomhole pressure MPD reduces NPT andenables fewer and deeper casing strings when pore- to

fracture-pressure gradient windows are narrow,

Dual gradient MPD enables total well depth in the righthole size in deep-well and deepwater drilling.

Returns-flow-control (HSE) MPD reduces risk topersonnel and the environment from drilling fluids and well

control incidents.

PMCD

CBHP

DG

HSE

Proactive MPD Variants


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Managed Pressure Drilling P reservoir = P bottomhole = P hydrostatic + P friction + P surface


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Performance Drilling

This is normally air drilling technique to increase penetration rate.

In Air Drilling the bottomhole pressure is as low as possible toincrease drilling performance.

The objective of Air Drilling is to reduce the drilling costs by drillingfaster. This is normally achieved by using gas or air as a circulationmedium. Reducing the bottom hole circulation pressure significantly

increases the penetration rate.


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Air Drilling

Air Drilling P formation >>>P bottomhole = P hydrostatic + P friction + P surface


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Semi & Automatic Choke systems

Solid expandables

Drilling with casing

Downhole Isolation Valves

Continuous Circulation Systems

RCH

Emerging Technologies

Alt t th d t t i d i CPD


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Kill the well with heavy weight fluids

Utilize Snubbing Unit to overcome forces

Flow the well to reduce surface pressures and reduce forces

Downhole Isolation Valve

Alternate methods to trip during CPDOperations


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There's no need to kill the well so formation damageis minimized.

Eliminates time required to circulate kill fluid into andthen out of the well

Protect against potential swabbing and kick whiletripping

No fluid loss

Eliminates the need for snubbing operations,enhancing safety

Pipe can be tripped at conventional tripping speeds,reducing rig-time requirements and improvingpersonnel safety.

Allow for installation of long complex assemblies, suchas whipstocks, slotted liners, and expandable sandscreens

Downhole Isolation Valve


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Hole Size 6-1/8Formation James Lime TrendDepth 6,400 TVDPore Pressure 3,400 psi

Well Type Gas Reservoir - Multilateral

Objectives:

Previous wells had to be killed to avoid the cost and risk of snubbing

Isolate the formation and allow for safe and economic means of

tripping the drill string in and out of the well during UBD operation. Minimize rig time and cost associated with loading the hole Improve production rate by preventing formation damage

Results: 19,200 (4 lat.) of 6-1/8 hole drilled through Valve over a period of 14 days

Reduced operators tripping procedure time by an average of 7.75 hrs. per trip (45 -52%)

Valve successfully isolated formation pressure for the three required drillstring tripsand allowed for the subsequent underbalanced installation of tubing completionstring

UBD + Downhole Isolation Valve


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PMCD + Downhole isolation Valve

Formation Fracture LimestoneAnnular pressure 3,400 psiWell Type Wet Gas

Objectives:

Drill safely through formations thattypically cause total loss of circulation.

Reduce Well control incidents Use MPD in tandem with downhole

isolation valve to intersect multipleproductive fractures and handle severe or

total loss of returns while drilling. Run the completion without killing the well Reduce the cost of mud materials


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Results:

The well was drilled, using pressurized mud-cap drilling(PMCD), a variant of MPD. Drilling was able to continue for anadditional 167 ft (51 m) after total loss of circulation began.

Total depth was declared after massive hydrocarbon-producingfractures were intersected.

A maximum of ~3,400 psi was observed in the annulus before Downholeisolation valve was closed for tripping.

Use of the Isolation valve eliminated the need for killing the wellbefore setting the completion string

Use of MPD (PMCD) reduced consumption of lost-circulation material. The volume of drilling mud lost to the formation was estimated at 2,500

bbl before the shift to PMCD was made. This is a fraction of the mud lost

on similar drilling campaigns.

Conveting to a PMCD system generate savings in mud materialsby using aprox. 12.000 bls or water rather than mud.

PMCD + Downhole Isolation Valve


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Costly and challenging from a well control perspective due toinduced lost of circulation and resultant formation influx

Objectives:

Minimize drilling induced formation damageMinimize induced losses and differential sticking. formation integrity wouldbe compromised if 18 ppg MW used in conventionally drilled well.

Integrate DwC and CPD technology to accomplish completion objective.Avoid potential well control problems due to surges form conventionaltripping (condition the well for csg running)

Results:

121 ft of cement and 1,696 ft of new hole and was set at planned depth2,300 ft.

Reduced flat time

Eliminated fluid lost into the formation

Penetration rates were doubled compared with offset wells. CBL showed improved cement bonding over conventionally drilled wells

in field. Eight

UBD + Rotary Drilling With Casing

Casing 5-in., 18 lb/ft, L-80, DwC/CFormation Sand/shaleDistance Depth in: 483 ft MD depth out: 2,300 ft MD (1,817 ft)Well type CO2 Injection Well

Parameters:

Bit 6-3/4 inWOB 6-12 klbsDistance 1,817 ftRPM 80ROP 54 ft/hrFlow 300 gpm (water)

with 450 800 psi

controlled pressure drilling

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