Drilling & Geology 2012 ResourcePres Festningen Long

8/9/2019 Drilling & Geology 2012 ResourcePres Festningen Long

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Drilling & GeologyResource presentation for exercises related to Storvola & Festningen

Kjell Kre FjeldeUiS


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Festningen Exercise

Solve an exercise that is

focusing on elements tobe considered when

constructing a drilling

program Can also be found on

the resource CD


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Festningen exercise

Exercise handed out to each group in

advance

Work with it during the excursion and

afterwards.

Two groups will be selected to present

and go through the assignment fordiscussion (powerpoint presentation)


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Festningen Exercise

In the field you should have focus on:

Which type of layers do we have and whatis the sequence ? (i.e draw thestratigraphic column)

For each layer, you should consider: What type of bit would I use here and how

will the ROP be (high or low) ?

Is there potential for stuck pipe here ?

Potential for lost circulation ?

Layers/structures that can cause problems fordirectional drilling ?


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Drilling & Geology


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Drilling Rigs

Jack up

West Ariel / Seadrill

Semi Sub

West Alpha - Seadrill

Drillship

West Alpha - Seadrill

Condeep type. www.statoil.comWest PhoenixDualramrigg. Seadrill

Consults

www.seadrill.comfor

an

overview/animations
http://www.seadrill.com/http://www.seadrill.com/


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Riser, BOP, Choke and Killline


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Some drilling surface equipment

Riser tensioners,

Petrobras.

Riser

www.akersolutions.com

Active heave compensator

www.akersolutions.com

Iron roughneckwww.akersolutions.com

TopDrivewww.nov.com
http://www.akersolutions.c/http://www.akersolutions.c/


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Drillstring components

BHA

Bottomhole assembly:DCDrill collars

HWDPHeavy wall drillpipes

Jar - to release stuck pipe

MWD - Measurement while

drilling

LWDLogging while drilling

Motor or

Rotary steerable assembly

(with logs integrated)

Underreamer

Holeopener

Stabilisators

+ +

The BHA compostion will vary

depending on which hole

section to be drilled.

Bit.

www.nov.com

ExampleUnderreamer -

www.halliburtion.com

Some important drilllingparameters:

WOBWeight on bit

Torque

RPM

Flowrate

ROPrate of penetration
http://www.halliburtion/http://www.halliburtion/


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Drilling bits

Depending on the formation type, hardness and

abbrasivenessa proper bit has to be selected to optimise

ROP etc. Consult the homepages of the different vendors to

see which bit that is most approriate.


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Some vendors

National Oilwell (Reed Hycalog drillbits)

www.nov.com

BakerHughes (Hughes Christensen) www.bakerhughesdirect.com

Smith

(www.smith.com)

Varel www.varelintl.com

Halliburton

www.halliburton.com
http://www.nov.com/http://www.bakerhughesdirect.com/http://www.smith.com/http://www.varelintl.com/http://www.varelintl.com/http://www.smith.com/http://www.bakerhughesdirect.com/http://www.nov.com/


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ROPrate of penetration

ROP tells us how fast we drill.

(1 m/ hourvery slow, 60 m / hourquite good)

Low ROP - > Expensive operations.

ROP will depend on formation hardness & bit choice Bit change (wear, failure etc) is time consuming & costs

money

Important to choose the right bit for the formation to

ensure As high ROP as possible

Avoid wearing out the bits too early.


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Formation hardness

The choice of an approriate bit will depend onformation hardness & abrasiveness

Soft/Medium soft formation

Shale, clay, limestone, sands.

Medium hard/hard formation

Hard limestone, sandstone, dolomite

Hard and abrasive formations

Granites, basalts, quartzite and chert

Check www.adriatech.comfor appropriate rockbits for the different formation types.
http://www.adriatech.com/http://www.adriatech.com/


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Drillbit types

Roller cone

Tricone

Fixed cutter bitsPDC

polydiamond

crystaline

www.nov.com- Rockforce

www.nov.com
http://www.nov.com/http://www.nov.com/


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Drillbit types

Diamond bit

Hard formations

Very expensive

Drill out bicenter bits

Hole enlargement

www.nov.com


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Drillbit types

Coring bits (takesealed samples offormation to surface)

Milling tools (specialbits are required for

making hole in a steelcasing whenperforming asidetrack)

www.varelintl.com


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Roller cone bits

Cones

Bearings

Cutting structure

Insert (tungsten carbide) bits

Milled tooth

Jet nozzles (x 3)

Remove cuttings

Jet impact force

Defines TFA (total flow area)

Gauge inserts (protect gauge

of bit)

www.nov.com


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Workprinciple

When the drillpipe

rotates the three

cones will roll on theformation and crush

the rock.

A certain WOB (weight

on bit) is applied


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www.smith.com

Note operating

Note focus on

hydralics

Note focus ongauge

protection

Note focus onbearings

(generally a weak

point)


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Gauge protection

Must ensure that the bitreally drills the correcthole size

Undergauge (due to wear)can lead to a stuck pipesituation when re-entering the well with anew bit.

Wear resistant, durableshapes or diamond insertson the heel row.


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Cutting structure

Soft formation

Long cutters

More scattered

Hard formation Short and butt cutters

Weak point is that thecutters will be worn

Reduced ROP

Increase WOB will helptemporarily but wear theteeth even more

Trip and install new bit


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Bearings

Different types

Ball and roller bearing

Journal bearing(friction bearing)

Sealed and non sealedbearings

Lubrication ( grease

reservoir inside bitbody supplies thebearings if the bearingis sealed)


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Jet nozzles

Usually three (sometimes a center

nozzle in addition)

Flow velocity ( around 100 m/s)

remove cuttings/clean

Nozzle diameters will impact flow

velocity/pressure loss across bit

Low flowspeed will impact ROP

Nozzle diameters e.g. 20/32


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Roller cone application areas

Steel tooth Top hole, Soft formations

Tungsten carbid inserts Medium to very hard formations

Formations where PDC does not work

Drill out shoe (cement)

Rate of penetrationMedium, Slow

SteerabilityGood More trips to change bit due to wear compared

to using PDC bits.


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Some issues to be aware of

Cones can be lost (fishing operations)

The cutters will be worn down

Bearings is a weak point

Gauge wear

Bit balling (bit packed with formation)


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PDC bits

Body (tungsten carbide)

Waterways (junk slot)

Nozzles (3-8)

Cutters (position andbackracking angle will affectagressiveness)

Cutter blades (form andnumber can vary)

No bearings (opposed to roller

cone)

Many different designs(pending on application area)


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Work principle

PDC cuts rock The cutter is placed with a certain angle (backrake)

which affects how aggressive the bit will be. (cutter

orientation)


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PDC Cutters

PDC is formed bypolycrystalline diamond layerwith tungsten carbide substrate

Different types (special

technologies) PDC cutters are self sharpening

PDC cutters deteriorate quicklyat temperatures above 700 C.Proper cooling bymud/hydraulics is very

important (number of nozzlesand positions).

More cutter blades give bettercooling and less wear on eachcutter blade

www.pioneer-

polydiamond.com


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Application areas

Soft to medium hard formations (not applicable in very hard &abrasive formations)

Shales are easier to drill (ROP) than limestone/sandstone and PDCbits usually drills twice as fast in shale compared to roller cone

Lower sections (12 hole ->)

Steerable and rotary applications (motor & RSS) High ROP (opposed to roller cones)

More expensive

More robust (fewer trips compared to roller cone)

Steerability depends on design

Aggressives of cutters

Backrake of cutters

Blade count

etc


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Bit stabilityimportant in design

Unwanted vibrations

Axial (Bit bounce)

Lateral (Whirl)

Torsionaltwist about

its axis (Stick slip)

Can destroy the bitsquite fast and wear

them down

Torsional

Lateral

Axial

Bit


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Vibration roller cone

Axial vibration -Yes

Due too the three

cones

Torsional vibrations

No

Lateral vibration- Yes

Can cause rapiddamage to teeth


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Vibration PDC

Axial vibrationNo

Torsional vibrationYes The shearing action of PDC causes

a torsional force 3-4 times higherthan for roller cone

Stick slip

Lateral vibration- Yes Quite common

Can lead to severe damage to bit

and drillstring Different designs to overcome this

(anti whirl etc)A challenge for PDC

bits


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Vibration - PDC

To reduce vibrations and increase the stability

of the bit is a very important part of the bit

design process.

When using PDC bit in a very hard formation

(e.g. hard abrasive sandstone), the bit can

easily be destroyed by vibrations (SPE 79797).


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What affects the steerability of a bit

High Torque sensitivity to WOBimplies that small changes in WOBwill easily change the direction in away that is not wanted

Roller cones are much less

aggressive than PDC bits - > easierto steer (basic design)

However, PDC design has beencontinously improved to increasethe steerability

E.g. non aggressive cutters in theface of the bit will reduce torque

sensitivity to WOB changes.Important for PDC bit steerability.

WOB

Torque

Roller cones

PDC


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Hybrid Bits (recent technology)

Combination of roller

cone and PDC bit design

(use the best of both)

Hard and interbedded

formations - handleschanges from soft to hard

rock

Less vibrations

Increased ROP potential

Chert drilling Kymera Hybrid bitBaker Hughes Tools


36/65

Natural Diamond Bits

Applicable for hardformations (e.g. whereroller cone is too slow orhar too short lifetime)

Not applicable for chertand pyrite (will breakinto pieces and maydestroy the diamonds)

Not applicable for very

hard broken formations(may break thediamonds)

www.nov.com


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Directional DrillingWhy ?

Drilling of many

wells from one

platform

Multilaterals

Sidetracking

Relief well (usually

two)


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Directional DrillingWhy ?

Drain several layers

Horisontal drilling(Troll)exploit a thinoil layer (10 m)

Fractured formations

(e.g carbonates) havevertical fractures ->Horisontal wells aregood for drainage


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Directional drilling equipment

Motor

Combined with

MWD/LWD

Angle set atsurface

Only the motor

rotates whenbuilding angle

(not pipe)


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Directional drilling equipment

Rotary steerableassemblies Possibility to rotate

while changingdirection

MWD, LWD fullyintegrated

Real timecommunication withsurface (i.e.possibility to changedirection whiledrilling dependingon informationgained)

Autotrak

www.bakerhughesdirect.com

Geopilot - www.halliburton.com

Powerdrivewww.slb.com

Check the homepages for most recent

technology developments
http://www.halliburton.com/http://www.slb.com/http://www.slb.com/http://www.halliburton.com/


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Casing program, Why ?

Stabilise formation

Control pressures (avoidlosses)

Protect formation Isolate sones (avoid

hydrocarbons migratingto surface)

Avoid communication

between zones Why is it smart to set the

casing shoe in shale andnot sandstone ?

The two upper casings are

typically cemented to seabed.

Otherwise a 200 meter overlap

is common.


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Casing program, why ?

Install equipment/completion

Reduce well friction

Isolate sones

Avoid contamination

Avoid unwanted production

Coning

Shut off gas/water bearing formation

Possibility to control production from differentlayers.


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Typical casing sizes

Navn Drilled hole

size

Casing Size Alt Example of

depths (from

seabed)

Conductor 36 30 50-100 m

Surface casing 26 20 18 5/8 300-1200 m

Run BOP on

riser

Intermediate

casing

17 13 3/8 16 1300-2000 m

Production

casing

12 9 5/8 10 25004500 m

Production liner 8 7 5


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l h l d


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Pore pressure + lithology is required to

make the casing program.


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Well pressures

If Pwell < Ppore - > Potential kick

If Pwell > Pfrac - > Potential losses

i.e Ppore < Pwell < Pfrac

Pwell (bar) = d x 0,0981 x Htvd

ddensity of mud i sg ( e.g 1500 kg/m3 =1.5sg) HtvdTrue vertical depth of well


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Purpose of casing

Avoid losses

The chosen mudweight

(red line) will fracture

the formation at

around 1500 meters. It

means that we must

set a casing before

drilling the next holesection

Vil


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Purpose of casing

Stabilise well/protect formationAvoid stuckpipe incidemts Plastic formation, swelling clay

Avoid loose (fractured formation falling into well)

Avoid key seating


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Selection of correct mudweight

Mudweigt in sg

(must be

between pore

grad and frac

grad). We must

set casings when

the new

mudweight can

create losses

Max mudweightis limited by ECD

(well pressure

when

circulating) and

ev. surge

pressures.

Ensure that there is a

margin which takes

into account:

Swab effects

Riser margin

Temperature effects

The mudweight must

be large enough to

avoid a kick


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Kick & well control

Kick - > unwanted inflowof gas, oil or water, if notcontrolled - > Blowout

Reasons: Uncertainty in pore

pressure Wrong mudweight

Swab (during tripping orheave effects)

Lost circulation (muddisappear) caused by toohigh well pressures causing

fractures or drilling intocaves.

Insufficient refill of wellwhile tripping out.


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Well kill

After the kick has been detected. Close BOP

Monitor shut in pressures

Open choke and circulate the kick out through

chokeline to separator/flare Drillers method (kill mud after the kick has been circ out)

Wait and weight (circulate kill mud immediately)

Bullheading Last option methodreverse kill by pumping/forcing kick

back into formation

Reasons (H2S, unacceptable large kick volumes that canbreak down the formations on its way up)


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BOP - Barrier

NORSOK D10 provides

an overview of the

required barriers

(two) which are

required during well

operations.

BOP is classified as asecondary barrier.


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Chokeline, Killine, Choke

If a kick is to be circulatedout of the well it will becirculated out through the

chokeline and the choke isused to control the wellpressures in order toavoid new influxes

A killline is a similar line as

chokeline to pump fluidsinto the well (or it can beused as a secondarychokeline

Chokeline ID : 3


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Separator

The kick must be

separated from the

drilling fluid and the gas

has to be flared. Typical 5-10 MMscf/day

capacity

Poor boy degasser

www.oilfieldgnsolidscontrol.com
http://images.google.com/imgres?imgurl=http://oilfield.gnsolidscontrol.com/wp-content/uploads/2009/08/Poor-boy-degasser.JPG&imgrefurl=http://oilfield.gnsolidscontrol.com/oilfield-drilling-poor-boy-degasser/&usg=__5snh-22aXstIbtGT-VIfXKaPzak=&h=2048&w=1536&sz=350&hl=no&start=2&um=1&tbnid=n4YVR4yf5efiuM:&tbnh=150&tbnw=113&prev=/images?q=poor+boy+separator&hl=no&rls=com.microsoft:no:IE-SearchBox&rlz=1I7GGLF_en&sa=N&um=1


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HPHT wells

Formation temp > 150C, Pwell > 690 bar.

Large kick volumes

Easier to get kick

Kick can hide in oilbased mud (flashlater).

More strict routines isimplemented

Always circulateacross choke ifuncertain.

Deepwater Horizon21 April

2010.- Gulf of Mexico,

www.wikipedia.org
http://upload.wikimedia.org/wikipedia/commons/9/9d/Deepwater_Horizon_offshore_drilling_unit_on_fire_2010.jpg


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Choice of type of mud

OBM (oil based mud) Advantage:

Often more compatible with the reservoir

Less risk for fracturing the well at the last casing shoe in case

of a kick (HPHT) Reduce problem with swelling clay, thinner mud filter cake ->reduced risk for getting stuck.

Disadvantage

HSE, environment, more expensive Can be difficult to detects kicks in HPHT wells (the gas influx

will hide in the mud) -> Special HPHT procedures areintroduced in drilling to reduce the problem.


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Choice of type of mud

WBM (water based mud) Often used in the upper sections

Advantage:

Cheaper, less HSE issues, more environmental friendly Easier to detect kicks in HPHT wells (High pressure, high

temperature wells)

Disadvantage:

Swelling Clay/Shale Less lubrication

Thicker mudcake /easier to get differential stuck


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Geology related drilling problems

Stuck pipe is one of the more severe eventsthat can occur during drilling and can lead tolarge costs

Fishing operation In worst case, a sidetrack is the final solution.

Three main causes

Mechanical related

Formation related

Differential sticking (pressure related)


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Mechanical

Key seating

Poor hole cleaning

Undergauge

Wellbore geometry

Formation layers,

change in hardness

Collapsed casing

Junk


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Formation related

Unconsolidated

formations (e.g sand)

Boulders

Fractured formations(e.g. around a fault)

Mobile formations

(e.g. salt)


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Formation related - Shale

Shale can cause somspecial problems:

Geo pressured shale(over pressured shale)

Requires a highermudweight to controlit.

Reactive shale (water

from mud inhibits theshale and it swells)lack of inhibition


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Lost circulation

Can result in a reduced mudlevelin the well which again cancause a kick.

Reasons: Naturally fractured formations

(Karst, dolomite, limestone) Maybe UBO must be used to drill

this type of prospect

Too high ECD -> Fracturepressure exceeded

Reduce pump rate andmudweight

Surges Avoid tripping to fast

Break mud gel before initiatingcirculation.


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Lost circulation

LCMLost circulation material pills arepumped (marbles etc ) to try to plug thefractures.

Note that a lost circulation incident can havesome very negative consequences

Increase Kick probability

Reduced cuttings transport -> possible stuck pipe

Reduced fracture pressure next time

Possible collapse of well


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Lost circulation

Important to identify potential loss circulationsones in advance.

Seismic, geology

Isolate potential low pressure sones withcasings

Control ECD, cuttings transport

Avoid pressure surges Have equipment ready for injecting LCM into

well.

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Drilling & Geology 2012 ResourcePres Festningen Long

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