gasstimulationinthesnsv2

7/31/2019 GasstimulationintheSNSV2

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SPE London Section Evening MeetingMRN 1

Stimulation of

Horizontal Wells inthe SNS

Mark NorrisEngineering Advisor

DCS Schlumberger


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Agenda

Drivers for SNS gas stimulation and historical recap

Aspects of SNS fracture design

Modern methods for maximising reservoir contact

Resource availability

Questions


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Drivers for SNS Stimulation


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EU Hydrocarbon Consumption

Demand for energy will

continue to rise

Natural Gas is an important

part of the Energy Mix in the

EU

Oil and Gas consumption curves for the EU

EU Energy Mix 2008


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North Sea is becoming Gas Province

Gas field

Oil field

2008 NWY UK NHL DK

Contributionto GDP

11.8%

1.3% 2.5% 0.8%


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..and where is the productionUK Norway

Denmark Netherlands

Units in million stm3Oil and billion nm3Gas


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Drivers for Stimulation in the SNS

Encouraging GIIP in fallow fields but often associated with low

permeability

Gas prices volatile compared to oil

Gas producers must compete with oil producers for resources (rigs,

materials services etc.)

Need to maximise the commercial potential of each new well

Need to take advantage of the current surface infrastructure before it

gets too old and/or is retired out of service.


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Map shows the location of majorstimulations operations over the last 3years by all operators

The majority are still in Scandinavia

sectors

Central UK sector steady activity

The SNS is becoming more active

>95% of North Sea stimulation work ison horizontal wellbores

Multiple fracturing operations dominate

Where is NS Fracturingtaking place

FlexSTIM type Purpose Built


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Aspects of SNS Fracture Design


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Objective: create a high conductivity vertical plane with thereservoir

The rock is split using the liquid lever principle

The split or fracture is held open using a hard granularmaterial called proppant

Hydrocarbon is then drawn from the fracture faces, betweenthe proppant grains, to the wellbore

What is Hydraulic Fracturing


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Real OH Hydraulic Fracture

A recent photograph of an OH wellbore drilled in the direction ofmaximum horizontal stress

The fracture is packed with proppant to prevent it closing


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Pseudo Steady State Production

Increase

the inflow

area

Improve

connection to thereservoir

Bypass near

wellbore skineffects

QP - Pwf

= PI = 2 kh

lnrerw

{ }( ) - + sQ

P - Pwf

= = 2 kh

lnrerw

{ }( ) - + slnrerw

{ }( ) - + s{ }( ) - + s


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Stimulation and Effective Skin

Moving from a +ve

skin to 0

skin is damage removal

eg. matrix acidising asandstone, conventionalperforating etc.

Moving from 0 skin to ve

skin

is stimulationeg. hydraulic fracturing

Changes in skin value below 0

represent a dramatic increasein well productivity

+20

Skin

0-8

FoldsofIncrease

MatrixacidizingSandMatrixacidizingCarbPerf&PropellantsHydraulicfracturing


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Maximising Sandface Contact ina Tight Gas Reservoir

Economic drainage rates and recovery are driven by maximising wellbore

contact to the sand face in a cost effective manner

Hydraulic fracturing, often linked to horizontal wells, has been

utilised with

considerable success in many tight gas regions to maximise the formation

face are exposed to drawdown

Cased/perf OH Vertical well frac Horizontal well fracs

157 ft2

210 ft2

20,000 ft2

80,000 ft2


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Fracture Wing Design

Conductivity

Horizontal stress profile is thekey parameter

This dictates the shape of thefracture

The stress profile is derivedfrom the rock mechanicsproperties and calibrated fortectonic effects etc. using offset

data and core data

The stress magnitude drivesthe decision for proppant gradeselection

The in-situ formationpermeability drives theselection of proppant mesh size

The temperature drives the

selection of fracturing fluid


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Numerical 3D Production Modelling

Typical gas targets are the Rotliegendes, Leman, Carboniferous

and Silverpit


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Productivity

vs. No. ofFractures

Nf = 1

Nf = 2

Nf = 3

Nf = 4

Nf = 5

Nf = 6

Nf = 7

Nf = 8

Nf = 9

Nf = 10

0 50 100 150 200 250 300

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

Time (Days)

ProductionR

ate

(STB/D)

Nf = 1

Nf = 2

Nf = 3

Nf = 4

Nf = 5

Nf = 6

Nf = 7

Nf = 8

Nf = 9

Nf = 100 50 100 150 200 250 300

0

400

800

1200

1600

2000

2400

2800

3200

3600

4000

Time (Days)

CumulativeProd

uction(MSTB)

Fracture prod. Simulator isused to determine potential

productivity for variousspacings

along the wellbore

By varying the length andconductivity etc.anoptimisation process ispossible

Objective: frac spacing & fraclength

Production Rate

Cum Production


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1 2 34 5 6

7 8 910

50 ft

100 ft150 ft

200 ft

250 ft

0

0.5

1

1.5

2

2.5

3

ProductivityIndex(STBD/psi)

Number of Colinear Fractures

2.5-3

2-2.5

1.5-2

1-1.5

0.5-1

0-0.5

Fracture HalfLength (ft)

Little or no improvement in PI observed with colinear

fracture length

Beyond 6 fractures very little improvement in PI observed

Case History -

Fracture Length Effect


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1 2 3 45 6 7 8 9 10

1041 mdft

3123 mdft

5205 mdft0

0.5

1

1.5

2

2.5

3

3.5

Pro

ductivityIndex(STB/Psi)

Number of Colinear Fracture

3-3.5

2.5-3

2-2.5

1.5-2

1-1.50.5-1

0-0.5

Proppant Fracture

Conductivity (mdft)

Case History -

Fracture Conductivity

Improvement in PI observed upto

3000 mdft

conductivity

Beyond 6 fractures very little improvement in PI observed


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Economic Optimization

Fracture size and

placement is a trade-offbetween income vs.expenditure

Historically calibrated

production simulatorused to assessproduction income

Economic indicators

(NPV, DROI etc.) arethen optimized againstfracture parameters

30

50

70

902

34

56

78-10

-8

-6

-4

-2

02

4

6

8

10

12

14

16

NP

V(MM$)

Length (m)

Number of Proppant Fractures


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The Process


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The Process

Brine Linear Gel

Concentrated

Gel

Proppant

POD

Blender

HP TriplexPumps

wellAdditives

Process Control


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First Hydraulic Fracture Treatment 1946


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Material Selection

Placement fluid needs to exhibithigh visco-elastic viscosity to

prevent fluid leakoff into the highperm sands while also transportingproppant

30 lbm to 40 lbm

Delayed Borate XL Guar

Injection rates 30

40 BPM

Oxidising breakers are used toenhance flowback

16/20 or 12/18 proppant used tomaximise conductivity

Typically >50% resin coated


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Minimising the Pressure Drop in

the Fracture

20/40 16/20 12/18

Dmean= 1.3mmDmean= 1.0mmDmean= 0.7mm

Every psi of gas pressure drop along the fracture represents a reduced

drawdown on the sand face compromised productivity

SNS fracturing up to the late 90s typically used 20/40 and/or 16/20 sizedproppant due to a) unrealistic expectations of proppant performance and b)

concerns proppant diameter & screenout

In recent years a switch has been made to 12/18 proppant, coupled with

fracturing fluid advances, to minimise the Beta Factor and maximise fracture

permeability/conductivity especially in horizontal well fracturing


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Maximizing Fracture Conductivity

Tip screenout

techniques are usedto maximize fracturewidth

Proppant size &material optimized

Wellbore vs. fractureazimuth influences

near wellbore fracturewidth

Net Pressure using Rat Hole Pressure Gauge

100.00

1000.00

10.00 100.00

Treatment Time (mins.)

NetPressure(psi)

2 PPA proppant

stage at perforations

Initiation of

tip screenout


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Treatment Execution Methods


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Plug & Guns Wellbore Preparation

Coil tubing or snubbing used for all wellbore operations (ie. perforating,cleaning out excess proppant and setting retrievable bridge plugs if required)

Allows stand alone completions to be performed while rig continues to drill

No well control issues

due to brine weights


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SPE London Section Evening MeetingMRN 29Well Preparation


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SPE London Section Evening MeetingMRN 30Perforating 1st Zone

0 1000 2000 3000 4000 5000 6000 7000 8000 9000

Measured Depth of Tool String - m

-10000

0

10000

20000

30000

40000

50000

60000

WeightIndicatorLoad-lbf

Stripper Friction Load - 1000 lbfWell Head Pressure - 1000 psiCoiled Tubing Circ. Pressure - 1000 psi

CoilCADE*

*Mark of Schlumberger

Coiled Tubing Weight Indicator Load

Acq Load Case01-31-2001


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SPE London Section Evening MeetingMRN 31 Fracturing With Proppant


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Staged Isolation -

Proppant Plugs

Frac Tip-Screen-OutSlurry under-displaced

Frac is allowed to close, before theremaining wellbore proppant issqueezed to form a rigid plug


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Proppant plugsComparison of Proppant Plug Setting in Adjacent Zones

4500

5500

6500

7500

8500

9500

0 20 40 60 80 100Time Since Shutdown (mins.)

BottomHolePres

sureatGauge(ps

i)

Zone 1

Zone 2

Pressure Diffential

Across the Proppant Plug

-1000

-500

0

500

1000

1500

2000

2500

520 540 560 580 600

Treatment Time (mins.)

Press

ureDifferentialAc

rossProppantPlu

g(psi)

Plug forming postshutdown

Thermal effects Gradualbleedoff

atsurface

Plug fails at850 psi reverse

differential

2 squeezecycles to set

the plug


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SPE London Section Evening MeetingMRN 34Clean-Out and Perforate


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Multiple Zone Completion


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Final Clean-Out

0 10 20 30 40 50 60 70 80 90

Angle with Vertical -

deg

0

1

2

3

4

5

FlowR

ate-

bbl/min

Downward Sliding Bed Flowrate

Stationary Bed Flowrate

Minimum Suspension Flowrate

Pipe ID -

3.92 in

CT OD -

2.38 in

Particle Mean Diameter -

0.025in

Particle Specific Gravity -

2.65

CT Standoff -

70 %

Density of Slurry -

9.03 lb/gal

Fluid Index -

1 2% KCL Water

Seawater

Pressure drop through 23/8" coiled tubing

Pump rate (bpm)

0

50

100

150

200

250

300

0 1 2 3 4 5

Pressure

drop(psi

per

1,000 ft)

Seawater only

Seawater

+ J507


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Well Ready for Production

3800

3900

4000

4100

4200

4300

4400

4500

4600

4700

4800

Spinner response


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North Sea Fracture Direction

Offshore the globalfracture direction from

multiple datasetsindicates a NW:SEazimuth

In soft formations (E

3.0 Mpsi) local faultinginfluences the fractureazimuth


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< 5< 5

Wellbore Azimuth vs. Fracture

Tortuosity3030

9090

Hmin

Hmax

4545


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Near Wellbore Friction Pressure

vs. Wellbore Azimuth

0

500

1000

1500

2000

2500

3000

0 10 20 30 40 50 60 70 80 90

Wellbore vs. Perferred Fracture Azimuth (deg)

NearWellboreFrictionPressure(psi)

Near Wellbore Friction Pressure


0

500

1000

1500

2000

2500

3000

0 10 20 30 40 50 60 70 80 90


NearWellboreFrictionPressure(psi)

Fracture Initiation Pressure


4000

4500

5000

5500

6000

6500

7000

0 10 20 30 40 50 60 70 80 90


FractureInitiatio

nPressure(psi)

Fracture Initiation Pressure


4000

4500

5000

5500

6000

6500

7000

0 10 20 30 40 50 60 70 80 90


FractureInitiatio

nPressure(psi)

Colinear vs. Orthogonal Fracs Fielddata (cased hole)


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Field Case

Prop Slugs for Tortuosity

1,7

50Psi

55

0Psi

450Psi

200Psi

4,000

4,500

5,000

5,500

6,000

6,500

7,000

7,500

8,000

8,500

0 10 20 30 40 50 60

Time (mins.)

BottomHolePressure(psi)

0

5

10

15

20

25

30

35

40

PumpRate(BPM)&

PropConc.(PPA

)

BHP (Psi) Proppant Conc. (PPA) Pump Rate (BPM)

Proppant Slugs


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Enhancements

i-Coil for CCL, BHP, BHT

Anchor

Centralizer

Orientating Sub

Slot Cutting

Reverse Circulating Sub

Nitrogen (improves cutting)

Longevity of Nozzles

Parameters

2500psi Pressure Drop

1.25 BPM per Jet

Require Standoff

H2

S when Reverse Circulating

JetsJets

ReverseReverse

Circulating PortCirculating Port

AnchorAnchor

Perforating by Abrasion Jetting


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Casing and Formation Penetration

H i OH H i l W ll


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How is OH Horizontal Well

Fracturing Performed?

Uncemented

liner with external packers and selectable ports

OH interval fractured sequentially from toe to heel

Balls dropped from surface isolate below and open the next zone

Packers must withstand shock cooling (40

55 degF

frac fluid)

Inflatables and swellables less well designed for shock cooling,solid element types typically used (approx 4,000 wells to date)

Balls flow to surface or can be milled out with seats for PLT

access


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Timing and Cost savings via OH

6 zone well

Typical spread rate $250k -

$350k /day

Completion time saving 19 days

Fluid on formation 3 days compared to

21 days

Faster, more complete, well cleanup

Cemented Liner Plug & Guns1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33

Cement

Cleanoutwellbore

N

ippledownBOPs

NippleupTree

RigupCTandFrac

Perforate

Stimulate1

Cleanout

Perforate

Stimulate2

Cleanout

Perforate

Stimulate3

Cleanout

Perforate

Stimulate4

Cleanout

Perforate

Stimulate5

Cleanout

Perforate

Stimulate6

Cleanout

OH Staged Fracturing

1 2 3 4 5 6 7 8 9 10 11 12 13 14

NippledownBOPs

NippleupTree

RigupforFrac

StimulateStages

1-3

ReloadFracVessel

StimulateStages

4-6

RunLiner

RunStageFRACL

iner

RunUpperCompletio

Flow

welltoclean

up

Flow

welltocleanup

Run

UpperCompletio


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Example of OH vs. Perfs

Production

Wellbore fracture contact

Perfs

6ft

OH 30ft

125ft frac

Drawdown at fracture faceinhibited by pressure losses inthe fracture

These are concentrated in theconvergent non-darcy

flow

region near the wellborecontact

In this case 24% moreproduction rate is realised byallowing the OH fracture tonaturally dictate the contactdistance at the wellbore

ProductionRate

Mscf/day

Cased/Perf

PressureDrop in Frac

OH

PressureDrop in Frac

10 2700 2300

12.4 3500 2700

P


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OH Horizontal Well Fracturing

Longer track record

OH system so cost/risk of cemented

liner is eliminated

Reduced production convergence

Short period from frac to cleanup

Very low historic screenout incidence

Frac fluid on zone for minimal timebefore flowback (hrs)

OH sandface

and frac open for

production, full kh

exposed

Fracture contact interval maximised

Performed via prod. string or fracstring

Can arrange for sliding sleeves to bebuilt-in

Pros Cons

Need all materials on location totake full advantage of rapid cycletime

Larger lower completion OD torun in place

Need to mill seat for PLT access


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Stimulation Resources


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Resources

The entire North Sea area is limited

to two Stimulation Vessels

Many operators have in the past

discounted stimulation due to lack of

surface resources

Recently operations have moved to

temporally classed stimulationvessels using converted PSVs

Vessels commonly mobilise for 1

3

months

>25 large scale proppant fracture

treatments have now been executed

in this way in the SNS since Q1 2007

S l ti f th PSV


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Selection of the PSV

Job Specifications ie. rate, pressure and materials volume dictate deck

area required, commonly 700

900m2 deck

A high wind wall is an advantage for protection of personnel and

equipment Typically use a pool PVS with Class 2 DP provided by Operator


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Detailed Engineering & Planning

Detailed engineering conducted

in parallel with regulatory

compliance process

Full 3D layouts allow equipmentfit to be fully optimised

Due consideration given for

emergency ingress/escape

Vessel Build 7 21 Days


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Vessel Build 7 21 Days

N h S F i Fl 2007 2010


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North Sea Fracturing Fleet 2007 - 2010

SLB

HES

BJS Left the North Sea
http://www.marinetraffic.com/ais/showphoto.aspx?photoid=28375&size=fullhttp://media.shipspotting.com/uploads/thumbs/rw/311071_800/Ship+Photo+SKANDI++BARRA.jpghttp://www.slb.com/content/services/stimulation/vessels/bigorangevxiii.asp


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FlexSTIM Type Activity

FlexSTIM type Purpose Built


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In Summary

Stimulation of gas fields by multiple proppant fracturing of horizontal

wells is the preferred completion method for growing number of

operators in the SNS

It is a well proven technology that was largely pioneered here in the

North Sea for oil wells and latterly in the USA/Canada for gas wells

The NS service industry is no longer constrained by low levels of

available stimulation resources


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Flaring Chiswick Alpha following 5 fracs performed by SchlumbergerFlexSTIM Autumn 2007

Questions

gasstimulationinthesnsv2

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