Angsi-A Fracture Campaign Summary China Trip__SINOPEC, 2006

7/25/2019 Angsi-A Fracture Campaign Summary China Trip__SINOPEC, 2006

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Slide 1

Angsi-A Fracture CampaignSummary

China Trip- SINOPEC

18 – 19 May 2006

Slide 2

Main Objective

• Increase productivity of the wells

• Mitigate the detrimental effect of condensate drop out ongas recovery



Slide 3

Angsi Overview

• 20 wells for hydraulic fracturing treatment

• Consist of K, L and I – formations

• Permeability ranges from 1 to 10 mD

• Porosity ranges from 15 – 20%

Slide 4

N

SOUTHCHINA

SEA

TAPIS PUMP

AnPG-A - Phase II

GUNTONG-D

ONSHORE SLUGCATCHER

P H A S E I - 3 2 "

, 1 6 6 k m G a s T

r u n k l i n e f r o m

A n g s i

P h

a s e I -

3 2 "

, 5 5 k

m g

a s

p i p

e l i n

e t o

A n g s i

SELIGI-A

2 4 " 8 5 k

m S e A

g a s

p i p

e l i n

e

AnDP-B - Phase II

1 6 " ,

4 8 k m

c r u

d e p i p e l i n

e

Legend

Southern Gas Pipeline

Oil pipeline

AnDP-C - Phase III

AnDP-E - Phase III

AnDR-A - Phase I

Angsi Field Location Map Angsi Field Location Map



Slide 5

1st Campaign2nd Campaign3rd Campaign

Angs i-A

Platform

P R O B . G O T : - 2

4 4 6

L P G - 2 4 3 2

A-13 A-06

A-12 A-19

A-15

A-02

A-01

A-07

A-03R1L14A

A-05

2 4 6 0

L P G - 2 4 2 0

L P G - 2 4 5 3

P R O B .

G D T : -

- 2 4 5 6 . 5

4 .5 K M

S

2 4 4 0

2 4 2 0

2 4 6 0 2400

2 4 6 0

1

4

2

A-16

A-20

A-18

A-17

A-22

A-10 A-08R1

A-04

A-21

Slide 6

BackgroundBackground……Cross Sectional MapCross Sectional Map



Slide 7

WESTWESTEASTEAST

3089 M3089 M--TD,TD, GpGp--MMMW 15.0 PPGMW 15.0 PPG

ANGSI ANGSI--11EPMIEPMI19741974


3,398 M3,398 M--TD,TD, GpGp--MM

MW 15.0 PPGMW 15.0 PPG

3,344 M3,344 M--TD,TD, GpGp--MM




2,660 M2,660 M--TD ,TD , GpGp--KKMW 11.2 PPGMW 11.2 PPG

2,232 M2,232 M--TD,TD, GpGp--I/JI/J


ANGSI ANGSI--66CarigaliCarigali

19971997


19971997

2,230 M2,230 M--TD,TD, GpGp--I/JI/J


ANGSI ANGSI-- A ADRILLINGDRILLING--

RISERRISERPLATFORMPLATFORM(ANDR(ANDR-- A) A)

ANGSI ANGSI--BBDRILLINGDRILLING

PLATFORMPLATFORM(ANDP(ANDP--B)B)


20002000

2133 M2133 M--TD,TD, GpGp--I/JI/J

MW 10 PPGMW 10 PPG

•• Production Tests:Production Tests:-- M (AngsiM (Angsi--2 & 3): Neglig ible flow, Perm ~ 0.022 & 3): Neglig ible flow, Perm ~ 0.02--0.0050.005 mdmd-- L (AngsiL (Angsi--2): Flowing < 0.5 MMSCFD, Perm ~ 0.022): Flowing < 0.5 MMSCFD, Perm ~ 0.02--0.0050.005 mdmd-- K (AngsiK (Angsi--2): Flowing < 4 MMSCFD, Perm ~ 0.72): Flowing < 4 MMSCFD, Perm ~ 0.7 mdmd

BackgroundBackground……Exploration WellsExploration Wells

•• Angs i Angs i--4 Exploration Well (K4 Exploration Well (K--sstsst), hydraulically fractured/tested:), hydraulically fractured/tested:-- PrePre--frac production yield 4frac production yield 4--5 MMSCFD.5 MMSCFD.-- Relatively shor t frac length, +/Relatively shor t frac length, +/-- 160 ft. maximum.160 ft. maximum.-- PostPost--frac production: 4frac production: 4--5 Fold Of Increase (times), avg.18 MMSCFD.5 Fold Of Increase (times), avg.18 MMSCFD.

Slide 8

FRAC EQPT SPREAD150 Lifts

WORLD LARGEST OFFSHORE PLATFORM FRAC OPN

A-2 K-25L PROD TEST

COIL TUBING UNIT5 Lifts

A-07 Compo site

2375

2400

2425

2450

2475

2500

2525

2550

2575

2600

2625

2650

Shale

K-25U sand

K-25L sand

K-30sand

Mudstone

Rocktype5 00 0 1 00 0 0Stress (psi)

25 50 75 100 125 150 175 200 225 250

2375

2400

2425

2450

2475

2500

2525

2550

2575

2600

2625

0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10

Proppant Concentration(lb/ft²)

K-30/35 206 ft

K-25L 182 ft

K-25U 164 ft

K-22 148 ft

Half-Length

A-07 Compo site

2375

2400

2425

2450

2475

2500

2525

2550

2575

2600

2625

2650

Shale

K-25U sand

K-25L sand

K-30sand

Mudstone

Rocktype5 00 0 1 00 0 0Stress (psi)

25 50 75 100 125 150 175 200 225 250

2375

2400

2425

2450

2475

2500

2525

2550

2575

2600

2625

0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10

Proppant Concentration(lb/ft²)

K-30/35 206 ft

K-25L 182 ft

K-25U 164 ft

K-22 148 ft

Half-Length

MULTI-STAGE FRAC ZONES

K-22

K-25U

K-25L

K-30/35

Per Well :

• Proppant Volume- 200 ~ 400 Tons

• Frac Fluid Volume- 6000 ~ 10,000bbl s

• Pumping Rate- 40 BPM

• Frac Job Pressure- 9,000 psi surface- 13,000 psi downhole

• Frac Zone Isolation- Sand Plugs

Design & Execution...

0 200 400 600 800 1000

K-30

K-25L

K-25U

K-20/22

I-1

I-85

MAX

MIN

TIP-TO-TIP FRAC LENGTH (ft)

Treatment Size/Length Optimizedbased on :

- Net Pay Thickness- Perm- Fracture Conductivity- Proximity to GWC- Reduce risk of screen-out- Height growth/zonal coverage- Maximum Equipment Capacity

TD 3000 -6000 m MD

‘S’ WELL PROFILE - vertical across K sands

7” Liner

9-5/8” Csg

13-3/8” Csg

18-5/8” Csg

45~79 deg

Reach 2 ~ 5 km

< 5 degvertical fractures

flow connectivity

vertical wellbore

K-sst

I & J-sst



Slide 9

•26" @ 600 ft-TVD

•18-5/8" @ 2000 ft-TVD

•(Contingency)•13-3/8" @ 3600 ft-TVD

•I, J - sands

•9-5/8" @ 7200 ft-TVD

•K - sands•3-1/2"

•7" L iner @ 8700 ft-TVD

•3-1/2"

Casing Program/Well Profile

• 'S' shape drilling trajectory

• - 9,400-20,000 ft MD

• - <77° max well inclination

•K-sandsto befrac’d

Slide 10

Platform Layout...Platform Layout...

Supply VesselSupply Vessel

•• To offload fracTo offload frac eqpteqpt && matmat ’’ lslsusing the platform crane.using the platform crane.

H H H H

MooringMooringLinesLines

T E N D E R

T E N D E R

Platform Flare BoomPlatform Flare Boom

TemporaryTemporaryBurnerBurner

Boom* for Boom* for

WellWell FlowbackFlowback //Production TestingProduction Testing

PipelinesPipelines

H H H H

FutureFuturePipelinePipeline

Inter Inter --Platform BridgePlatform Bridge

**

Platform CranePlatform Crane

Drilling RigDrilling Rig

Area f or Fr acturi ng , Nit rogen/Well Test Equi pmen t Area f or Fr acturi ng , Nit rogen/Well Test Equi pment

Area f or Coi led Tub in g/Well Test Area f or Coi led Tub in g/Well TestEquipmentEquipment

Tender Barge (T6):Tender Barge (T6):

•• Filtration and Storage of frac water .Filtration and Storage of frac water .

•• Transferring frac water to ANDRTransferring frac water to ANDR-- A A

•• Storage for fracStorage for fracmaterials/chemicals.materials/chemicals.

•• Accommod ations Accommod ations

Angsi Dr il ling Riser Angs i Dril ling RiserPlatformPlatform -- A(ANDR A(ANDR-- A) A)

Tender CraneTender Crane

ANGSI ANGSI-- A A Central ProcessingCentral Processing

Platform (ANPGPlatform (ANPG-- A) A)



Slide 11

Fluid & Proppant

• PrimeFRAC Fluid – Temperature activated, zirconium-crosslinked water based fl uids

– Design for low polymer application for mini mum gel damage

– Compatible with Angsi fo rmation temperature – 300 F

– Recipe designed to be stable for about 1 ½ hour in 320 F environment

- still having viscosity >200 cp

• 16/20 Carbolite Opticoat Resin Coated ISP – Resin coated for proppant flowback control

– Provide high conductivity

– hold 5,000 to 14,000 psi press ure

Slide 12

Design Consideration• Rock Mechanic:

• Stress prof ile

Previous DataFRAC* (Frac on 1995) give estimate of sand frac gradient 0.71 – 0.72

psi/ft. ELOT test g ive estimate of shale frac gradient 0.81 – 0.85 psi/ft. Linearinterpolation of gamma ray reading based on the value above to build the stressprofile

• Young modulusTri-axial test give sand young modulus of 2.5E+6 to 3.0E+6 psi and shale young

modulus of 1.8E+6 psi.

• Poisson ratio

Tri-axial test estimate Poisson ratio range from 0.13 to 0.06



Slide 13

Design Consideration

• Pumping Parameter Pumping rate at 40 bpm wil l maintain the frac from unwanted heightgrowth and provide the higher net presssure to create suffic ientconductivity

PAD Volume ratio (PAD Volume/total treatment volume) of 35% issuffi cient to create design half length and Tip Screen Out effectbased on assumed leak off coefficient

Proppant ramping from 1 to 8 PPA will provide sufficient proppantconcentration (lb/sqft) and will provide good conductivity.

Slide 14

Fracturing Equipment

• 8 Frac Pumps ( around 1200 HHP each)

• 1 Pod Blender

• 1 PCM – 150 bbls

• 4 Frac Tanks – 4 x 250 bbls & 1 Header Tank – 1 x

250 bbls• 4 Liquid Additives Tank

• 4 Proppant Silo (each silo 64000 lbs capacity)

• 1 Sand Belt Conveyor

• 1 FracCAT container (for monitor ing and acquisi tion)

• 1 Lab container (for QA/QC)



Angsi-A: T-6, Drilling Platform, Production PlatformFlowing A-22L (13-July-03)

Slide 16

Fracturing SequenceFracturing Sequence……Current operationCurrent operation

•• Perforate#Perforate#11 (4(4--1/21/2”” WCP)/WCP)/RIH FracRIH Frac--stringstring/Mini/Mini--frac/Main Stage/frac/Main Stage/Sand plugSand plug

•• Perforate#Perforate#22 (2(2--1/81/8”” ThruThru’’ Tubing Gun)/MiniTubing Gun)/Mini--frac/Main Stage/frac/Main Stage/Sand plugSand plug

•• Pickup Frac BHA :Pickup Frac BHA : To frac I or J sand (if any)To frac I or J sand (if any)•• RIH Frac BHA/cleanRIH Frac BHA/clean--out sand plugs/Kill wellout sand plugs/Kill well•• POOH Frac BHAPOOH Frac BHA/Complete well/Complete well

……withoutwithoutPacker Packer

No TestingNo Testing(2nd well(2nd wellonwards)onwards)

•• Perforate#Perforate#33 (2(2--1/81/8”” ThruThru’’ Tubing Gun)/MiniTubing Gun)/Mini--frac/Main Stage/frac/Main Stage/Sand plugSand plug

I/J SandsI/J Sands



Slide 17

Treatment Statist ics• 596 Days from First to Last Fracture Treatment (7-Dec-01 to

26-Jul-03) 85 Weeks or 20 Months• 20 Different Wellbores

• 79 Fracture Treatments – 67 K-Sands

• 18 K-28/30/35

• 17 K-25L

• 12 K-25U

• 20 K-20/22

– 8 I-Sands

– 4 L-Sands• 13,800,000 Pounds of Proppant (70 Boat Loads)

• 217,500 Barrels of Water (110 Boat Loads)

Slide 18

0

50000

100000

150000

200000

250000

300000

350000

A - 0 2

A - 0 4

A - 0 6

A - 0 7

A - 0 3 R

1 A - 0 1

A - 0 5

A - 0 8 R

1 A - 1 0

A - 1 2

A - 1 3

A - 1 5

A - 1 6

A - 1 7

A - 2 1

A - 2 0

A - 2 2

A - 1 9

A - 1 8

Well Sequenc e

A v e r a g e P r o p p a

n t V o l u m e p e r W e l l ( l b s )

0

10

20

30

40

50

60

70

80

90

100

P a d S i z e

( % )

Design Volume

Actual Volume

Pad Size

Avera ge o f al l

K-Sands Stages per Well

Proppant Volume Per Well



Slide 19

0

50

100

150

200

250

300

350

400

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

A

v e r a g e F r a c t u r e H a l f - L e n g t h ( f t )

0

2

4

6

8

10

12

14

16

P r o p p an t C on c .i nP a y Z on e ( l b / s qf t )

Averag e of al lK-Sands Stages per Well

A - 0 2

A - 0 4

A - 0 6

A - 0 7

A - 0 3 R 1

A - 0 1

A - 0 5

A - 0 8 R 1

A - 1 0

A - 1 2

A - 1 3

A - 1 5

A - 1 6

A - 1 7

A - 2 1

A - 2 0

A - 2 2

A - 1 9

A - 1 8

Average Frac Half-Length

Slide 20

Stimulation Time Per Well (days)

0

5

10

15

20

25

30

A - 0 2

A - 0 4

A - 0 6

A - 0 7

A - 0 3

R 1

A - 0 1

A - 0 5

A - 0 8

R 1

A - 1 0

A - 1 2

A - 1 3

A - 1 5

A - 1 6

A - 1 7

A - 2 1

A - 2 0

A - 2 2

A - 1 9

A - 1 8

S t i m u l a

t i o n T i m e ( d a y s )

A-15

L-Sands

A-18

L-Sands

3.3 Days Average

Not Including L-SandsStarted "Live" Annulus

(No Packer)



Slide 21

Stimulation Time Per Stage (days/stage)

0

1

2

3

4

5

6

7

A - 0 2

A - 0 4

A - 0 6

A - 0 7

A - 0 3 R

1 A - 0 1

A - 0 5

A - 0 8 R

1 A - 1 0

A - 1 2

A - 1 3

A - 1 5

A - 1 6

A - 1 7

A - 2 1

A - 2 0

A - 2 2

A - 1 9

A - 1 8

S t i m u l a t i o n T i m e p e r S t a g e ( d a y / s t a g e )

0

1

2

3

4

5

6

7

N o of S t a g e s P er W el l

Slide 22

Results• 34% of Gas Production from K-Sands

– 104 MMscf/d out of 303 MMscf/d (July 2003)

• 22% of Liquids (Oil & Condensate) from K-Sands

– 14,000 bopd out of 67,000 bodp (July 2003)

• $ 660,000 USD Cash Flow From K-Sands

– $3.00 per Mscf

– $25.00 per bb l



Slide 23

“ Typical” Mini-Frac Procedures

• Pump 100 bbls Linear Gel or 2% KCl at 30 bpm

• Shut-Down for 15 to 30 Minutes

– Analyze Pressure Decl ine

• Pump 250 bbls XL Gel & Displace to Top Perf with Linear Gel (AverageFlush 175 bbls)

• Perform Rate Step-Down Test

– Analyze Step-Down Data

• Shut-Down for 30 to 90 Minutes

– Analyze Pressure Decl ine

Slide 24

Mini-Frac Analysis Procedure(performed in “ real-time” )

• Review Injection History

• Determine Instantaneous Shut-In Pressure (ISIP)

• Analyze G-Funct ion Graph

– Closure Pressure, Net Pressure, Fluid Effic iency, Pressure DependentLeakoff, and Height Recession

• Analysis Log-Log Graph

– Closure Pressure, Net Pressure, Fluid Effic iency• Analyze Square-Root-of-Time Graph

– Closure Pressure, Net Pressure, Fluid Effic iency

• Review Results for A ll Analysis Techniques and Determine ClosurePressure & Fluid Efficiency



Slide 25

BackgroundBackground…….Conceptual to Implementation.Conceptual to Implementation

(cont.)(cont.)

Conceptual:Conceptual: 16/30 Intermediate Strength16/30 Intermediate Strength ProppantProppant (ISP)(ISP)Implement:Implement: 16/20 ISP16/20 ISPBetter conductiv ity, avoidBetter conductivi ty, avoid proppant flowbackproppant flowback

•• ProppantProppant Size:Size:

Conceptual:Conceptual: sand plug + mechanical bridge plugssand plug + mechanical bridge plugsImplement:Implement: sand plugssand plugsSaves rig timeSaves rig time

•• Zonal Isolation:Zonal Isolation:

Conceptual:Conceptual: Coil tub ing (CT) with 16/30 + 20/40 sandCoil tub ing (CT) with 16/30 + 20/40 sandImplement:Implement: mixmix ‘‘on the flyon the fly’’ with breakers (16/20+100mesh)with breakers (16/20+100mesh)Saves rig time, better pressure integrity with 100 meshSaves rig time, better pressure integrity with 100 mesh

•• Sand Plug Placement Method:Sand Plug Placement Method:

Slide 26

BackgroundBackground…….Conceptual to Implementation.Conceptual to Implementation

•• Perforation Guns:Perforation Guns:

Conceptual:Conceptual: hydraulic + mechanical retrievable packer hydraulic + mechanical retrievable packer

Implement:Implement: ‘‘ live annuluslive annulus’’ i.e.i.e. packerlesspackerless (2nd well onwards)(2nd well onwards) Avoid packer leaks/stuck, saves rig t ime Avoid packer leaks/stuck, saves rig t ime

•• Downhole Equipment (packer):Downhole Equipment (packer):

Conceptual:Conceptual: CT + ThruCT + Thru’’ tubing wireline guns (1tubing wireline guns (1--11/1611/16”” ))

Saves rig time on pipe trippingSaves rig time on pipe tripping

Implement:Implement: Wireline Casing guns + ThruWireline Casing guns + Thru ’’ tubing (2tubing (2--1/81/8”” ) +) +‘‘ tractor tractor ’’ for wells > 70 deg.for wells > 70 deg.

Conceptual:Conceptual: CT and NitrogenCT and NitrogenImplement:Implement: ‘‘gas from adjacent wells (2nd well onwards)gas from adjacent wells (2nd well onwards)Saves rig time and costSaves rig time and cost

•• Well Unloading:Well Unloading:



Slide 27

Key Lessons Learnt...Key Lessons Learnt...

• Batch Drill sui table for Batch Drill sui table for fracingfracing::

sufficient time for better f rac design (actual formations).sufficient time for better f rac design (actual formations).

•• ‘‘Live AnnulusLive Annulus”” Fracturing Technique:Fracturing Technique:

reduces rig time and overall NPT (simpler operations).reduces rig time and overall NPT (simpler operations).

•• PostPost--frac testing after completion through productionfrac testing after completion through productionsystem:system:

significantly saves rig time.significantly saves rig time.

•• Use of Resin CoatedUse of Resin Coated ProppantProppant::successful in mitigatingsuccessful in mitigating proppant flowbackproppant flowback at high rates.at high rates.

•• Extensive planning on equipment design, inspection,Extensive planning on equipment design, inspection,

onshore preonshore pre--commissioning and maintenance:commissioning and maintenance:

resulted in negligible equipment downtime.resulted in negligible equipment downtime.

Slide 28

Continuous Performance Improvement ...Continuous Performance Improvement ...

• Utilizing wirelineUtilizing wireline ““ tractor tractor ”” perforation technique for wellperforation technique for well

deviation > 70 deg:deviation > 70 deg:

saves rig time on pipe tripping for TCP perforation.saves rig time on pipe tripping for TCP perforation.

• Conducted fracturing the poorerConducted fracturing the poorer ““ II-- reservoirsreservoirs”” ::

To improve productivi ty.To improve productivi ty.

• Understanding actual formation stresses and fractureUnderstanding actual formation stresses and fracture

height growth:height growth:

optimize the frac design, save cost.optimize the frac design, save cost.

• Managing space constraint due to logistics, liquidManaging space constraint due to logistics, liquid

storage, supply vessels,storage, supply vessels, personnelspersonnels on board (POB).on board (POB).Have simpler, safe and cost effective operations.Have simpler, safe and cost effective operations.



Slide 29

TOPICTOPIC PrePre--Drill DesignDrill Design Best PracticeBest Practice Do DifferentDo Different

GeomechanicalGeomechanical Reservoir CharacterizationReservoir CharacterizationPressure fall-off,E-LOT at csgshoe, DSI logs

DSI in appraisal well was used to estimatestress profiles & rock properties, calibratedwith core triaxial mech properties, leak-off testin shales at csg shoe & mini-frac data.

- Run in correctmode for rockmechanicalproperties

- Run one DSI login each faultblock & calibrateDSI logs

Post-fracevaluation

Do post-frac diagnostic& integrate withfracture & reservoirmodelling to analyse

resulting fracture.

Diagnostics for post-frac evaluation is criticalto improve futu re designs. Use wirelinegauges for real-time BHP, measurementsduring diagnostic injection, BHP memory

gauges (with wireline interrogation ),temperature logs, radioactive tracer logs, andflow test (to evaluate frac performance).

Perform diagnostic(Injection test) toanalyze in-situformation stresses,barrier competency &fluid leak-off, and dobase-design. Data onin-situ stresses can beused with logs duringdrilling to refine stressprofile.

Full density logs Full density log in appraisal well used toestimate overburden/vertical stress. Stresscontrast btw min sand stress & vertical stresssuggest frac orientation is vertical.

UBI logs Borehole image log is not a primary indicatorof frac azimuth, but was used to show nowellbore breakout/ellipci ty in K-sand. (Notcritical for Angsi due to its large well spacingand modest frac length)

Best Practices & Lesson Learnt...Best Practices & Lesson Learnt...

Slide 30


FracFrac FluidsFluidsGelled Frac FluidSystemPrimeFrac(CMHPG-Zir) vsothers

Guar or its derivatives(HPG/CHMPG) with delayed cross-linking of gel structure

Freshwater Zirconium crosslinked(CHMPG-Zir) with 35lb/kgalpolymer loading provided thedesired fluid viscosity &minimized frac conductivityimpairment (concern on scalingetc)

Freshwater vsseawater

Use freshwater filtered to 2 miconswith 2% KCl by weight of water.Seawater can minimize logist icissue & less expensive, but wasnot selected due to its lower

viscosity (or higher polymerconcentration required), and fluidstability issue at high temperature.

2% KCl was used to stabilizeformation c lays.Tender ballast andlarger capacity boat critical tofresh water deliv ery. Had alternatefluid (flexability) - 55lb/kgal

seatwater based fluid system(same materials as freshwatersystem) as backup in casefreshwater supply interrupted.

Review fracturefluid with blendedwater (fresh andseawater)

Fluid rheology /lab testing

Conducted extensive lab rheology(Fann-50) and retainedconductivity test.

CrossLink Increased crosslink delay agenton long er reach wells

Fluid formulationshould considerspecific wellbores(crosslink time onextended reachwells)

Best Practices & Lesson LearntBest Practices & Lesson Learnt……



Slide 31


ProppantProppant16/20 resin coatedCarbolite (premiumlightweight ceramicproppants)

16/30 Mesh IntermediateStrength Proppant (ISP)

Curable resin coatedproppant (RCP) was requireddue to high gas productionrates & inability to handleproppant flow-back. Workwith production to minimizecyclic loading of proppant byimplementing bean-upprocedure for each well.

Surface facilitiesshould b e able tohandle some solidsproduction (sand filter,cyclone, strainer, etc.)

20/40 & 100 meshsand

Having different proppanttypes/sizes on locationallowed flexibility in proppantslug design to reduce nearwellbore pressure

Proppant Quantity& Concentration

400k lbs for 600 ft fracheight/length ( K-22, K-25,K28/30 in a s ingle stage jo b). 1

to 8 ppg mixed in stages withgelled frac fluid

As per j ob


Slide 32


Formation Damage TestingFormation Damage TestingCore flow tests (I &K-sands) andCompatibility /emulsion

Conducted formationdamage & fluid compatibilitytests using K-sand core,reservoir, completion &stimulation fluids, addingfree-ions/fines to simulateactual field conditions.

- Obtain more coresamples (ran out ofcore)

- Obtain formationwater sample (used labsimulated sample fortesting)

Work stringWork string4-1/2", 15.1lb/ft, P-110, PH6 tubing

- Industrial best practice - 4-1/2"tubing frac string used inside 7"liner in deviated wellbore

Use DP instead of regularwork string (makes-upquicker)

5" & 5-1/2"Drillpipe

"Live Annulus" workstring -use of 5" DP in 9-5/8" casing ,and 4-1/2" DP in 7" linerwitho ut packer. Proven ascost-saving, simpler stringwith fewer problems & littledown-time

Start with drillpipe?Condition of DP afterfracture treatments?




Slide 33


PerforationPerforation2-1/8" & 4-1/2" perfgun phasing /charges/decentralization

90-120 deg phasing, 2-6 spf,average perf diameter 0.21"/shot

-Zero phasing not a problem

- Limit p erf interval (6 meters)

- No problem running down 2-1/8” guns up to 70 deg(pumping down with rollers).

- Overbalance perforating (4000psi) helped breakdowns

Start with Safety perfsystem (no need forradio silence)

Tagging sandplugs

Have at least 5 meters frombottom perf to top of sand plug

When changingfrom multiple stageto single stage job

Use limited entry perf technique "Lim ited entry" per hasadvantage over "ball sealers"technique for h igh temp (>300deg F).

LoggingLoggingGamma ray/perfguns

Alw ays run GammaRay with perf guns


Slide 34

TOPICTOPIC PrePre--DrillDrillDesignDesign

Best PracticeBest Practice Do DifferentDo Different

Completion EquipmentCompletion EquipmentHi-Performancepacker, PTV,DGA, TFTV,BPCV, Linc

Use field proven hardware with adocumented track record andpersonnel experienced withhardware (HPP)

Flex Packer - Hanging weight below packer workedwell on the A-15 L-Sand

-Hanging workstring in tubing hangaradded extra level of protectio n (A-18 L-Sand)

-Set isolation packer on top of L-Sandbefore moving up to K-sand (A018)

-Consider having packer in workstring(unset) so it could be set if required tobreakdown, saving a trip

Coiled Tubing & NitrogenCoiled Tubing & NitrogenCleanup/Logistics

- Avoid using nitrogen to clean outwell (mess up plugs or flow backsand plugs requiring pre-settingsand plugs)

- Review logistics of nitrogenstorage (on location/delivery/supply)

- Larger ID CTU for washing 7” liner.

- Locate CTU to reach ALL slo ts




Slide 35


Surface EquipmentSurface EquipmentTreating i ron,measurementequipment (flowmeters, densitymeters, etc.)

- Max Surface TreatingPressure of 7000 psi at 35bpm

- Flexibility in treating ironis required to allowexpansion caused by flowvelocity & heat. Minimizeno. of bend/sharp turns toreduce erosion risk due toabrasive flow.

- Max Surface TreatingPressure up to 10,000 psiat 40 bpm

- Consider need for high pressuredensometer with low pressuredensometer

- Consider 4” high pressuretreating line (compared to two 3 inlines)

Well test &coiled tubing

- Eliminated use of h eaterin testing equipment

- Alw ays use targ etelbows when flowingafter fracture treatment

- 4" water supply lineworked well (no valve at

the end)

- Position CTU relative to V-door,hi-line, and well sl ot position

- Have two sacrifical lines (one toeach flair)

- Capture proppant from sand filterto measure volume of proppant

- Consider permanent flow lines

for extended testing programs (nohammer unions)

Flow head, frachead, E-Z valve

Valving must be properlyinstalled to avoidbackflow, isolateequipment sectors.

- Minimal erosion on fl owhead and frac head (14million lbs of proppant)

- Review wellhead/frac valveconfiguration during planningphase (reduce rig-up time andheight)

- Consider backup flowhead onlocation (or located close by)


Slide 36


Surface Equipment (cont.)Surface Equipment (cont.)Safety reliefdevices (GORV,pop-offs, pumptrips, annulustrips)

- Set GORV below maxpressure to account foractivation time

- Pump kickout based onboth annulus and tubingpressures

Emergency shut-down on wellheadduring cleanup via productionwellhead (eliminate manuallyclosing valve on wellhead)

BOPs Tubing ram closed tocreate pressurizedannulus.Install automatedoverpressure reliefmechanism (lined up toannulus).Need heavy dut ytubing ram to encounterrepeated tubin gmovement.




Slide 37


Fracture Treatment OptimizationFracture Treatment OptimizationMissing data(productionlogs, well tests,etc.)

Consider PBU, additionalsingle zone testing,production logs early inthe program

Proppantflowback

Operate wells as per procedure tominimize proppant flowback

- Review all materials(Resin Coating / PropNet/ Sand Wedge / Flex Prop)

- Compare initial wellcleanup information tosensitivity of sandproduction on w ells thatmake proppant, also fracdata and reservoir fluidproperties

Sand plug zoneisolation

Either use sand plugs ordrillable bridge plugs for

zonal isolation in deviatedwell. Bridge plugshowever need CTU &good debris clean-out toavoid sticking problemsduring completions. Sanddumping only works invertical well.

- Sand plug is the preferredmethod over setting bridgeplugs

for multiple zones- Sand plugs should be set on thefly

- Use 100 mesh on top

- 5 meter minimum height aboveperfs


Slide 38

TOPICTOPIC PrePre--DrillDrill

DesignDesignBest PracticeBest Practice Do DifferentDo Different

Fracture Treatment Optimization (cont)Fracture Treatment Optimization (cont)Fluid mixing,preparation, & transfer

Base fluid (2% KCl, additives) was mixedon tender barge and transferred before andduring each treatment. Combinatio n offluid storage on patform & fluid transferduring treatments allowed treatments aslarge as 2500 bbls of clean fluid.

Physically clean commonmanifolds (circulating notsufficient)

Mini-fracs and stepdown rate tests

Highly recommended

Clean-out after

fracture treatment

Gun debris and 100 mesh was difficul t to

wash-out (some wells)

Flow-back & clean-up(e.g., bean-upprocedures)

Clean-up tim e limited after fracturetreatment by rig moving to next slot

-Better job of clean-upbefore handover toproduction (minimizechlorides contact withtubing and productionfacilities)

-Speed up flow line rig-up(reduce time from frac toflowback)

- Do better job ofsimultaneous operations(continuous flowing ofwell for clean-up)




Slide 39


Wellbore ConfigurationWellbore ConfigurationTrajectory S shape profile. Sufficient

rathole needed below lowermostfrac zone to allow TD logging,room for settling sediments,crushed fines, and residualproppants.

S shape (up to 20000 ft MD and75 deg) to minimize fraccomplexity (multiple frac &tortuosity)

Casing Ensure good primary cementingbtw casing & formation(precautions against highpressure pumping acrossperforation)

Consider designingwellbore (casing andsurface equipment) for liveannulus

Packers,accessories, etc.

Use hydraulic retrievable packer& slip joints.

Pressurized

annulus (tocounteract tubingmovement &detecttubing/packerleaks)

Use overbalanced brine ( KCl for

up to 10.9 ppg, and CaCl2 forabove 11.0 ppg Angsi K wells).


A-020 300Gamma ...

0 40Resistivit...

2 3Bulk Den...

0 0.5Neutron ...

8000

8100

8200

8300

8400

8500

8600

8700

8800

Shale

K-20/...

Muds...

Muds...

Siltst...

K-25...

Muds...

Sand...

Muds...

R o. .. S tr .. .

100 200 300 400 500 600 700 800

0 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.0

Proppant Concentration (lb/ft²)

Treatment Design A-02

87 Klbs

139 Klbs

106 Klbs

27 Klbs

Total 359 Klbs



Treatment Design A-18 A-18 K-sand Composite Geometry

7800

7900

8000

8100

8200

8300

8400

8500

8600

8700

A... R... N... GR

D e p t h ,

T V D ( f t )

Shale

K-25U sand

K-25L sand

K-25L sand

K-30 sand

Mudstone

L shale

Rocktype

D e p t h ,

T V D ( f t )

100 200 300 400 500

7800

7900

8000

8100

8200

8300

8400

8500

8600

8700

0 0.20 0.40 0.60 0.80 1.0

Proppant Concentration (lb/ft²)

Width Profil...

0

7800

7900

8000

8100

8200

8300

8400

8500

8600

8700

289 Klbs

153 Klbs

301 Klbs

295 Klbs

Total 1038 Klbs

Slide 42

Back Up



Slide 43

Lesson Learned

Fluid QA/QC – Fluid Contamination during transferring from T-6 toPlatform

The Ca++ is higher than the specification that reduce fluid performance. Flush the

line before transferring the base fluid.

Live Annulus Frac Vs Packer Reduce the execution time significantly

Spotting Sand Plug (On the fly -part of flush ,Cut X-linker, Increase

the breaker concentration).

Reduce time to spot sand plug using CTU and No bridging issue.

Reduce The Gel Loading

Stop pumping PrimeFRAC 55 and plan to pump PrimeFRAC 40.

Increase the sand concentration and Reduce the Pad volume

Improve the frac conductivity

Wellhead Deck December 2001



Wellhead Deck July 2003

Slide 46

ECONOMICS ...

ECONOMIC EVALUATION K-SAND STIMULATIONTYPE WELL

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

0 10 20 30 40 50 60

Production Time, days

R e v e n u

e ,

$ U S D

27 Days to Payout

37 Days to Payout

Total Cash Flow

Gas Cash Flow

Condensate Cash Flow

$1,120,000

Stimulation Cost

(incl. Rig Time)

Cash Flow Based on

20 MMscf/day (Gas Rate)

1040 bbl/day (Condensate Rate)

$1.50 per MMscf of Gas

$10 per bbl o f Condensate

Excl. well clean-up period



Slide 47

•• PERFORATION CRITERIAPERFORATION CRITERIA

•• SPFSPF : 2: 2 -- 6 spf 6 spf •• DIAMETERDIAMETER : 0.2: 0.2”” -- 0.40.4””

•• PHASINGPHASING : 90: 90°° –– 120120°° / / 180180°°

•• PERFORATION TECHNIQUEPERFORATION TECHNIQUE

•• Thru Casing : Wireline/TCP (orientation possible)Thru Casing : Wireline/TCP (orientation possible)

•• Thru Tubing : Wireline/CT (nonThru Tubing : Wireline/CT (non--orientation)orientation)

•• CURRENT PERFORATION GUNS UTILIZESCURRENT PERFORATION GUNS UTILIZES

•• 1st Stage (bottom most stage)1st Stage (bottom most stage)

•• Gun TypeGun Type : 4: 4--1/21/2” ” HMX PJ4505 WCP HMX PJ4505 WCP

•• Diameter Diameter : 0.41: 0.41” ” (average)(average)

•• SPFSPF : 5: 5

•• Phasing Phasing : 72: 72°°

•• Subsequent Stages (ThruSubsequent Stages (Thru’’ Tubing Wireline Guns)Tubing Wireline Guns)•• Gun TypeGun Type : 2: 2--1/81/8” ” Enerjet HMX BH Enerjet HMX BH

•• Diameter Diameter : 0.45: 0.45” ” (average)(average)

•• SPFSPF : 4: 4

•• PHASING PHASING : 0: 0°°

Perforation Strategy...Perforation Strategy...

Slide 48

Angsi A-07 K-25U Mini-Frac

Injection SummaryMeas'd Btmh (psi) Slurry Flow Rate (bpm)

40.00 50.00 60.00 70.00 80.00 90.00 0

1600

3200

4800

6400

8000

0.0

25.0

50.0

75.0

100.0

125.0

1:Start Minifrac (44.1 min)

2:Stop Minifrac (56.2 min)

3:End of Shut-in (86.2 min)

Total injection test volume: 443.7 bbls

Average slurry rate: 36.4 bpm



Slide 49

Angsi A-07 K-25U Mini-Frac AnalysisG-function Graph

Meas'd Btmh (psi) (d/dG) Surf Press [Ann] (psi)(G·d/dG) Surf Press [Ann] (psi)

0.000 0.540 1.080 1.620 2.160 2.700 4500

4900

5300

5700

6100

6500

0

800

1600

2400

3200

4000

0

400

800

1200

1600

2000

BH Closure Pressure: 5613 psi

Closure Stress Gradient: 0.693 psi/ft

Closure Time: 3.1 min

Pump Time: 12.2 min

Implied Slurry Efficiency: 17.1 %

Estimated Net Pressure: 632 psi

Slide 50

Angsi A-07 K-25U Mini-Frac Analysis

Log-Log GraphDelta Pressure (psi) (d/dt) Delta Pressure (psi)

0.100 1.000 10.000 100.00 10

100

1000

10000




Pump Time: 12.2 min





Slide 51

Angsi A-07 K-25U Mini-Frac AnalysisSqrt Graph

Meas'd Btmh (psi) (d/dt) Surf Press [Ann] (psi)

5000

5400

5800

6200

6600

7000

-750

-600

-450

-300

-150

0

0.0 6.0 12.0 18.0 24.0 30.0




Pump Time: 12.2 min



Slide 52

Mini-Frac Applications

• Closure Stress

– Fracture Modeling

– Net Pressure (Complexity)

• Fluid Efficiency

– Optimize Pad Size

– Estimate Permeability (Some Cases) – Ad just Proppant Schedule



Slide 53

WHAT IS TORTUOSITY? WIDTHRESTRICTION CLOSE TO WELLBORE

Slide 54

WIDTH RESTRICTION INCREASESNECESSARY WELLBORE PRESSURE



Slide 55

FRACTURES GROW PERPENDICULAR TO THE LEAST PRINCIPLE STRESS

-- BUT WHAT HAPPENS AT THE WELLBORE ?

Slide 56



Slide 57

STEPDOWN TEST

Source: “SPE paper 29989 by C.A. Wright et al.

• Perforation friction dominated regime

Slide 58

STEPDOWN TEST

• Tortuosity friction dominated regime



Slide 59

Angsi A-07 K-25U Mini-FracStep-down Test

Meas'd Btmh (psi) Btm Slry Rate (bpm)

55.00 55.40 55.80 56.20 56.60 57.00 6000

6200

6400

6600

6800

7000

0.0

20.0

40.0

60.0

80.0

100.0

Step 1Step 2

Step 3

Step 4

Rate is reduced by simply shutting down pumps

Slide 60



Slide 61

Remedial Measures Depend on Proper Diagnosis

High entry friction

High perf friction Severe fracture tortuosity

Re-perforate Use proppant slugs

Initiate with high viscosity fluid

Increase gel loading

Increase rate

Future wells may have alteredcompletion strategy such as

FEWER perfs

Slide 62

Mini-Frac Analysis

• Analysis Performed on Every Fracture Treatment

– Graphs In Lessons Learnt IV

– Values In Lessons Learnt IV and DataBase

• Analysis A lso Performed by Schlumberger Using FracCade



Slide 63

Mini-Frac AnalysisK-28/30/35 Sands

K-28/30/35 Sand

Fault Closure Fluid Net Perf O pen % PerfsWell Block Pressure Eff. Pressure Tortuosity Friction Perfs Open

(psi/ft) (%) (psi) (psi) (psi) (each) (%)

A-02 1 0.70 49 1210 100 240 26 24

A-04 1 0.73 61 883 190 400 22 25

A-06 1 0.74 58 600 40 40 68 99

A-12 1 0.72 44 529 0 170 37 36

A-13 1 0.71 64 650 57 75 60 36

A-15 1 0.74 47 685 150 595 14 9

A-16 1 0.74 52 730 20 200 29 35

A-17 1 0.73 43 620 0 140 35 35

A-19 1 0.74 58 710 150 160 33 41 A-21 1 0.78 35 420 0 230 21 25

A-08R1 2 0.74 67 730 93 130 45 37

A-10 2 0.74 56 620 60 340 20 26

A-22 2 0.73 53 530 116 54 54 68

A-01 4 0.72 43 600 50 30 93 38

A-07 4 0.72 42 665 40 215 29 35

A-18 4 0.73 70 620 80 60 54 45 A-20 4 0.75 72 560 114 76 48 48

Average 0.73 54 668 74 186 41 39

Minimum 0.70 35 420 0 30 14 9Maximum 0.78 72 1210 190 595 93 99

-Sorted by Fault Block-Screen-Outs shown in Bold and Italic

Slide 64

Mini-Frac AnalysisK-25L Sand

K-25L SandsFault Closure Fluid Net Perf Open % Perfs

Well Block Pressure Eff. Pressure Tortuosity Friction Perfs Open


A-02 1 0.67 9 860 600 400 26 18

A-04 1 0.74 20 450 220 330 24 11

A-06 1 0.74 26 450 120 60 56 38

A-12 1 0.71 30 350 78 32 76 47

A-13 1 0.70 74 653 46 130 38 29

A-15 1 0.72 34 580 88 197 25 31

A-16 1 0.75 58 520 20 180 31 29

A-17 1 0.69 6 500 90 180 30 38 A-19 1 0.75 15 290 120 30 74 70

A-21 1 0.73 22 600 160 150 25 24

A-08R1 2 0.71 19 680 525 380 23 24

A-10 2 0.75 50 440 210 300 21 23

A-22 2 0.74 24 340 50 330 23 29

A-07 4 0.75 36 350 57 23 90 55

A-18 4 0.72 15 460 90 210 12 11

A-20 4 0.74 54 617 124 86 45 56

Average 0.73 31 509 162 189 39 33

Minimum 0.67 6 290 20 23 12 11Maximum 0.75 74 860 600 400 90 70




Slide 65

Mini-Frac AnalysisK-25U Sand

K-25U SandsFault Closure Fluid Net Perf Open % Perfs



A-02 1 0.75 38 680 140 920 14 20

A-04 1 0.75 41 659 144 65 53 92

A-06 1 0.76 48 490 290 710 16 33

A-13 1 0.73 38 540 105 30 79 72

A-15 1 0.73 53 785 67 43 43 54

A-16 1 0.75 39 620 10 160 33 41

A-17 1 0.73 33 650 140 130 36 45

A-01 4 0.73 17 425 233 118 40 37

A-05 4 0.76 27 430 110 40 82 77

A-07 4 0.70 18 550 210 30 79 49

A-18 4 0.68 20 400 10 500 18 17

Average 0.73 34 566 133 250 45 49

Minimum 0.68 17 400 10 30 14 17Maximum 0.76 53 785 290 920 82 92


Slide 66

Mini-Frac AnalysisK-20/22 SandsK-20/22 Sands

Fault Closure Fluid Net Perf Open % Perfs



A-02 1 0.71 36 804 90 425 21 21

A-04 1 0.74 32 537 167 58 57 50

A-06 1 0.78 31 510 60 140 36 42

A-12 1 0.74 14 402 24 80 48 44

A-13 1 0.72 54 859 55 96 44 54

A-15 1 0.73 47 780 66 64 43 54

A-16 1 0.77 56 620 80 360 21 36

A-17 1 0.76 47 520 60 140 34 43

A-19 1 0.75 81 1000 80 30 86 81

A-21 1 0.76 41 660 60 210 30 45

A-08R1 2 0.75 22 505 140 475 20 24

A-10 (1) 2 0.70 49 1100 50 400 19 17

A-10 (2) 2 0.72 36 1210 600 450 19 17

A-22 2 0.72 20 470 90 50 56 70

A-01 4 0.71 43 1020 565 370 22 33

A-03R1 4 0.76 35 530 93 127 38 46

A-05 4 0.75 56 750 40 240 28 41

A-07 4 0.75 51 485 269 766 16 23

A-18 4 0.74 36 570 20 350 13 16

A-20 4 0.73 37 629 100 100 42 53

Averag e 0.74 41 698 135 247 35 40

Minimum 0.70 14 402 20 30 13 16Maximum 0.78 81 1210 600 766 86 81




Slide 67

Mini-Frac AnalysisI-Sands

I-SandsClosure Fluid Net Perf Open % Perfs

Well Interval Pressure Eff. Pressure Tortuosity Friction Perfs Open


A-11 I-1 0.63 15 360 780 1180 9 40

A-20 I-15 0.67 34 705 638 2112 5 18

A-05 I-85 0.69 19 320 990 1400 12 40

A-08R1 I-85 0.63 35 800 550 1675 6 18

A-10 I-85 0.69 22 430 600 550 17 70

A-16 I-85 0.69 56 430 0 200 22 81

A-19 I-85 0.63 62 970 690 1550 12 44 A-21 I-85 0.63 54 640 1210 1470 7 26

Average 0.66 37 582 682 1267 11 42

Minimum 0.63 15 320 0 200 5 18Maximum 0.69 62 970 1210 2112 22 81

-Sorted by Formation-Screen-Outs shown in Bold and Italic

Slide 68

Mini-Frac AnalysisL-SandsL-Sands

Closure Fluid Net Perf Open % Perfs

Well Interval Pressure Eff. Pressure Tortuosity Friction Perfs Open


A-15 L-10 0.78 77 850 101 424 17 26

A-18 L-10 0.77 84 950 80 160 34 43

A-15 L-30 0.75 59 1165 532 978 10 6

A-18 L-30 0.78 60 1200 90 60 50 63

Average 0.77 70 1041 201 406 28 34

Minimum 0.75 59 850 80 60 10 6

Maximum 0.78 84 1200 532 978 50 63

Angsi-A Fracture Campaign Summary China Trip__SINOPEC, 2006

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Transcript of Angsi-A Fracture Campaign Summary China Trip__SINOPEC, 2006