Total Well Perf AD Oct 28,07 Reveal (JRochon)

Jean ROCHON – Meridien Hotel - ABU DHABI - October 28th, 2007

Well Productivity/Stimulationand

Well Performance Enhancement Seminar

Jean ROCHON & Hughes POITRENAUD part 1

Laurent BRUNET & Vincent PEYRONY part 2

Jean ROCHON – Meridien Hotel - ABU DHABI - October 28th, 2007

Well Productivity/Stimulation and Well Performance Enhancement Seminar

_________Productivity & Reservoir – Part.1

Jean ROCHON & Hughes POITRENAUD

3

Productivity & PerformancePart. 1-1

- Jean ROCHON – Meridien Hotel - ABU DHABI - October 28th, 2007

Jean ROCHON

4 - Jean ROCHON – Meridien Hotel - ABU DHABI - October 28th, 2007

Content

Introduction

Productivity – Performance - Monitoring

ProductivityNear Wellbore Model for HQ WP teamExamples

Sensitivity to well completionComparison vertical frac/horizontal in TGR

PerformanceIntegrated modelExamples of integration

WTPL: a revolutionary tool for WP team


Well Performance Management

TOTAL has developed a formal transverse process called WELL PERFORMANCE MANAGEMENT

Objective: deliver maximum production at any timeAll disciplines involved in the Production process must participate

Well Performance Teams or Groups are in place in ALL affiliates

Process enforced by a Company Rule (CR FPO 320)

16 KPI’s defined


Ass

et Operations

DrillingCompletion Geosciences

TownWP Team leaderFacilitator

Well Performance Group

Planning

FieldWell & fieldOperations

Well works

Well PerformanceSuperintendant

HQ

HQ

Drilling & Wells

EXPLOITATION

Training Training cursuscursus of WPEof WPEAssignment coAssignment co--ordinationordinationFocal pointFocal point

Geosciences

Well Performance organisation

Well Performance Engineering and WP- R&D at HQ level is within D&W Division,

with cross posted engineers from all involved disciplines


Reservoir Engineering & Well Performance

Reservoir Engineering plays an active role in the Well Performance Group

Advanced flow modeling near the well

Definition of reservoir management requirements guiding the wellexploitation strategy

Evaluation of the properties of the formations near the well (saturations, permeability) and control of skin

Definition, implementation and analysis of monitoring actions for evaluating the pressures and their evolutions in the formations near the well


Part.1) Advanced Near Well Bore Flow Modeling: REVEAL

NUMERICAL SIMULATOR (Petroleum Experts) selected by TDO/FPL/EP to perform near well bore investigations or special well studies

4 PHASES (O,G,W, Steam/µ-emuls./foam/gel/polymer)

Data importation from ECLIPSE or VIP (with STARS via PETREL)

THERMAL & CHEMICAL EFFECTS ON MOBILITY

FRACTURING (Thermal/Hydraulic): finite-element fracture grid and stress calculation

TRACERS and STREAMLINES for (G,W,O)

Available links with GAP (or other softs) thru RESOLVE

• Viscosity (non-newtonian fluids)• Wettability and capillary desaturation• Wellbore heating

• Precipitation and adsorption• Φ & K reduction• Scaling risks, wax/asphalten deposits


REVEAL: EXAMPLE_1 Water Chemistry

945 days 2104 days 3405 days

Sulfate concentration in water

- Formation water contains barium and lot of calcium

- Sulfate from sea water will not reach oil producer before year 2014

- At that date, if no barium sulfate precipitation can be anticipated in bottom hole conditions (solubility constant), some calcium sulfate deposit could occur

(Congo field case)


REVEAL : EXAMPLE_2 TIF - Kioubloka (cube-low K)

0

10

20

30

40

50

60

70

0 1000 2000 3000 4000 5000 6000 7000 8000

Time (days)

Frac

ture

Hal

f-len

gth

(m)

Kic=1 psi.ft2Kic=10 psi.ft2Kic=145 psi.ft2

Xf: Frac half-length versus time

Acid gas injection (66%H2S, 33%CO2)

Qg= 2. 106 Sm3/d ; Tinj =40°C; Pini=350 bara@3730 m ; Tres=100°C

Gas is dense

Oil saturation

Temperature

Gas is cold

(Russia field case)


120 m

Injection rate: 15bpm for 70 minCumulative gel injection: 180 m335 lb X-link geldx=dy= 1 m (well)

21 mFracture width = 0.23’’

REVEAL : EXAMPLE_3 TIF – Hydraulic fracturing with gel & breaker

Even after 2 hours high polymer conc. in the frac and in the reservoir

bad and low cleanup

(China field case)


Example 4 - Choice ofcompletion type (1)

Number of Cells : 48749 cells(41 x 41 x 29)

Cells size (x, y) : 50 m

Number of layering : 29

PVT: Gas with few condensate

Sandstone formation

Press and Temp Initial 161 Bar and 63.2 °C

Layering REVEAL

1690

1695

1700

1705

1710

1715

1720

1725

1730

1735

1740

1745

1750

1755

1760

1765

0.001 0.01 0.1 1 10 100Permeability (mD), Porosity (%)

Dep

th (M

D)

Phi Core Kh Core Phi Reveal Kh Reveal

(Argentina field case)


Choice of completion type (2)

AP – 01 (5 subcases) Slanted type (± 86°)Without fracWith 2 or 3 fracs in direction XZ and YZ Perforation length : 1000 m

AP - 02Slanted type (± 82°)Without fracPerforation length : 506 m

AP - 02

AP - 01

AP – 01 F2 orth

AP – 01 F2 paralel

AP – 01 F3 paralel

Example ofsubcases

8 classes have been tested


Choice of completion type (3)AP – 03 (3 subcases)

VerticalWith (2 and 3) fracs and Without fractPerforation length 70 m

AP – 04Perforation length 1280 m

AP – 05 Perforation length 1310 m

AP – 06Perforation length 2470 m

AP-06 3D view

AP-06 side view

AP-06 top view

AP - 05

AP - 04

AP - 03



AP – 07Two fracsPerforation length 1230 m

AP – 08 Perforation length 3710 m

AP-08 3D view

AP-08 side View

AP-08 top view

AP-07



Cummulative Gas Production PredictionSensitivity 1 - kv/10 qnd kh/10

0

200

400

600

800

1000

1200

0 500 1000 1500 2000 2500 3000 3500 4000Days

Gp

(Msm

3)

0101 F2orth01 F3orth020303 F203 F3040506070801 Sens01 F3orth Sens02 Sens03 Sens03 F3 Sens04 Sens05 Sens06 Sens07 Sens08 Sens

Cum

ulat

ive

Prod

uced

Gas

(MSm

3)

Production time (days)

AP - 04AP-08 3D view AP-07 AP - 03 AP – 01 F2 orth


Example 5 - Vertical frac/horizontal in TGR (1)Gas Reservoir set-up

Considered Area : 2 x 2 km2 ; T =115°C; Pres= 195 bar3 sublayersLow permeability: total k*h geometric = 21 md*m

Porosity: #3%

(Algeria field case)


Vertical frac/horizontal in TGR (2) : Well TypeVertical & 3 Fracs

0

100

200

300

400

500

600

700

800

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25Date

Gas

Pro

duct

ion

Rat

e (1

000

Sm3/

D)

0

200

400

600

800

1000

1200

1400

1600

Cum

ulat

ive

Gas

Pro

duct

ion

(MSm

3)

Vertical_base caseVertical & 3 Frac-rectVertical & 3Frac-ellipse

•Vertical

•3 Rectangular fractures xf = 150 m

•3 Elliptical fractures xf = 150 m

wf= 5 mm = 0.2 “

Vertical & 3 Fracs & Dev80°

0

100

200

300

400

500

600

700

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25Date

Gas

Pro

duct

ion

Rat

e (1

000

Sm3/

D)

0

200

400

600

800

1000

1200

Cum

ulat

ive

Gas

Pro

duct

ion

(MSm

3)

Vertical_base caseDev80°_Drain=103 + 625 + 1186 mVertical & 3Frac-ellipse

THP = 80 bar

• Deviated 80°

•Lp # 1900 m

Lower production with a long near horizontal well without frac


Vertical frac/horizontal in TGR (3):Vertical fractured - Sensitivity to frac geometry

Frac Aperture Impact

0

100

200

300

400

500

600

700

800

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25Date

Gas

Pro

duct

ion

Rat

e (1

000

Sm3/

D)

0

200

400

600

800

1000

1200

1400

Cum

ulat

ive

Gas

Prod

uctio

n(M

Sm3)

w f = 5 mmwf = 2 mmwf = 10 mm

Fracture Length Impact

0

100

200

300

400

500

600

700

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25

Date

Gas

Pro

duct

ion

rate

(100

0 Sm

3/D)

0

200

400

600

800

1000

1200

Cum

ulat

ive

Gas

Pro

duct

ion

(MSm

3)

100 m50 m150 m

wf = 5 mm xf = 100 m

Frac Length impact Frac width impact


Vertical frac/horizontal in TGR (4):Vertical fractured - Sensitivity to proppant & frac damage

Frac Permeability Impact

0

100

200

300

400

500

600

700

800

900

11/01/05 11/01/07 11/01/09 11/01/11 11/01/13 11/01/15 11/01/17 11/01/19 11/01/21 11/01/23 11/01/25Date

Gas

Prod

uctio

nR

ate

(100

0Sm

3/D

)

0

200

400

600

800

1000

1200

1400

Cum

ulat

ive

Gas

Prod

uctio

n(M

Sm3)

Kf = 5 DKf = 10 DKf = 20 D

Pack permeability Beta Factor Impact

0

100

200

300

400

500

600

700

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25

Date

Gas

Prod

uctio

nRa

te(1

000

Sm

3/D

)

0

200

400

600

800

1000

1200

Cum

ulat

ive

Gas

Prod

uctio

n(M

Sm3)

Beta-factor = 0 bar.s2/gBeta-factor = 1.5 e-3 bar.s2/gBeta-factor = 4e-3 bar.s2/g

β- factor Fracture Skin Impact

0

50

100

150

200

250

300

350

400

11/01/05 11/01/07 11/01/09 11/01/11 11/01/13 11/01/15 11/01/17 11/01/19 11/01/21 11/01/23 11/01/25

Date

Gas

Pro

duct

ion

Rate

(100

0Sm

3/D)

0

200

400

600

800

1000

1200

Cum

ulat

ive

Gas

Pro

duct

ion

(MSm

3)

skin Frac = 0Skin Frac = 2Skin Frac = 10

beta-factor = 1.5 e-3

Frac skin

xf = 100 m, wf= 5 mm, Kf = 5 D, β = 1.5 e-3 bar.s2/g, fracskin = 2Gp # 1 BSm3


Vertical frac/horizontal in TGR (5):Highly deviated well without frac

Skin impact on well Dev80°

0

50

100

150

200

250

300

350

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25

Date

Gas

Pro

duct

ion

Rat

e (1

000

Sm3/

D)

0

100

200

300

400

500

600

700

800

900

Cum

ulat

ive

Gas

Pro

duct

ion

(MSm

3)

Dev80°_skin0Dev80°_skin2Dev80)_skin5

THP = 80 bar

• Impact of well damage skin

• Almost no impact of kv/kh

• But …

Gp # 0.75 BSm3


Vertical frac/horizontal in TGR (6):Highly deviated - Transverse Natural Fractures

Fissures Aperture

0

200

400

600

800

1000

1200

1400

1600

11/1/05 11/1/07 11/1/09 11/1/11 11/1/13 11/1/15 11/1/17 11/1/19 11/1/21 11/1/23 11/1/25

Date

Gas

Pro

duct

ion

Rat

e (1

000

Sm

3/D

)

0

200

400

600

800

1000

1200

1400

1600

Cum

ulat

ive

Gas

Pro

duct

ion

(MSm

3)

1mu10 mu100 mu1 mm

THP=80 bar

Drainage Area 4 km2

Damaged horizontal well skin = 2

Frac-Fissure Aperture sensitivity

(from 1 µm to 1 mm)

To be compared with Gp #1 GSm3For

Vertical 3 fracs


Vertical frac/horizontal in TGR (7):Conclusions

For the same production conditions (drainage area, THP)

Optimum values for the fracsxf # 100 m (300ft)wf # 5 mm (0.2”)

Low impact of Kf

Impacts of β , frac_skin (cake, embedment, crushing)

Horizontal well is interesting if natural fracs are intercepted or if it is multifractured (not presented here)

Moreover …. a lot of parameters can have a major impact on the productivity after fracturing process


Part.2) Performance – Integration (1): by using IPM suite

ECL is the TOTAL reference software for reservoir engineering

IPM package (Petroleum Experts) is a suite of software used by WP engineering

Reveal (reservoir)Prosper (well)Gap (lines network)Resolve (link between all kinds of software)

Go & Back between Eclipse and Reveal-Prosper for representing a complex well in a reservoir

Importation of ECL model into RevealAfter well design, exportation to ECL model of the inflow connection factors (Reveal) and of the outflow VFP (Prosper)


RESOLVE allows arbitrary software tools to be connected together

Can build a single system from a set of pre-modelled components

Possible components:Reservoir simulators (REVEAL, VIP, ECL?,...)

Material balance calculators (MBAL)

Nodal analysis solvers/optimisers (GAP)

Process simulators (HYSYS,…)

Financial packages/spreadsheets (?)

Anything at all – Word documents, reporters, etc…

Performance – Integration (2): Resolve software for coupling


Performance – Integration (3): RESOLVE architecture

RESOLVE

REVEAL

REVEAL

ECL

GAP

- Interface

- Data Transfer

- Data Validation

- Results collection and display

- File handling

- Timestepsynchronisation

- Advanced- scheduling by flexible script


Performance – Integration (4): Example 1

3 FFMs (#150,000 cells)==> 3 PC processors have been used for coupling

Field 1 Field 2 Field 3

(Angola field cases)

(RESOLVE, GAP and the smallest REVEAL model have been run on the same PC-processor )


Performance – Integration (5): Coupling 3 FFMswith 1 GAP model (Example1)

Reservoir1

Reservoir 2

Reservoir 3

FPSO

Water-Injection

Gas-Injection

Production

network

Other FFMs

not yet ready

One week-end for 20 years forecast


Performance – Integration (6): Example 2a

Mud line separation & boosting to the riser

Field 1

Field 3Field 2

36 km 18 kmFPSO

(Nigeria field case)


Performance – Integration (7): Example 2b

Gas lift at bottom riser pipes

TLP


Performance – Integration (8): Example 2 comparison

0

50000

100000

150000

200000

250000

03/12/200903/12/201003/12/201102/12/201202/12/201302/12/201402/12/201501/12/201601/12/201701/12/201801/12/201930/11/202030/11/202130/11/202230/11/202329/11/202429/11/202529/11/202629/11/202728/11/202828/11/202928/11/203028/11/203127/11/2032

SEP FOND GL Pied de Riser

Mudline separation

Gas lift at bottom legs


Performance–Integration (9): Integrated Models Benefits

To manage globally produced gas with respect to gas export constraints, gas injection constraints (Pfrac), etc … especially on multi-fields systems Critical issue as it can impact oil production (No Flaring policy)

To deal globally with water injection while meeting local voidagereplacement strategy

To manage different reservoir fluids PVT mixing

To promote inter-disciplines team work and lead to new ideas

To ensure consistency between each part of the system over time implicit data cross-checking

Finally, production and injection systems are optimized at each time step with consistent reservoir data


Performance – Integration (10): centric process

Integratedmodel

Reservoirinput

Network input

Economicinput

Processinput

New workingflow

New methodology: ‘’centric process’’

More interaction between peopleneeded at start-up

One set of hypothesisOne single model (simple or complex) One single profile for allusers

No iteration required

A change in one component>>> no impact on the other parts>>> re run the integrated model>>> new profile for all users

Less time consuming

Easier and faster approachfor new projects

Easier re-engineering ofmature fields


Performance – Integration (11): Use of coupledmodels : strong expansion within TOTAL …

0

1

4

9

0

1

2

3

4

5

6

7

8

9

10

2003 2004 2005 2006

Moho-Bilondo

DunbarLacqBloc32Akpo

UsanYukal PlacerBloc 17LussagnetMeillonBloc 32Moho-BilondoAkpo...


Part.3) WTPL: Principles of a new well test

-6

-4

-2

0

2

4

6

Time(s)

Flow ratePressure's variation

∆ϕ

∆Q

∆P

-6

-4

-2

0

2

4

6

Time(s)

Flow ratePressure's variation

∆ϕ

∆Q

∆PBH

Measurements of ∆P/∆Q and phase shift ∆ϕ

PLT coupled with a servo-controlled modulator for

generating periodic signal

Periodic rate Periodic pressure

⇒ Estimation of K & S


WTPL Investigation radius < 50 m

0

5

10

15

20

25

30

35

40

45

0 2 4 6 8 10 12 14 16 18 20 22 24 26

Period (min)

Inve

stig

atio

n ra

dius

(m)

1mD5mD

10mD

50mD

100mD

500mD

1000mD

Investigation is a function of variations period & reservoir diffusivity

WTPL is a near wellbore tool to monitor and analyze well productivity


WTPL: Data processing

PLT measurements @ station 17800 ft/RT

22

23

23

24

24

25

25

26

0 500 1000 1500 2000 2500 3000 3500 4000

Time (s)

rps

-5710

-5700

-5690

-5680

-5670

-5660

-5650

-5640

-5630

-5620

-5610

psi

SpinnermeasurementsPressuremeasurements

Production signal @ 17800 ft/RT

6700

6750

6800

6850

6900

6950

7000

7050

7100

7150

0 200 400 600 800 1000 1200 1400 1600 1800 2000

Time (s)

stbd

5645

5650

5655

5660

5665

5670

5675

5680

psi Flow rate

BHP

Periodic variations @ 17800 ft/RT

-400

-300

-200

-100

0

100

200

300

400

0 500 1000 1500 2000

Time (s)

stbd

-40

-30

-20

-10

0

10

20

30

40

psi Flow rate

BHP

Production carrying signals Periodic signals to be interpreted

Global recorded bottom-hole signals


Layer 1

Layer 2

Formation section influence

PLT station 1 PLT station 2

2stationPLT@

2stationPLT@

1stationPLT@

1stationPLT@

2layer

2layer

QP

QP

QP

∆

∆=

∆

∆+

∆

∆

K & S Layer 1Layer 2

totQQQ =+ 21Rate Conservation:

1stationPLT@

1stationPLT@

1layer

1layer

QP

QP

∆∆

=∆∆

Application to multilayer reservoir


WTPL on J-481: Reservoir scheme, PLT stations & Results

17841 ft/wl

18014 ft

18261 ft/wl

17901 ft/wl

PLT Stations

Layer A1

Layer B

Layer C

Layer A2

Well deviation # 20°

Investigation radius ~ 10m

kh = 713 md×ft / k = 17.8md

S = -1.8

kh = 877 md×ft / k = 43.8 md

S = -1.7

kh = 450 md×ft / k = 15.0 md

S = -2.5

(Argentina oil producer)


Validation using PIE multilayer model

Jusepine J481 WTPL

0. .10 .20 .30 .40

-400

.0.

200.

T im e (hours)

rates

STB

/D

Jusepine J481 WTPL

0. .10 .20 .30 .40

-10.

10.

30.

50.

pres

sure P

SI2004/11/03-1229 : OIL

Three-Layer Reservoir with Cross-Flow** Simulation Data ** well. storage = 0.000648 BBLS/PSI Skin(1) = -1.80 Skin(2) = -1.80 Skin(3) = -2.59 permeability-1 = 17.8 MD permeability-2 = 43.8 MD permeability-3 = 15.0 MD Omega(1) = 0.327 Omega(2) = 0.268 Lambda(1) = 0. Lambda(2) = 0. Perm-Thickness = 2010. MD-FEET Initial Press. = 28.6700 PSI

Type-Curve Model Static-DataLayer-1 Thick. = 30.0 FEETLayer-2 Thick. = 20.0 FEETLayer-3 Thick. = 40.0 FEET

Static-Data and ConstantsVolume-Factor = 2.409 vol/volThickness = 90.00 FEETViscosity = 0.1700 CPTotal Compress = .1368E-04 1/PSIStorivity = 0.0001081 FEET/PSIDiffusivity = 28860. FEET^2/HRGauge Depth = N/A FEETPerf. Depth = N/A FEETDatum Depth = N/A FEETAnalysis-Data ID: DATABased on Gauge ID:


WTPL: Well Testing Production LoggingREVOLUTIONARY tool for reservoir and production engineers

From short test, Estimate permeability and skin in the near wellbore area

Along the well without packer (multilayered reservoir)

For all kind of completed wells (O/G producers, W/G injectors), everywhere where a PLT is representative

Without stopping the production

No need of rate history

Low influence of measurement errors

Small rate variations avoiding fluid redistribution and cross-flow impairment when shutting-in

DEVELOPMENT BY TOTAL WITH SONDEX and HALLIBURTONCommercialization mid 2008


END of Part 1-1

Thank you for your attention



BackUp WTPL

BACK UP


Long horizontal drain: Well capacity

Layer 2Layer 1

R1 et R2’ R2

1

021

11−

⎥⎦

⎤⎢⎣

⎡−+= ωVic

RRR tot

Big volume of fluid betweenproducing intervals

Volume of fluid

c,V

ωVicZ 0

0

1=

2

1R1

1R

Measurement

totR1


Well Aspect: Horizontal Well application

00.050.1

0.150.2

0.250.3

0.350.4

0.450.5

kv/kh

1 2 3 4 5

Case

Real and estimated anisotropy ratio

Real kv/kh

kv/kh from T0

Average kv/kh

For an horizontal well in an anisotropic reservoir (kh known):skin and kv/kh estimation

-5

0

5

10

15

20

Skin

1 2 3 4 5

Case

Real and estimated skins

Real Skin

S from T0

Average S


Well Aspect: Hydraulic Fractured Well application

Formation Permeability supposed known : Frac conductivity estimation

Fracture 1 Fracture 2 Fracture 3 Fracture 4FCD 10 1 1 0.1Formation permeability 1 1 10 1Half Length 150 150 50 150Conductivity 1500 150 500 15

0

200

400

600

800

1000

1200

1400

1600

m.md

1 2 3 4

Fracture

Real and Estimatred Fracture Conductivity

Real Conductivity

Estimated Conductivity


Average Pressure Estimation

If well drainage area is known, Production Index (PI) could then be derived from K and skin

Average Flowing Pressure (PF) and Average bottom hole Flow Rate (Q) could be estimated

Finally Reservoir Pressure (PR) could be simply computed as :

PR = PF + Q / PI

Documents

Total Well Perf AD Oct 28,07 Reveal (JRochon)