Wells Dynamic Simulation With OLGA Perth Techint 2010

1

Introduction to Wells Dynamic SimulationUsing OLGA

1

Juan Carlos ManteconAdvisor SPT GROUPLevel 1, 234 Churchill Avenue Subiaco East, W.A. 6008 Australia phone +61 (8) 9286 6500 mobile +61 (0)401 694 182

[email protected]

Wells Dynamic Simulation

• Well flow assurance key areas• Differences between wells and pipelines• OLGA well module• Data input requirements• The importance of IPR, PI and Skin• The importance of WHT calculations• Heat transfer mechanisms in wells• Well Dynamic Simulation Applications

– Artificial Lift: Gas Lift, ESPW ll Cl

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– Well Clean-up– Well Testing– The Virtual Gauge– Well Control

• The importance of Integrated Modelling• Real-Time Production Management

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Common Approach in Pipeline Modelling

Fixed Outlet Boundary

SOURCE-1

SOURCE-2 SOURCE-3

Inflows are modelled as SOURCE with Fixed Inlet Conditions –Constant Mass Flowrate, T (& P). Flowrates, T & P are usually

provided by Reservoir and Well Engineers based on IPR curves.

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A SOURCE does not represent reservoir inflow behaviour. A WELL is required to proper model inlet boundary conditions

Traditional simulations

DeDe--coupledcoupledTwo departments

• Flowline simulations

(Facilities Engineering)

• Well simulations

(Production Technology)( ) – Transient simulations

– OLGA– Fixed inlet condition

(Template P or GT)

(Well Engineering)– Steady-state– Prosper,– Pipesim,– WellFlow,

– etc.4

3

Disadvantage

• Not able to model the dynamic effects occurring De-coupledDe-coupled

Traditional simulations

y gin a well - flowline system during startup, shutdown and low rate production

• Well – Flowline – Riser interaction is not taken into account

• Slug catchers and separators have beendesigned based on only the flowline volume

• Any restrictions in the well or flow assurance problem may have not been considered

• Slugging generated in the well has not been considered

5

...

6

4

Well Dynamic Modelling

IPRIPR7

Advantage


• Longer wells, horizontal and even sinusoidal wells could be major contributors to unstable flow (NODAL Analysis do not handle terrain induced slugging).

Simulations with Reservoir influx at inlet boundarySimulations with Reservoir influx at inlet boundaryInclude the wellhead choke at templateInclude the wellhead choke at templatePressure, separator, e.g. at outlet boundaryPressure, separator, e.g. at outlet boundary

IPRIPR

• Slugging etc. should be investigated taking the wells into account (from the reservoir to the treating facilities)

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5

Advantage


• Tubing sizes based on dynamic well simulations, not only steady state – SS-> incorrect results, specially for low GOR and flow assurance

Simulations with Reservoir influx at inlet boundarySimulations with Reservoir influx at inlet boundaryInclude the wellhead choke at templateInclude the wellhead choke at templatePressure, separator, e.g. at outlet boundaryPressure, separator, e.g. at outlet boundary

IPRIPR

• Wells are not different from flowlines+risers in principal! Slugging can occur…...

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Relevance

• New technology trends: Production

Well Modelling

– Longer wells

WaterInjection zone

Separator

Productionzone

– Smart wells– Production from multiple zones– Multi-lateral wells

– Complex wells

• Demand for downhole monitoring (P, T gauges, flow meters) AND OLGA® Well simulations ☺

– Pumping– Downhole separation

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6

Multibranch flowCounter current flowGaslift

Multiphase wellbore flow – TransientsWell Dynamics

Stagnant mud

Liquid accumulation

Reservoirinteraction

Slugging & surges

Well Design & Operation Based on Modelling of Life-Cycle Scenarios • Life-Cycle Modeling of Well Completions (Multi-Lateral, etc.)• Effect of Well Position/Trajectory & Length• Effect of Pressure and Temperature• Transient and Steady-Sate Effects

Modeling: Optimum Well Design and Operation

Transient and Steady Sate Effects• Well Operability Limits• Well Integrity

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7

Well Flow Assurance – Life Cycle

What make a well different from a pipeline

• Well Completion– Geometry (multi-lateral, multi-layer, etc)– Complex Walls (tapered concentric pipes

with annular fluids/cement in soil)with annular fluids/cement in soil) – Lift & Control Equipment (SSSV, ICV, etc.)– Annular Fluid Production/Injection

• Reservoir-pipeline-network-riser interaction• Thermal effects

– Slower well transients, usually days or weeks (True SS temperature may take months to reach)

Reservoir

(True SS temperature may take months to reach)– Counter current heat transfer effects if injecting

fluids through well annulus– HPHT

• Higher ΔP-T – Flow Assurance Issues• Drilling fluid

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• Standard OLGA – Simple well inflow (source or PI)

Production tubing with walls and formation

Wells in OLGA

– Production tubing with walls and formation

• Well Module– Annular flow– IPR models– Drilling Fluids– Non-Newtonian fluids– Non-Newtonian fluids– Quasi-dynamic Input– Workovers Simulation (Fluid displacement) – Underbalanced Drilling Simulation

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What the Well Module adds to OLGA?

• Annulus key– Allows for modeling multiphase flow through the annulus – Gas Lift,

Well tubing-annulus circulation, workovers, well control, kill, etc.– Well Integrity - Increase in Annular P-T when fluids are trapped

(subsea wells with no annular venting) during well start-up(subsea wells with no annular venting) during well start-up– Counter current heat transfer effects if injecting fluids through annulus

• IPR (Inflow Performance Relationship)– Define the rate-pressure relationship (well-reservoir interaction) for

specific reservoir properties (P, T, Permeability, Skin, etc.)– Define the multiphase flow (G, O and W) rates entering the wellbore

model from the reservoir boundary – it is like a source defined by the IPR selected equation (Forchheimer, Vogel, etc.)

– 2 Options: Steady Sate IPR or quasi-dynamic IPR (P-T and reservoir– 2 Options: Steady Sate IPR or quasi-dynamic IPR (P-T and reservoir properties changing with time) input

• ROCX (Optional – no part of the Well Module)– Near-wellbore reservoir simulator that can be fully connected (implicit)

with OLGA to improve the modelling of the well-reservoir interaction effects

– OLGA can be connected (explicit) with other reservoir simulators (Eclipse, VIP, MoRE, Chears, etc.)

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What the Advanced Well Module adds to OLGA (cont.)?

The interaction between the near-wellbore reservoir and the well can play a dominant role in the description of the dynamic

behaviour of the complete system

Q (t) P (t) Q (t) P (t) Q (t) P (t)

OLGA Multiphase Flow Transient Simulator



Q (t) P (t) Q (t) P (t) Q (t) P (t)

Transient Reservoir Model ROCX

Steady-State Reservoir Parameters Explicit Input

Quasi-Dynamic Reservoir Parameters Explicit Input

Dynamic - SS Dynamic – Quasi-D Dynamic – Dynamic

OLGA-for-Wells OLGA-for-Wells OLGA-for-Wells + Rocx

What the Well Module adds to OLGA (cont.)?

• Drilling Fluids– Allows for the addition of fluids other than the reservoir

(production) fluids – drilling muds, well completion brines, diesel etcdiesel, etc.

– Input drilling fluid at initial conditions and/or as a source– Required in well clean-up modeling

• Underbalanced Drilling– Allows for the addition of the bit and rate of penetration (ROP)– Normally tubing length do not change with time when the well

is completed but it does during drilling (ROP)is completed but it does during drilling (ROP)– UBbitTS provides a GUI specifically design

for modelling drilling operations with OLGA– Drillbench is another SPT GROUP software

option for drilling operations – designed for Drilling Engineers

– ABC is Drillbench+OLGA for blowout control

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1 D - Well Dynamic Simulation

100m - 2 pipes - 8.861" 160 m MODU ID WallP13 P12

P11 8.861" Wall Riser-air130 m Sea Level

P10 8.861" Wall Riser-seaOlga 0 m SS Tree 7.0625"

Wellhead 6.25"Riser P9 6 184" Wall 1

Well XX14 - OLGA Wellbore Model

-3500

-3000

-2500

-2000

-1500

-1000

-500

0

-3500 -3000 -2500 -2000 -1500 -1000 -500 0

Well Profile (MD-TVD)

Well bore Schematic with Equipment

Riser P9 6.184 Wall 170 SCSSV 6.25"

WellboreP8 8.861" Wall 70

345 m 20" Csg shoe

P7 8.861" Wall 3451100 m TOC

P6 8.861" Wall 11001950 m Mandrel 6.18"

P5 6.765" Wall 19502000 m Nipple 5.75"

P4 8.681" Wall 20002100 m

Steel

Cement

Formation

MD 2766.1 m

MD 1432.2 m

Wall 1

Wall 2

Wall 3

W ll 4

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1 2 543

1 2 543

1,2,3,…,5 (inside) : section volumes

1,2,3,…,6 (outside): section boundaries

6

P3 8.681" Wall 21002850 m

P2 6.184" Wall 28503000 m

P1 6.184" Wall Reservoir3050 m

P, T Q

Section Length < 50mSPE 109829

Wall 4

Standard Data Requirements

C i T bi d Ri /Pi li t

Well Modelling – Input Requirements

• Casing, Tubing, and Riser/Pipeline geometry– Inner diameter– Wall roughness– Walls thickness– Walls material type– Wall materials thermal conductivity, density and

heat capacities

Well Schematic

p– Soil temperature, conductivity, density and heat

capacity– Well deviation profile– Relevant equipment locations (i.e. SSSV)– Flow Restriction Locations (i.e No-go Nipple) 20

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• Valves Details (SSSV, GLV, Adjustable Chokes, etc.) – Type of valve and Internal Diameter– Fully open CV of all valves used in simulation– Closing and opening times– PSV set pressure

• Equipment detailsq p– Type of equipment (i.e. downhole gauge)– Location and internal diameter of any restriction

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• Environment (Boundary Conditions)– Maximum & minimum air temperatures– Maximum & minimum seawater temperatures– Maximum & average wind speeds– Maximum & average subsea current strengths– Sea temperature and current velocity profiles from

surface to mudline if a riser is part of the model– Soil (rock) type and temperature gradient

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• Surface Boundary Conditions– Pressure, temperature and fluid (if flow is reverse)

• Bottom Boundary Conditions– Reservoir properties (skin, permeability, etc) or PI,

and Pressure, Temperature conditions

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– Constant Productivity IndexForcheimer model

IPR models in OLGA®Wellhead Boundary

P=f(t)

T=f(t)

Wellbore – Forcheimer model– Single Forcheimer model

(High Pressure Gas Wells)– Vogel equation– Backpressure equation

(Gas Wells)– Normalized Backpressure

(Saturated Oil Wells)– Tabulated IPR curve Reservoir

B d

Wellbore Dynamic Model

SSSSHeat Transfer to surrounding media

– Quasi-dynamic reservoir explicit input k-h, s, nD-s, P, T time series

– Dynamic Nearwellbore Reservoir OLGA-ROCX

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Boundary q=PI*dP f(t)

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Reservoir Boundary

• Straight line IPR (Radial inflow performance – steady state) equation:

Srr

PPBkq

w

e

bhs

oo

oo

h

'

Re

43ln

00708.0 )(+−⎟

⎟⎠

⎞⎜⎜⎝

⎛

−=

μ

Permeability (md) Net pay (ft) Average Reservoir Pressure (psi)

Flowing Bottom Hole Pressure (psi)

Formation VolumeViscosity (cp)

Total SkinTurbulent non-Darcy skin

Mechanical damage skin

25

PPq

wfR

o

−=PI Index,ty Productivi

Drainage Radius (ft)Wellbore radius (ft)Formation Volume

Factor (rb/stb)Viscosity (cp)

qo= PI (PR - Pbhwf)

IPR Models in OLGA

LINEAR• Production of a typical oil

VOGEL• Traditionally used for oil wellProduction of a typical oil

reservoir• Undersaturated oil wells• Oil wells with Pfbh > Pbp

• Oil wells with HWOR• Oil wells with limited

drawdown• Water wells and water injection

wells

Traditionally used for oil well performance in saturatedsaturated oil reservoirs

• For solution-gas-driven reservoirs when the reservoir pressure is at or below the bubblepoint pressure (undersaturatedundersaturated)

• Best-fit approximation of numerous simulated well

• First estimate when the production curve for the well is not properly defined

• General equation:qo = PI (Pres – Pfbh)

numerous simulated well performance calculations

2

max

8.02.01 ⎟⎟

⎠

⎞

⎜⎜

⎝

⎛−⎟

⎟

⎠

⎞

⎜⎜

⎝

⎛−=

pp

pp

qq

res

fbh

res

fbh

o

o

Maximum oil rate (absolute open flow, AOF) when Pfbh=0 26

14

IPR Models in OLGA

FORCHEIMER• Quadratic form of the BACKPRESSUREQuadratic form of the

relation between inflow and drawdown

• Can be used when a full production curve can be estimated and a constant PI is not applicable

• Usually used for gas reservoirs

BACKPRESSURE• Normally used for gas wells

NORMALISEDBACKPR• For saturated oil wells

( )nwfr PPCQ 22 −=

SINGLEFORCHEIMER• For high pressure gas wells

with limited drawdown

TABULAR• User specify the IPR curve

using the TABLE keyword• DELTP vs. FLOW, GASFL,

LIQFL, PILIQ, WATFR, OILTC, GASTC, WATTC 27

Reservoir Boundary

Two ways of specifying data for flow between reservoir and well (Production/Injection):reservoir and well (Production/Injection):

1. Specify the coefficients (PI) used in the IPR directly

2. Specify traditional well/reservoir variables like permeability and net pay. These variables are translated into the coefficients (PI) used in the IPRtranslated into the coefficients (PI) used in the IPR.

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Parameters in IPR Models

• Net pay (*)– Net oil/gas producing reservoir height.

• Permeability (*)– A meassure of the porous rock ability

to conduct fluid.

• Hole size– Wellbore diameter.

(*) can be input as time-series

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Parameters in IPR Models

• Turbulent non-Darcy skin (*)– Accounts for the additional pressure drop in the near

llb i d t hi h l itwellbore region due to high gas velocity.– Input number should represent all rate dependant effects

• Mechanical damage skin (*)– Accounts for reduced permeability in the near wellbore

region due to particles from the drilling mud plugging some pore spaces around the wellbore or completionsome pore spaces around the wellbore or completion restrictions.

– Input number should represent all mechanical skin effects (partial penetration, deviation, gravel pack, etc.)

(*) can be input as time-series30

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Mechanical Skin

Situation Typical SkinBadly damaged or partially completed well +20 – +500Damage well +2 – +20Good initial completion – unstimulated +2 – -1

Lightly acidised 0 – -2Deviated well -0.5 – -3N t l f t ll d f 3 5Natural fractures or small propped frac -3 – -5Large frac in low permeability reservoir -5 – -6

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Parameters in IPR- models

• Reservoir extension – Represents the outer

boundary of the reservoir.

• Maximum flow rate– Maximum oil rate when wellbore flowing

pressure equals zero.

• Free Water cut (*)– Amount of water to be added to the amount

provided by the fluid file

(*) can be input as time-series32

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Reservoir Boundary

• The reservoir can be divided into multiple zones with differences in properties and IPR modelsdifferences in properties and IPR models

• Properties can be defined as time series (well’s life cycle) for each zone:– Reservoir pressure– Reservoir temperature– Gas fraction / GOR– Water fraction / Water cut– Skin– Non-Darcy Skin

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Well Module

34

18

Well Module

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Vogels

36

19

Forchheimer

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Backpressure

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Well Module

Use of Annulus keyword

• Each branch defined as normal with internal diameter and wall thickness– Tubing branch wall: only tubing thickness– Annular branch wall: casing thickness and

all other external concentric pipes and annular materials + soil (15-25m)

• The annulus keyword is used to define annulus configuration, and the hydraulic diameter is calculateddiameter is calculated

• Note that all pipes used for the annulus keyword have to be defined with the same section lengths

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Well Module

Annular flow

• In annular flow there will be a higher wettedIn annular flow there will be a higher wetted surface area compared to the flow area

• In OLGA a single pipeline with corresponding flow area is assumed

• The wall interfacial friction is calculated based on a hydraulic diameter, Dh:

tch D - DS

4A D ==

40

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The Importance of WHT CalculationsHeat Transfer System Topology

Interval - 1Interval - 1

Interval - 2

Interval - 3

Interval - 4Interval - 5

Interval - 6

Interval - 1

Interval - 2

Interval - 3Interval - 4Interval - 5

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Completion with 7 heat transfer intervals Completion with 6 heat transfer intervals

Interval - 7 Interval - 6

Heat Transfer Mechanisims in Wells

ConvectionConvectionwithwith airair

ConvectionConvectionwithwith waterwater((subseasubsea))

ConductionConductiontowardstowards soilsoil

42

22

OLGA® for Wells Thermal Model

ProductionGas lift

4

Convection

Conduction

Radiation in annulus (Minor Effect)

1

2

34

Te

TFluid

43

1. Counter-current heat transfer2. Radiation, convection and conduction in gas filled annulus3. Conduction and convection in drilling mud4. Conduction in steel, cement and formation

Warm-up of Well and FormationOLGA® for Wells Thermal Model

SS conditions ifi d

t0 t1 t2 t3 tss

Tem

pera

ture

Distance from Wellbore

are verifiedP-T profiles can be input as correlations in SS Software

44

Temperature

Dep

th

Wel

lbor

e

23

Heat Conduction and Storage

• Heat conduction and storage in the formation is always a t i t er

atur

e

Formation warm-up processdue to production

transient process– i.e. an infinite-acting

process• Then the question becomes

how thick the soil “layer” should be

ture

tu

re R2

Tem

pe

Distance from wellbore

Temperature

th

t0 t1 t2 t3 tss

t0 t1

t2 t3

tss

45

Tem

pera


t0 t1

t2 t3

tss Tem

pera


t0 t1

t2 t3

tss

R1

Wel

l Dep

tReservoir

Tubi

ng

Ann

ulus

Cas

ing

Cem

ent

Flow

ing

Flui

ds

TLarge influence in wellhead temperature

Formation Radius re:

Choose the right formation thickness

rti

r

Tf

TeTw

Large influence in wellhead temperaturepredictions for shutdowns

Minor effect on production rate prediction

Upper limit should be based on the rto rci

rcorw re ?

‘drainage area’ of the well

46

24

Wells Warm-up and Cool-down

• Heat propagates very slowly into the formation– Starting a shut-in from thermal steady state is often wrongStarting a shut in from thermal steady state is often wrong

• Cool-down is also a very slow process– The no touch time can be very long– The SSSV is often at a very conservative depth

• In order to obtain correct results– Determine if the well has operated long enough to be at

“steady state”If not run a simulation for the period which the well has– If not, run a simulation for the period which the well has been operating to get the correct starting point

47

Tubi

ng

Ann

ulus

Cas

ing

Cem

ent

Form

atio

n

Flow

ing

Flui

ds


rti

Tf

TeTw

ti

rto rcirco

rw

( ) ( ) ( ) ( )⎥⎥⎦

⎤

⎢⎢⎣

⎡+++++

Δ=−

e

we

cem

cow

c

cico

ancit

tito

ftief k

rrk

rrk

rrhrk

rrhrL

qTT /ln/ln/ln1/ln12π

What Formation Radius Should We use?

48

25


e

• The formation temperature profile should give a zero derivative at its tail if a enough thick formation is included

• As a rule-of-thumb, a thickness of 15~25 m should be good enough for most of the cases for transients in the order of d d 25 50 f

Tem

pera

tur


0≈drdT

The thickness of the formation layer

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days and 25~50 m for transients in the order of month

The thickness of the formation layeris big enough if a temperature profile as the red curve is observed.

Vertical Geothermal Gradient

• Vertical geothermal gradient is approximately 1.8~3.6 ºC

100 tper 100 meters– For example, knowing

seabed temperature is 4 ºC, the reservoir temperature at 2000 meters should be about 64 ºC

• The figure also qualitatively shows the production and injection (e.g. cold water)

Temperature

Production

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injection (e.g. cold water) fluid temperature profiles along the wellbore

Wel

l dep

th Injection

Formation

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Warm-up of Well and FormationWell Integrity

_ _ _ _ _ , [ ],160

Warm-up Effects on Annulus (Trapped Fluids)

Packer

C

155

150

145

140

51

135

130

Length [m]40003500300025002000150010005000

60/120MMscfd – Annular Temperature Profile Comparison

Wellhead


_ _ _ _ _ [p ]12000

11000


Packer

12060

psia

10000

9000

8000

7000

6000

5000

4000

Wellhead

12060

PackerPacker

52

60/120MMscfd – Annular Pressure Trends at the Packer & Wellhead

3000

2000

1000

0

Time [h]2520151050

WellheadWellhead

27



53

System Integrity – Mechanical Forces

• It is not enough to look at SS conditions when designing or troubleshooting oil and gas flow systemsystem

• The most common transient situations imposing mechanical forces that can result in momentary over-pressurization, physical deformation and movement are:– Closing and opening valves

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Closing and opening valves– Localized occurrence of liquid flashing and

condensation

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Well Integrity – Valve Shut-in – P-T effects

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Temperature Transient Peak After Valve Shut-in

Well Integrity – Valve Shut-in – P-T effects

Time about WHT

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Temperature Transient Peak as Function of Valve Closing Time

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Drilling Hydraulics

Cleanup

Well Testing

Artificial Lift

Liquid Loading and GWD

Completion Design

Annulus Pressure Management

Erosion

Corrosion

Equipment Integrity

Temperature

Leak Detection

OLGA 4 Wells Applications

Horizontal & Multilaterals

Well-Pipeline Interaction

Well-Reservoir Interaction

Injection

CO2 Storage

SAGD

Well Control

SPE 109829

Hydrate

Heavy Oil

Wax

DST

Online/Offline Soft Sensing

Water Monitoring

PLT - DTS

• Flow stability, maximum production rates – Optimize tubing size– Well completion design

• Flow assurance, wax, hydrates

Multiphase wellbore flow – Operational phaseWell Dynamic Simulation Applications

– Optimize inhibitor injection• Cross-flow / merged fluid streams

– Multilateral, Multilayer wells– Smart wells

• Well clean-up– Mud removal efficiency

Mi i l t– Minimum clean-up rate• Well testing

– Test procedure & data optimisation– Segregation, after-flow effects– Virtual gauge and flowmeter

• Well control / work-over evaluation

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• Artificial lift design and optimisation– Gas Lift injection– Unloading, flow stability

Compressors shut down

Multiphase wellbore flow – InterventionWell Dynamic Simulation Applications

– Compressors shut-down– ESP sizing

• Injection– WAG - water alternating gas injection– Steam and or CO2 injection

(Single Component Module)– Water injectionj– Gas, N2, etc

Flow Stability

• Is the flow going to be stable?• What’s causing slugging flow?What s causing slugging flow?

– Terrain induced? Well horizontal section?– Upwards-downwards slopes liquid accumulation?– Low pressure, Rate change? ID changes?– Riser induced? Low Flow Rate? Low GOR? – Condensate? Low liquid velocities?– GL injection? Compressors? Well Interference?

• Where the slugs are originated?• What’s the size of the slug and frequency?• How slugging flow can be eliminated/mitigated?

– Tubing size reduction– Back pressure increase?– Gas injection? Where? How much?

6060

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Water Accumulation and Corrosion

• Is there water condensation? What depth?• Is water as a film in contact with pipes and equipment?

• Is water as a film in contact with pipes and equipment? Where? How long?

• Is corrosion inhibitor being injected? What’s the concentration along well?

• Where (location) it is more likely that corrosion problems may occur?

• Corrosion rates? – Corrosion moduleNORSOK M d l

Vapor Water Droplets Water FilmGas Oil Droplets Oil Film

– NORSOK Model– De Waard 93 and 95 Models– Top of Line (IFE)

Wax and Hydrates

• How deep from the wellhead the well will experience hydrates-wax problems? When?

• When the pipe wall temperature falls

Hydrates

• When the pipe wall temperature falls below WAP (wax appearance temperature)

• What’s the predicted hydrate dissociation temperature profile? How far the conditions are from hydrate formation? Where? When?

• What’s the best solution for the well flow assurance problems?assurance problems?– Pressure Control, Temperature Control– Remove supply of water – Hot-cold re-start– Flowline depressurization– Insulation, inhibitor injection? Where?

When? How much?

Hydrate curves- Gas-Condensate with WC 10%

0

50

100

150

200

0 10 20 30T (C)

P (b

ara)

0 MEG10 % MEG30 % MEG40 % MEG

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• GL – Is GL injection stable?– Annular heading? GLV choke size? Compressors?– Density wave instability? Reservoir? Horizontal well?

Artificial Lift Design and Production Optimisation

– Multi GLV design? Single injection point?– Deepwater GL injection line? Liquid injection?– Riser instability? Riser GL?– Optimum amount of gas lift gas?– GL Well unloading? Compositional tracking?

• ESP – Which are the conditions at ESP depth?

GLGL

63

– Slug Size (free gas volume)? Slug frequency?– Optimum setting depth to improve pump Ev?– Optimum pump size to improve pump Ev?– Liner-Tubing-Casing optimum ID?– Optimum ESP design & operating conditions?

ESPESP

Modelling concerns:

Typical Gas Lift Well Optimisation

b) Annular Flow

c) Heat Transfer

d) Non-constant Composition in Tubing above Injection Point

e) Injecting dry gas?

a) Cause of Unstable Flow

Casing

Tubing

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Gas Lift is clearly a transient problem

NODAL analysis do not capture the transients that inevitably occur in an operating GL well

Production

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Longer Gas-Bubble Arriving at ESP Inlet

ESP - Sinusoidal WellsTrajectory Design to Reduce Instability SPE 109262

Liquid Slug

Shorter Gas-Bubble Arriving at ESP Inlet(1) Original Trajectory

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Liquid Slug

(2) Improved Trajectory: Higher Entrance Angle and half amplitude

Shut-in / start-up

• What’s the watercut limit for which the well will not kick off after a shut-in?

• Any future kick-off problems? • When liquid loading will kill the well? • When GL injection is required?

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Watercut Limit

• Increased accuracy in settled water holdup profile results in better calculation of bottom hole pressure

• As reservoir pressure declines and water-cut increases, naturally flowing wells often require artificial lift to ‘kick-off

• The shut-in water-cut limit is usually lower than the natural flowing water-cut limit due to fluid segregation effects in the wellbore under static

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conditionsWanaea #7 - FTHP = 700 psia

28

36

44

52

62

0

10

24

32

38

0

10

20

30

40

50

60

70

2700 2900 3100 3300 3500 3700

Reservoir pressure [psia]

Wat

ercu

t [%

]

Steady state Kick-off

Crossflow / Commingling fluids

• Is there any crossflow between productive layers at static conditions?– While producing? During shut-in?

Zone 1

ShaleWhile producing? During shut in?• Are very different fluids merging?

– multi-lateral, multi-layer completions• Are there significant T-P differences

between bottom and top layers?• What will be the WHT effect if the

hotter bottom layer production is favoured?

Gas

Water

Shale

Zone 3

Oil

Perf

orat

ions

Cross Flow(potential)favoured?

• What will be the fluid composition and P-T resulting from different production rates, WC and GOR, from each layers?– Smart completion?

(potential)

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• What’s the effect of water accumulations on the slugging flow conditions?

• What’s the effect of multiple production zones th t t l il/ / t t ?

Horizontal Wells / Smart Wells Solutions

on the total oil/gas/water rates? High GOR from heel? High Wc from toe?

– Reasonable number of inflow points required– Matching production logs and DST– Gas/Water sources (Gas/Water coning)

• What ICV opening combination will provide the

0.8

0.9

1.0

69

best clean-up/unloading results?• What ICV opening combination will provide the

best total production optimisation results?• What completion design will provide the

best clean-up and total oil rate?

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

1 2 3 4 5 6 7 8 9 10

ICV ID

ICV

open

ing

(-)

Well Clean-up

• What’s the minimum rate required to clean-up the well? How long is going to take?

• Clean-up to the MODU or to the FPSO?

• Can we unload the well to a production fluid filled line? Would GL be necessary?

• Would flowline dewatering be required?

G Lifti l th i (Ri GL) ld l

70

• Gas Lifting only the riser (Riser GL) would solve the problem?

• How long I’ve to wait to take clean fluid samples? If I was injecting Inhibitors?

36

• An ESD at max fluid density (well/riser) would create unloading problems when restarting?

Well Clean-up

• What’ the effect of multi-layers inflow?

• What’s the worst case scenario?

• What completion design will provide the best clean-up?

71

• Well Integrity with fluids trapped in annulus? What’s the P-T increase in the annulus when opening the well and heating-up the wellbore?

Well Clean-up Solutions

30 MMscfd – Purple25 MMscfd – Light Blue20 MMscfd – Green15 MMscfd – Black10 MMscfd – Blue5 MMscfd – RedDowhnole shut-in at 60 minSurface shut-in at 65 minutes

72

Gas Arrival Times vs. Gas Rate

37

Well Clean-up Solutions

30 MMscfd – Purple25 MMscfd – Light Blue20 MMscfd – Green15 MMscfd – Black10 MMscfd – Blue5 MMscfd – RedDowhnole shut-in at 60 minSurface shut-in at 65 minutes

73

Brine Arrival Times vs. Gas Rate

Problem Description

• The time required to clean-up the well for the proposed design was unknown – big-bore completion, gas and condensate well

Case studies – Well clean-upWell Clean-up – Case Study 1

• Determine the minimum gas rate required for a proper well clean-up – this minimum rate will dictate the size of the testing equipment to be hired ($$$)

• Determine the gas rate at which all mud would be removed and the time required (if it takes to long it will imply higher MODU rental cost – USD 600 000/day)rental cost – USD 600,000/day)

• Determine the minimum gas rate by running sensitivities between 30 MMscfd and 150 MMscfd

38

Well Clean-up – Case Study 1: 30 MMscfd

7" x Tree ⊕⊕

W/Hd &

SCSSV7

CRA 30"O

20"9-5/8CRA

7-5/8CRA

13-3.8"

75

9-5/8" CRA

7" CRA

7" x Tree ⊕⊕

W/Hd &

SCSSV7

CRA 30"

Well Clean-up – Case Study 1: 150 MMscfd

O

20"9-5/8CRA

7-5/8CRA

13-3.8"

9-5/8" CRA

7" CRA

39

Problem Solutions

• It was found that a 60 MMscf/d gas flow rate would clean all the mud t f th llb


out of the wellbore.

• The small 50MMscfd testing unit will not efficiently perform the well clean-up and posterior testing program

• It was necessary to include in the budget and justify the extra cost of the bigger testing unit

Ri k d t i t d d d l dd d t th ROI• Risk and uncertainty was reduced and value added to the ROI required for a successful clean-up and well test

Problem Description

• Estimate the minimum rate and time required to clean-up the well – Horizontal Oil Well


• Verify the planned well clean-up and testing program using dynamic simulation

40

Well Clean-up – Case 2

79

Well Clean-up – Case 2 using GL

80When using gas lift (300 scf/min of N2 during the first 4 hours), it took 4.3hrs to clean the well.

41

Well Clean-up – Case 2 using GL

81

When using gas lift (300 scf/min of N2 during the first 4 hours), it took approximately 4.3 hours to clean-up the well.

Problem Solutions

• It was found that a mud plug was form at the base of the vertical ti f th ll hi h ld t b lift d i th l d


section of the well which could not be lifted using the planned choke opening program.

• The injection of N2 at the base of the riser was simulated to evaluate if the amount of N2 in cylinders required to produce the well was realistic or other methodology should be considered

• When using gas lift (300 scf/min of N2 during the first 4 hours), it took approximately 4 3 hours to clean-up the welltook approximately 4.3 hours to clean up the well.

• Risk and uncertainty were reduced and value added to the ROI required for a successful clean-up and well test

42

• Down-hole gauges• Down-hole shut-in valve

(IRDV)• Initially filled with brine

and diesel500 i d b l d

System layout

Case studies – Well test optimization (OTC-19767)

• 500 psia underbalanced

Upstream P-T Separator P-T

Diesel Surface ChokeTest Manifold

Completion Mud

Pwh Twg

Ps Ts

What we know from measurements

Surface flow rate

Quasi-Dynamic IPRMatching Well Testing Results with the Simulator


Completion Mud

Upper GaugeBottomhole P-T measurements

PackerTester Valve Downhole Choke effects

Opening - Closing Test Valve

Middle GaugeBottomhole P-T measurements

Gauge P correction

Pg Tg

Surface flow ratePressure & Temperature

What we don’t know, but have to know

Pressure & Flow Rate at the sandface

How to know it?

U thi i l th tl tgΔP=ρghin-situ density Flowing bottomhole P-T

Formation Top

Datum

Formation Bottom

Lower Gauge Initial Reservoir P-TBottomhole P-T measurements

Rathole

Pr TrPwf Twf

Use this pressure signal as the outlet boundary condition in the model

Tune the quasi-dynamic IPRto match the other pressure measurements

43

Well Test Arrangement Upstream P-T Separator P-T

Diesel Surface Choke

Pwh Twg

Ps Ts

Downstream WHP

1000

1500

2000

2500

3000

Pres

sure

(psi

a)

Case studies – Well test optimization (OTC-19767)Quasi-Dynamic IPR and Backpressure input

Diesel Surface ChokeTest Manifold

Completion Mud

Upper GaugeBottomhole P-T measurements

PackerTester Valve Downhole Choke effects


Middle GaugeBottomhole P-T measurementsPg Tg

-500

0

500

0 1000 2000 3000 4000 5000 6000 7000 8000

Time (minutes)

P

Top Layer - Skin and Reservoir Pressure Time-series Input

4

5

6

6020

6025

6030

6035

6040

)

Skin S Preservoir

Manifold Downstream Pressure Time-series

85

Gauge P correctionΔP=ρghin-situ density Flowing bottomhole P-T

Formation Top

Datum

Formation Bottom

Lower Gauge Initial Reservoir P-TBottomhole P-T measurements

Rathole

Pr TrPwf Twf

0

1

2

3

0 1000 2000 3000 4000 5000 6000 7000 8000

Time (minutes)

Skin

(-)

5990

5995

6000

6005

6010

6015

6020

Pres

sure

(psi

a)

Top Layer ResPr – Skin Time-series

Model Description• Forchheimer inflow relation between inflow and draw-down was

selected for the gas well

Hydrocarbon fluid composition from drilling log data and


• Hydrocarbon fluid composition from drilling log data and saturated at reservoir conditions used with properties calculated using SRK-Peneloux EOS

• Detailed tubing and casing steel, cement, and formation layers included for accurate thermal response

• Detailed geometry of well, riser, and topsides tubing wasDetailed geometry of well, riser, and topsides tubing was considered

• 3 1/2” OD 2 5/8”ID production test string

• Valves at well test choke manifold, surface wing valve, subsea tree valve, tubing hanger, SSSV, and IRDV were included

44


Results

87

Upstream P-T Separator P-T

Pwh Twg

Ps Ts


Surface ChokeTest Manifold

Diesel Closed

Completion Mud

PackerTester Valve open Downhole Choke effects


GaugeBottomhole P-T measurements

Gauge P correctionΔP=ρghin-situ density Flowing bottomhole P-T

Formation Top

Datum

Pg Tg

Pr TrPwf Twf

88

Formation Bottom

Initial Reservoir P-T

Rathole

45


• Multi-rate test and surface shu-in build-up– Measured downhole gauge pressure – Blue– Calculated by OLGA – Yellow


5900

5950

6000

Pres

sure

(psi

a)

90

5800

5850

800 1300 1800 2300 2800 3300 3800 4300

Time (minutes)

Downhole Gauge Pressure Matching using quasi-dynamic reservoir input

46

• The dynamic simulator is a useful tool that can be used to "virtually" run through a full well-test to validate and optimise well testing design, planning and operations, as well as, to enhance data for pressure transient analysis.

General Conclusions

In general, it provides the ability to simultaneously model, design, and analyse results in rapid screening of the available options and identify the optimum designs early in the life cycle, resulting in better project ROI.

• Furthermore, it is the most cost-effective way to:– Enable safe and environmentally

friendly operations

91

friendly operations– Optimise data from measurements

(i.e. well test analysis)– Minimise risk and uncertainty– Minimise CAPEX, OPEX and downtime

Pr

drainage boundary

Pwf

riserseparator

Pressure lossesThe Importance of Integrating The Total System

sand face

PwhP riser base

well head

riserbase

flow line

Well

Flowline and Facilities

92

well boreP sep

Reservoir

47

Integrated Modelling ApplicationAll-in-One Gas Lift ExampleReservoir-Well-GL-Flowline-Riser-Separator-Facilities

Gas LiftID=8-in, Depth=120 m

ID=8-in, Length=4.6 km

W1 W2 W3 W4

PCV

PC

LC

Gas Outlet

ID=2 m, Length=6 mNLL=0.842 mHHLL=1.687LLLL=0.315

Annulus

Depth=2840 m

Tubing ID=0.1143 m

ID=0.2159 m

93

LCV

Production Separator Liquid

Outlet

Emergency Liquid Outlet

Emergency Drain Valve

Riser• Quasi-dynamic Reservoir: incorporated explicitly

• Facilities: Simple model

Integrated Modelling ApplicationGas Lift ExampleReservoir-Well-GL-Flowline-Riser-Separator-Facilities

Gas

rate

94

48

OLGA OnlineReal-Time Solutions

WO March 03

3) Enable better management strategies – transparent system

4) Enhance Operability – Virtual instruments

1) Minimise downtime

2) Minimise blockages risk - hydrates warning

95

5) Inhibitor Management and tracking6) Slug Monitoring and tracking

7) Liquid inventory Management

8) Cooldown advisor9) Leak detection

Abandon-ment

OLGA Value Chain through the field life

DELIVERABLES / VALUE

Extend-ProductionProduction / Optimization / ModificationsDevelopmentDiscovery

FeasibilityD i / E i i

OLGA Engineering toolMODELING TOOLS

Design / EngineeringMax Operational window

Operating Phil.ProceduresOperator Training

Production OptimizationMonitoringTrainingModifications

OLGA models

96

I

Integrated Engineering Simulator

OTS Operator Training Simulator

PMS Production Monitoring System

OLGA models

OLGA models

OLGA models

EVOLUTION OF OLGA MODELS

Estimations Accuracy & Speed Tuned to Field data Historical database

49

Technical Papers

Clean-up Paper Year Authors

Well Testing by Design: Transient Modelling for Predicting Behaviour of Exteme Wells SPE 101872 2006D.Teng, and B.Maloney, Woodside Energy, and Juan C. Mantecon, Scandpower Petroleum technology

Downhole Metering

Downhole Multiphase Metering in Wells by Means of Soft-Sensing SPE 112046 2008M.Leskens, B. de Kruif, S. Belfroid, and J. Smeulers, TNO; A. Grizlov, Delft University of Technology

ESPA Dynamic Wellbore Modelling for Sinusoidal Horizontal Well Performance With High Water Cut SPE 109262 2007

Yula Tang, and Martin Wolff, Chevron ETC; P. Condon and K. Ogden Chevron International

Impact of Transient Flow Conditions on Electric Submersible Pumps in Sinusoidal Well Profiles: A Case Study SPE 84134 2003

S.G. Noonan, SPE, M.A. Kendrick, P.N. Matthews, ChevronTexaco EPTC; N. Sebastiao, SPE, ChevronTexaco Overseas Petroleum; I. Ayling, SPE, and B.L. Wilson, SPE, Baker Hughes Centrilift

Oil/Water Slugging of Horizontal Wells- Symptom, Cause and Design SPE 49160 1998 Nathan Barrett & Dave King, BP Exploration Operating CompanyGas Lift

Occurrence of density-wave instability in gas-lift wells Banff 04 2004 Bin Hu, Michael Golan

Automatic Control of Unstable Gas Lifted Wells SPE 56832 1999

Bård Jansen, ABB Industri AS; Morten Dalsmo, ABB Corporate Research; Lars Nøkleberg, SPE, ABB Corporate Research; Kjetil Havre, ABB Corporate Research; Veslemøy Kristiansen, ABB Industri AS; Pierre Lemetayer, SPE, Elf Exploration Production.

A Novel Approach to Gas Lift Design for 40.000 BPD Subsea Producers SPE 77727 2002 G.J. Duncan, SPE, Petro-Canada and B. Beldring, SPE, Norsk Hydro

Impact of Dynamic Simulation of Establishing Watercut Limits of Well Kick-off SPE 88543 2004

Juan Carlos Mantecon, SPE, Scandpower Petroleum Technology, Iris Andersen, Scandpower Petroleum Technology, David Freeman, SPE, Woodside Energy Ltd, Mark Adams, SPE, Helix-RDS

Characterising Gas Lift Instabilities with OLGA2000

ASME/API/ISO Gas-Lift Workshop 2003 Bin HuCharacterising Gas-Lift Instabilities with OLGA2000 Workshop 2003 Bin Hu

Gas Lift Automation: Real Time Data to Desktop for Optimizing an Offshore GOM Platform SPE 84166 2003 Donald Reeves, Ronald Harvey, Jr., and Troy Smith, BP America, Inc.

Active Feedback Control of Unstable Wells at the Brage Field SPE 77650 2002 M. Dalsmo, SPE, ABB; E. Halvorsen, Norsk Hydro ASA; O. Slupphaug, ABBStabilization of Gas Lifted Wells 2002 Gisle Otto Eikrem, Bjarne Foss, Lars Imsland, Bin Hu, Michael GolanGas-lift Instabilitiy Resulted Production Loss and Its Remedy by Feedback Control: Dynamical Simulation Results SPE 84917 2003 Bin Hu, Michael Golan NTNUYme Marginal Field, 12 km Subsea Gas Lift Experience SPE 71539 2001 Alf Midtbø Øveland, Helge J. Ramstad Statoil ASA

Gas Lift - Riser Gas LiftA Systematic Investigation of Girassol Deepwater Field Operational Data to Increase Confidense in Multiphase Simulation IPTC11379 2007 Erich Zacarian, and Dominique larrey, TOTALModelling and Mitigation of Severily Riser Slugging: A Case Study SPE 71564 2001 Weihong Meng, Jeff Zhang, R J Brown Deepwater Inc.

97

Technical Papers (cont.)Gas Wells Liquid Loading Paper Year Authors

A Combined Well Completion and Flow Dynamic Modeling for a Dual-Lateral Well Load-up Investigation IPTC11332 2007 Yula Tang and W.S. Huang, ChevronIntegrated Wellbore/Reservoir Model Predicts Flow Transients in Liquid-Loaded Gas Wells SPE 110461 2007

Gaël Chupin, SPE, Bin Hu, SPE, Tor Haugset, SPT Group; Jan Sagen, SPE, IFE; Magali Claudel, SPE, Gaz de France

A Systematic Approach to Predicting Liquid Loading in Gas Wells SPE 94081 2005D. Teng, SPE, and B. Maloney, SPE, Woodside Energy Ltd., and J.C. Mantecon, SPE, Scandpower Petroleum Technology

General Well Dynamic Simulation ApplicationsThe Virtual Well: Guidelines for the Application of Dynamic Simulation to Optimise Well Operations, Life Cycle Design and Production SPE 109829 2007 Juan Carlos Mantecon, SPT GROUP

Heavy OilsThermal design of Wells Producing Highly Viscous Oils in Offshore Fields in The Gulf of F Ascencio-Cendejas Pemex; O Reyes-Venegas and M A NassThermal design of Wells Producing Highly Viscous Oils in Offshore Fields in The Gulf of Mexico SPE 103903 2006

F. Ascencio-Cendejas, Pemex; O.Reyes-Venegas and M.A. Nass Scandpower Petroleum Technology

Helicoaxial PumpsOperating Multiphase Helicoaxial Pumps in Series to Develop a Satellite Oil Field in a Remote Desert Location SPE 109785 2007 Hisham Saadawi, ADCO

Horizontal Wells

Analyzing Underperformance of Tortuous Horizontal Wells: Validation With Field Data SPE 102678 2006M. Kerem, SPE, Shell Intl. E&P B.V.; M. Proot, Shell GSI B.V.; and P. Oudeman, SPE, Shell Intl. E&P B.V.

Integration of advanced production and image logging in a high GOR horizontal well with asessement of remedial actions SPE 93473 2005

A.A. Al-Fawwaz, H.K. Mubarak, Saudi Aramco and M. Zeybek, Schlumberger Oilfield Services

Performance Evaluation of Horizontal Wells SPE 39749 1998Fikri J. Kuchuk, Chris Lenn, SPE, Schlumberger Technical Services, Inc., and Peter Hook and Paul Fjerstad, SPE, GeoQuest

HydratesEffectiveness of Bullheading Operations for Hydrate Management in DVA and Subsea Wells OTC 16689 2004 George J. Zabaras and Ajay P. Metha, Shell Global Solutions (US) Inc.

Hydrate Remediation in Deepwater Gulf of Mexico Dry-Tree Wells: Lessons Learned OTC 17814 2006 A.F. Harun, SPE, T.E. Krawietz, SPE, and M. Erdogmus, SPE, BP AmericaTransient Simulations Assisted Hydrate Remediation Efforts in Deepwater Gulf of Mexico Dry-Tree Wells SPE 100750 2006 A.F. Harun, SPE, T.E. Krawietz, SPE, and M. Erdogmus, SPE, BP Americay , , , , g , ,Experience in AA-LDHI Usage for a Deepwater Gulf of Mexico Dry-Tree Oil Well: Pushing the Technology Limit SPE 100796 2006 A.F. Harun, SPE, G. Fung, SPE, and M. Erdogmus, SPE, BP AmericaWhen flow assurance fails: Melting hydrate plugs in dry-tree wells World-Oil 2007 Amrin F. Harun, Thomas E. Krawietz and Muge Erdogmus , BP America

Integrated Well-Flowline-Riser SystemEnvironment OTC17956 2006 E.F. Gaspari, G. Oliveira, M. Monteiro, and R. Dourado, Petrobras

Erha: A Flow Assurance Case Study from Well Packer to process Facilities OWA 2004 2004

Ikenna Onuoha (Esso Exploration & Prodution Nigeria Ltd), Rex Spahn (Consultant to ExxonMobil Development Company), Torgeir Vanvik (Scandpower Petroleum Technology Inc), Mark Utgard (Paragon Engineering Services), Jean-Francois Saint-Marcoux (Stolt Offshore/Paragon Engineering Services, Inc.)

Operational Experience and Model Prediction SPE 77573 2002 Johnny Kolnes, SPE, TOTALFINAELF E&P Norge, Emile Leporcher, SPE,

Dynamic Simulation of the Europa and Mars Expansion Projects: A New Approach to Coupled Subsea and Topsides Modeling SPE 56704 1999

M.F. Lamey, Shell Deepwater Development Systems, Inc.; W. Schoppa, Shell E&P Technology Co.; K.H. Stingl, Shell Deepwater Development Systems, Inc.; A.J. Turley, Jr., Waldemar S. Nelson and Company, Inc.

Innovative Development Engineering Techniques SPE 65202 2000P W Gayton, Ingen / S D Miller, Baker Jardine & Associates / R Napalowski, Veba Oil & Gas Ltd. 98

50

Technical Papers (cont.)Kick-Off Paper Year Authors

Impact of Dynamic Simulation of Establishing Watercut Limits of Well Kick-off SPE 88543 2004

Juan Carlos Mantecon, SPE, Scandpower Petroleum Technology, Iris Andersen, Scandpower Petroleum Technology, David Freeman, SPE, Woodside Energy Ltd, Mark Adams, SPE, Helix-RDS

Near WellboreIntegrated Wellbore/Reservoir Model Predicts Flow Transients in Liquid-Loading Gas Wells SPE 110461 2007

Gael Chupin,SPE, Bin Hu, SPE, Tor Haugset, SPT Group, Jan Sagen, SPE, IFE; Magali Claudel, SPE, Gaz de France

Integrated Wellbore/Reservoir Dynamic Simulation SPE 109162 2007

Bin Hu, SPE, SPT Group; Jan Sagen, IFE; Gaël Chupin, SPE, Tor Haugset, SPT Group; Arild Ek, IFE; Tor Sommersel, Zheng Gang Xu, SPE, Juan Carlos Mantecon, SPE, SPT Group

Dynamic Reservoir Well Interation SPE 90108 2004W.L. Sturm, SPE, S.P.C. Belfroid, SPE, O. van Wolfswinkel*, M.C.A.M. Peters, SPE, F.J.P.C.M.G. Verhels, SPE, TNO TPD, Delft, The Netherlands

OLGA-Wells-Reservoir-Simulator-Integration

An Investigation Into the Need of a Dynamic Coupled Well-Reservoir Simulator SPE 110316 2007E. Nennie, G. Alberts, S. Belfroid, and E.Peters, TNO; and G. Joosten Shell International E&P

Gas Coning Control for Smart Wells Using a Dynamic Coupled Well-Reservoir Simulator SPE 112234 2008A. Leemhuis, E. Nennie, G. Alberts, S. Belfroid, and E.Peters, TNO; and G. Joosten Shell International E&P

Real-time

Gulf of Mexico Field of the Future: Subsea Flow Assurance OTC 18388 2006R. Gudimetla and A. Carroll, BP, and K. Havre, C. Christiansen, and J. Canon, Scandpower Petroleum Technology Inc.

Smart Wells

Gas Coning Control for Smart Wells Using a Dynamic Coupled Well-Reservoir Simulator SPE 112234 2008A. Leemhuis, E. Nennie, G. Alberts, S. Belfroid, and E.Peters, TNO; and G. Joosten Shell International E&P

Tight Gas Reservoirs

Predicting Highly Unstable Tight Gas Well Performance SPE 96256 2005A.L. Ballard, D. Adeyeye, and M. Litvak, BP; C.H. Wang, Consultant; and M.H.Stein, C. Cecil, and B.D. Dotson, BP

Validation with Field DataCanadian

Comparison of Correlations for Predicting Wellbore Pressure Losses in Gas-Condensate and Gas-Water Wells

International Petroleum Conference 2003 M.D Trick, Neotechnology Consultants Ltd.

Verification of Transient, Multi-Phase Flow Simulation for Gas Lift Applications SPE 56659 1999 H. Asheim, SPE, NTNU, Trondheim - Norway

Simplified Wellbore Flow Modeling in Gas-Condensate Systems SPE 89754 2004C.S. Kabir, SPE, Chevron Texaco Overseas Petroleum; A.R. Hasan, SPE, U. Of Minnesota-Duluth

Critical Evaluation of Mechanistic Two-Phase Flow Pipeline and Well Simulation Models SPE 36611 1996 H. Dhulesia, SPE, Total SA, and D. Lopez, SPE, Elf Aquitaine, FranceWell Control

The Necessity of Modelling in Contingency Planning and Emergency Well Control Response IADC 2005 2005 Ole Rigg, WellFlow Dynamivs

Advanced Well Flow Model Used for Production, Drilling and Well Control Applications IADC 1966 1966Ole Rigg, WellFlow Dynamics; John Friedemann, Saga Petroleum, and Jan Nossen, Institutt for Energiteknikk

Well testingPlanning and Executing Long Distance Tie-back Oil Well Testing: Lessons Learned IPTC11193 2008 Amrin F. Harun BP America

Well Testing by Design: Transient Modelling for Predicting Behaviour of Exteme Wells SPE 101872 2006D. Teng, SPE, and B. Maloney, SPE, Woodside Energy Ltd., and J.C. Mantecon, SPE, Scandpower Petroleum Technology 99

Play with the virtual well, do not play with the actual well!

100

be dynamic

Wells Dynamic Simulation With OLGA Perth Techint 2010

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