Gas Lift Workshop Gas Lift Workshop Doha Qatar Qatar Doha 4- - - PowerPoint PPT Presentation

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Gas Lift Workshop Gas Lift Workshop Doha Doha – – Qatar Qatar 4 4-

• 8 February 2007

8 February 2007 Gas Lift Optimisation of Gas Lift Optimisation of Long Horizontal Wells Long Horizontal Wells

by Juan Carlos Mantecon

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Long Horizontal Wells

• The flow behavior of long horizontal wells is

similar to pipelines (well horiz section) + riser (vertical section)

• Dynamic Simulation techniques offer the best

solution:

– Slugging flow predictions – Multiple inflow points performance relationship – Limited validity of steady state techniques

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Well Modelling – Horizontal-Vertical Wells IPR

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• Horizontal well PI is is inversely proportional to ß.
• The impact of ß increases as the thickness of the reservoir increases (ßh)

Well Modelling - Horizontal Wells PI

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• A Steady State Equation – assumes equal drainage

areas

Well Modelling - Horizontal vs. Vertical PI

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• Lateral wells with long horizontal wellbores require

multiple inflow points and corresponding PIs

• Normally PI/m (or k thicknes) is available, and the PI for

each section can be roughly estimated by multiplying the PI/m with the section length.

• Building the model using a too fine grid can result in

long simulation time and too many inflow point (reservoir data)

Well Modelling – IPR Dynamic Simulation techniques

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Potential Problems for Stable Multiphase Flow

• Inclination / Elevation
• “Snake” profile
• Risers
• Rate changes
• Condensate – Liquid

content in gas

• Shut-in / Start up

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Flow Regime Map - Inclination: Horizontal Measured & calculated

SEPARATED DISTRIBUTED

Potential Problems for Stable Multiphase Flow

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Inclination impact on flow regime

Down Horiz. Up

SLUG FLOW STRATIFIED BUBBLE

Down Horiz. Up

SLUG FLOW STRATIFIED BUBBLE

Pressure impact on flow regime

Horizontal flow

20 bar 45 bar 90 bar

SLUG FLOW STRATIFIED BUBBLE

20 bar 45 bar 90 bar

SLUG FLOW STRATIFIED BUBBLE

Pressure impact on flow regime

Vertical flow

SLUG FLOW ANNULAR BUBBLE

Slug flow area increases with increasing upward inclination Slug flow area decreases with increasing pressure

Potential Problems for Stable Multiphase Flow

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Rate Changes

– Pipe line liquid inventory decreases with increasing flow rate – Rate changes may trigger slugging

Gas Production R ate Liquid Inventory

Initial amount Final amount

Amount removed

Shut-In - Restart

– Liquid redistributes due to gravity during shut-in – On startup, slugging can

• ccur as flow is ramped up
• Shut-In - Restart

– Liquid redistributes due to gravity during shut-in – On startup, slugging can

• ccur as flow is ramped up

B-Gas and Liquid Outlet Flow A-Liquid Distribution After Shutdown

Flowrate gas liquid

Potential Problems for Stable Multiphase Flow

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Hydrodynamic Slugging

Frequency Slug Length

b.-slug distribution

3 pipe 2 pipe 3 pipe 1 1 2

a.-terrain effect and slug-slug interaction

• Two-phase flow pattern maps indicate

hydrodynamic slugging, but

– slug length correlations are quite uncertain – tracking of the development of the individual slugs along the pipeline is necessary to estimate the volume of the liquid surges out of the pipelines

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• Riser-Induced Sluging
• A. Slug formation

B.Slug production

• C. Gas penetration
• D. Gas blow-down

Liquid flow accelerates Liquid seal Gas surge releasing high pressure Pressure build-up Equal to static liquid head

• Terrain Slugging

– A: Low spots fills with liquid and flow is blocked – B: Pressure builds up behind the blockage – C&D: When pressure becomes high enough, gas blows liquid out of the low spot as a slug For subsea and deepwater, the fluid behavior in the flowline and risers may actually dictate the artificial lift method, not the wellbore environment itself.

Pigging-405.plt

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Slug Mitigation Method

• Increase GL gas rate
• Reduction of flowline and/or riser diameter
• Splitting the flow into dual or multiple streams
• Gas injection in the riser
• Use of mixing devices at the riser base
• Subsea separation (requires two separate

flowlines and a liquid pump

• Internal small pipe insertion (intrusive solution)
• External multi-entry gas bypass
• Choking (reduce production capacity)
• Increase of backpressure
• External bypass line
• Foaming

A 20 km, 16” Dubar-Alwyn flowline, riser depth 250 m

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Gas Lift Stability

• H-wells allow reduced drawdown

pressure, thereby maintaining the reservoir pressure above the bubble point for longer periods of time, thus reducing GORs and improving recovery

• H-wells producing below bubble

point pressure can act as downhole separators – leading to slug flow

• well instability occurs in long

horizontal sections with upward- downward slopes, when liquid accumulates at the low points

• Flow is suspected to be channeling
• utside the liner?

Well Modelling - Horizontal Wells

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Well Modelling - Horizontal Wells - ER

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Well Modelling - Horizontal Wells - ER

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Well Modelling - Horizontal Wells - ER

Blue – gas Red – oil Green

• mixture

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Gas Lift Stability Gas Lift Well Stability

• Conventional Design (unloading valves) - the well instability is

dampened due to multi-point injection.

• Single point system (orifice) - there is a minimum surface injection

rate required for the orifice to maintain sufficient annular backpressure (i.e. casing pressure consistently higher than the flowing tubing pressure) for continuous downhole gas injection.

• This minimum injection rate is a function of orifice size and flowing

tubing pressure (wellhead pressure, PI, reservoir pressure, watercut, etc)

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Downhole & Surface Orifice Interaction (Flow Stability)

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Interaction Between Downhole & Surface Orifice

Casing heading m ay happen To thoroughly elim inate casing heading, m ake the gas injection critical

If gas injection is not critical...

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Interaction Between Downhole & Surface Orifice

Is the well unconditionally stable if gas injection is critical?

Replace the orifice with a venturi

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Density Wave Instability

Stability map (L=2500m, PI=4e-6kg/s/Pa, Psep=10bara, 100% choke opening, ID=0.125m)

0,00 0,05 0,10 0,15 0,20 0,25 0,30 0,35 0,40 0,45 0,50 0,55 0,60 0,65 0,70 0,75 0,80 0,85 0,90 0,95 1,00 1,05 1,10 1,15 1,20 1,25 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200 210 220 230 240 250 260 270 280 290 300 310

PR-Psep (bar) Gas injection rate (kg/s)

Density wave instability can occur!

Increasing reservoir pressure and gas

injection rate increases stability.

Increasing well depth, tubing diameter,

PI and system pressure decreases stability

Instability occurs only when

1 < − gL P P

l sep R

ρ

SPE 84917

Two-phase vertical flow under gravity domination often is unstable, particularly in gas lift wells.

Because the gas-injection rate is constant, any variation in liquid inflow into the wellbore will result in a density change in the two-phase mixture in the tubing. The mixture-density change results in a change in the hydrostatic pressure drop. The mixture-density change travels along the tubing as a density wave.

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Subsea-Deppwater Gas Lift Issues

• Zero Intervention Philosophy
• Single Point Injection
• Understanding the Stability Issues
• Using Dynamic Simulation Techniques

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Single Point Injection Using Orifice Advantages

• higher reliability than conventional completion using live

valves

• meets “zero intervention” philosophy set for subsea

developments

• fewer expensive GL mandrels required (less relevant)
• removal of moving parts or parts that could leak
• eliminate risk of incorrect pressure settings on bellows

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Single Point Injection Using Orifice Disadvantages

• requires a minimum gas injection rate for well stability
• requires a higher injection pressure
• valve erosion becomes an issue
• perating valve will have to be set higher in the well

(less production rate)

• a well with only one mandrel will require a major well

intervention should the operating valve have a problem

• less flexible design

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Gas Lift Stability – Horizontal Wells

• The primary cause of wellbore and flowline slugging is

that the superficial gas velocity is too low. The addition of gas lift gas increases the superficial gas velocity and changes the multiphase flow to a more stable flow regime.

• Long horizontal sections give large volumes of gas and

fluid which may influence each other and produce pressure variations in the wellbore and pressure fluctuations in the gas lift injection line.

• Condensation of water in GL injection flowline could not
• nly cause erosion of GLVs but reduce the GL efficiency

by injecting also fluids – unexpected GLR.

27 Use Dynamic Simulation techniques – added benefit of flow

assurance analysis.

When the cause of slugging flow and the severity is known,

changes in design and/or producing conditions can mitigate or eliminate slugging and optimise production

Evaluate optimal single point injection: Downhole Wellhead Base of riser Downhole: If max. injection pressures already pre-

determined, then injection depth variable. If not, injection depth in wellbore fixed as deep as possible, above 60 degree deviation. No limit for remote GLVs.

Gas Lift Stability – Subsea Production System

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Long Horizontal Wells - Dynamic Simulation Techniques Application Examples

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• Dynamic Well Modelling is a powerful tool for establish the

potential of water accumulations in the wellbore and the effects of multiple production zones (Multilateral and SMART Wells) – Potential water accumulation and backflow in the well is dictated by number and location of production zones, reservoir pressure and PI of each zone.

Horizontal Wells Modelling

Sinusoidal Profile – Multiple Production Zones

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• WELL GEOMETRY

– Sensitivity simulations to investigate the effect of multiple production zones on the total well production rate – The production zones can be located at the bottom and top of the well profile to maximise the effects off static head

Horizontal Wells Modelling - Sinusoidal Profile

Zone 1 Zone 2 Zone 3 Zone 4 Zone 1 Zone 2 Zone 3 Zone 4 Zone 1 300 20 Zone 1+2 300 300 20 20 1+3 300 300 20 20 1+2+3+4 300 300 300 300 20 20 20 20 PI var - RP cons 300 300 300 300 20 5 20 5 PI const - RP var 300 280 300 280 20 20 20 20 RESERVOIR PRESSURE (bara) PRODUCTIVITY INDEX (sbbl/d/psi) CASE

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• BASE CASE – 10% Watercut

– No gas formation occurs until an elevation of around 1,000m. – For a rate of 2,500 sbbl/d the water hold-up for the downhill and uphill sections of the tubing are very similar – At 5,000 sbbl/d the bottom & top of the 1st uphill as well as the last uphill part increase. – At 10,000 sbbl/d there is no slip between water and oil and an almost constant water holdup is predicted throughout the tubing

Horizontal Wells Modelling - Sinusoidal Profile

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• PRUDUCTION ZONE SENSITIVITY – 1000 Bbl/s, 30% Watercut

– Case 1-2 (Case 1 Base Case): all production comes from Zone 1 (Zone 2 locared in low point) – Case 1-3: Zone 3 produces about 2/3 of the total production. Zona 1 and Zone 3 are place at the same elevation (identical Reservoir pressure and PI) Zone 1 has to deal with the frictional losses from Zone 1 to Zone 3. – Case 1-2-3-4: Having all identical Reservoir pressure and PI Zone 2 and 4 behave as injection wells instead of production wells. Zone 2 water injection rate is greater than Zone 1 water production rate indicating some backflow from Zone 3 whilst still maintaining forward oil flow

1 2 3 4

Horizontal Wells Modelling - Sinusoidal Profile

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• PRUDUCTION ZONE SENSITIVITY – 5000 Bbl/s, 30% Watercut

– Due to higher total production rate, none of the wells behave like injection wells for any of the cases.

Horizontal Wells Modelling - Sinusoidal Profile

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• Dynamic Simulation is a powerful tool for establish the potential of

water accumulations in the wellbore and the effects of multiple production zones

– Potential water accumulation and backflow in the well is dictated by:

• number and location of production zones
• reservoir pressure of each zone
• PI of each zone.

– Depending on the combination of the above variables there will be periods where some backflow maybe expected into different production zones. The most significant variable is reservoir pressure. – It is possible to get backflow of water only into a specific production zone whilst still maintaining forward flow of

• il (slip between oil and water phases)

Horizontal Wells Modelling - Sinusoidal Profile

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Horizontal Well Completion Design Evaluation gas water

• il

Case description

• A sandwiched thin oil layer
• A horizontal well to be drilled
• Early water and gas coning at the heel

might be a problem

• Need to evaluate three different

completion designs

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Three different completion designs

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Parameters for case 1

• The well is 3000 m deep, has a 10” casing and a 6”

tubing.

• Horizontal wellbore is 2500 m long, has 10 evenly

distributed perforations, for each perforation, an equal PI is used (400Sm3/D/bar)

• Reservoir pressure is 200 bara (2900 psia), temperature

is 100 oC, (close to the oil bubble point)

• Gas lift: appr. 8E5 Sm3/D (5 MMscfd), gas-lift valve is

modeled as leak

• Production choke and injection choke are included
• On the surface, Pout = 15 bara (217 psia)

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196.0 196.5 197.0 197.5 198.0 198.5 199.0 199.5 200.0 250 500 750 1000 1250 1500 1750 2000 2250 2500

Distance from heel (m) Wellbore flowing pressure (bara)

Completion design 1: cemented and perforated casing Completion design 2: cemented and perforated casing + passive stinger Completion design 3: cemented and perforated casing + active stinger

Simulation results: pressure profile in the wellbore

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Case 2: Case description

• A sandwiched thin oil layer
• A horizontal well with smart completion design
• Water and gas coning is still a problem
• Need to avoid coning, and optimize the opening of

each ICV

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Simulation results: pressure profile in tbg & annulus

185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 250 500 750 1000 1250 1500 1750 2000 2250 2500

Distance from heel (m) Wellbore flowing pressure (bara)

Tubing pressure Annulus pressure

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Simulation results: optimal ICV openings

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1 2 3 4 5 6 7 8 9 10

ICV ID ICV opening (-)

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be dynamic

Thank You! Any Questions?