Gas Lift Optimisation of Long Horizontal Wells - · PDF fileGas Lift Optimisation of Long...

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Gas Lift WorkshopGas Lift WorkshopDoha Doha –– QatarQatar

44--8 February 20078 February 2007

Gas Lift Optimisation of Gas Lift Optimisation of Long Horizontal WellsLong 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


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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 regimeVertical flow

SLUG FLOW

ANNULAR

BUBBLE

Slug flow area increases with increasing upward inclination

Slug flow area decreases with increasing pressure


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Rate Changes– Pipe line liquid inventory decreases

with increasing flow rate – Rate changes may trigger slugging

Gas Production Rate

Liqu

id In

vent

ory

Initialamount

Finalamount

Amountremoved

Shut-In - Restart– Liquid redistributes due to

gravity during shut-in– On startup, slugging can

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

– Liquid redistributes due to gravity during shut-in

– On startup, slugging can occur as flow is ramped up

B-Gas and Liquid Outlet Flow

A-Liquid Distribution After Shutdown

Flow

rate

gasliquid


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Hydrodynamic Slugging

Frequency

Slug

Len

gth

b.-slug distribution

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pipe 2 pipe 3pipe 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 downholeseparators – 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 outside 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 - ERBlue – gasRed – oilGreen -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 happenTo thoroughly elim inate casing heading, m ake the gas in jection critica l

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

0,000,050,100,150,200,250,300,350,400,450,500,550,600,650,700,750,800,850,900,951,001,051,101,151,201,25

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

inje

ctio

n ra

te (k

g/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 stabilityInstability occurs only when

1<−

gLPP

l

sepR

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 subseadevelopments

• 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• operating 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 only cause erosion of GLVs but reduce the GL efficiency by injecting also fluids – unexpected GLR.

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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:DownholeWellheadBase 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 TechniquesApplication 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 ModellingSinusoidal 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 4Zone 1 300 20Zone 1+2 300 300 20 201+3 300 300 20 201+2+3+4 300 300 300 300 20 20 20 20PI var - RP cons 300 300 300 300 20 5 20 5PI 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


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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 23 4


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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.


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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 oil (slip between oil and water phases)


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Horizontal Well Completion Design Evaluation

gas

wateroil

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

0 250 500 750 1000 1250 1500 1750 2000 2250 2500

Distance from heel (m)

Wel

lbor

e flo

win

g pr

essu

re (b

ara)

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

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189

190

191

192

193

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195

196

197

198

199

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0 250 500 750 1000 1250 1500 1750 2000 2250 2500

Distance from heel (m)

Wel

lbor

e flo

win

g pr

essu

re (b

ara)

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

open

ing

(-)

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be dynamic

Thank You! Any Questions?

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