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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
2
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
4
• 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 regimeVertical 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 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
Potential Problems for Stable Multiphase Flow
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Hydrodynamic Slugging
Frequency
Slug
Len
gth
b.-slug distribution
3
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.
23
Subsea-Deppwater Gas Lift Issues
• Zero Intervention Philosophy• Single Point Injection • Understanding the Stability Issues• Using Dynamic Simulation Techniques
24
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
25
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
26
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
28
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
30
• 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
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 23 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
34
• 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)
Horizontal Wells Modelling - Sinusoidal Profile
35
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
36
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
39
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
40
Simulation results: pressure profile in tbg & annulus
185
186
187
188
189
190
191
192
193
194
195
196
197
198
199
200
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
41
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
(-)
42
be dynamic
Thank You! Any Questions?