Single-Point Gas Lift Design UsUs g y a c S u a oing...

33rd Gas-Lift WorkshopHouston, Texas, USAFebruary 1 - 5, 2010

Single-Point Gas Lift Design Using Dynamic SimulationUs g y a c S u a oJuan Carlos Mantecon

AdvisorAdvisor

This presentation is the property of the author(s) and his/her/their company(ies).It may not be used for any purpose other than viewing by Workshop attendees without the expressed written permission of the author(s).

Single Point Injection Gas Liftg j• Subsea General Issues• Gas Lift Design Issues• Subsea Gas Lift Design Issues• Single Point Injection Issues• Dynamic Simulation• Understanding Slugging• System Integration• Surface Control GLVs• Real-time Online Optimization• Summary

Feb. 1 - 5, 2010 2010 Gas-Lift Workshop 2

Subsea General Issues• Wells usually share flowline to platform:

– FTHP cannot be considered constantFTHP cannot be considered constant – Over-injecting lift gas causes oil deferment

• Flowline/riser system is prone to slugging:

– No validity of steady-state models– Difficult well kick off (risk of platform trip)

• Subsea wells are hardly ever surveyed (expensive access)Subsea wells are hardly ever surveyed (expensive access)

– Long flowlines -> several hours stabilisation time ( > 8 hrs after GL rate change)

– Slugging -> long test timesgg g g– Difficult to test at normal operating conditions– Multi-rate testing of one well takes days

• Wells are sporadically tested (oil deferment)• Wells are sporadically tested (oil deferment)

• Downhole gauges/flowmeters are lacking/ malfunctioningFeb. 1 - 5, 2010 2010 Gas-Lift Workshop 3

General Gas Lift Design Issuesg

• StabilityModelling concerns:

– Cause of Slugging

• Annular Flow– P-T gradientsP T gradients– Condensation (dry gas?)– Heading

• Heat Transfer– Counter-currents effects– T @ valve locationT @ valve location

• Non-Constant Fluid Composition in Tubing above Injection Point

• Unloading Valves Operation


Gas Lift is clearly a transient system

Subsea Gas Lift Issues• Zero Intervention Philosophy

(High Cost Re Entry / Impractical)(High Cost Re-Entry / Impractical)– No unloading valves

(no multi-point injection)(no multi-point injection)– No re-entering to change GLVs

Orifice (no moving parts higher life)– Orifice (no moving parts – higher life)

• Single Point Injection– Downhole– Wellhead– Riser


Single-Point Gas Lift Issuesg

• Stability (GL System Flexibility Lost)– Reduced operational range vs conventional GL:

upper GLV injection can keep well in production and generating revenue (gone!)and generating revenue (gone!)

– Instability may be dampened due to multi-point injection in unloading GLVs (gone!)injection in unloading GLVs (gone!)

– Well-Riser Slugging Interaction (needs system integration)

• Significantly higher operating pressure is required to unload the well to this single depth.


Single-Point Gas Lift Issuesg

• No unloading GLVs may result in a shallower operating point and reduced draw-down – depending on compressor capacity economicsIf i j ti i l d l t d• If max injection pressure is already pre-selected, then: inj. depth variable. If not, inj. depth in well fixed as deep as possible, above 600 deviation – no limit for remote GLVs

• Once injection point is set, there is a minimum f i j t i d t i t i ffi i tsurface inj. rate required to maintain sufficient

annular back pressure for continuous GL – it is a function of orifice size and flowing Ptubing g g(WHP, PI, reservoir pressure, watercut, etc.)


Subsea Single-Point Gas Lift Issuesg

• More Difficult Troubleshooting, Well Testing and Surveillance gdue to Subsea Environment and single point injection

• Dynamic simulation is necessary to properly design and operate subsea gas lift single point injectionand operate subsea gas lift single point injection wells and systems due to the reduced system’s flexibility and range of application


Dynamic Simulationy• Prior to defining the gas-lift design, detailed flow

assurance studies must be completeassurance studies must be complete. For subsea and deepwater, the fluid behavior in the integrated well-flowline-riser system dictates the artificial lift design, not

the wellbore environment itself

• Dynamic Flow Assurance studies should include:St bilit l i t d t i P T fil li id h ld d

the wellbore environment itself.

– Stability analysis to determine P-T profiles, liquid hold-up and minimum gas / fluid velocities required for well-riser stability.

• Well • Well-Flowline-Riser integrated system

– Slugging Type & Severity (horizontal & deviated wells, riser): • Hydrodynamic slugging (slip induced)y y gg g ( p )• Terrain induced slugging


Dynamic Simulationy• Flow Assurance studies should include (cont.):

– Optimum Injection Point and Gas Rate: The primary cause of wellbore/flowline slugging is that the superficial gas velocity is too low. The addition of GL gas increases the superficial

l it d h th lti h fl tgas velocity, and changes the multiphase flow to a more stable flow regime.

– For high pressure gas lift scenarios need to address:– For high pressure gas lift scenarios, need to address: “Is the gas really a gas at the point of injection?”

– Annulus/Inj line: Condensation could cause erosion of GLVsAnnulus/Inj. line: Condensation could cause erosion of GLVs –eliminated by maintaining the temperature above condensation.

– In addition, issues regarding hydrates, wax, emulsions and other , g g y , ,fluid behaviors must also be addressed.


Slugginggg g


Slugginggg g

Blue = GasBlue = GasGreen = OilRed = Water


Gas Lift – One Injection PointExample SetupExample Setup

60°F500 psia sep press

TVD

10000 ft

3 1/2”

10000 ft5 1/2”

250°F, 3300 psia and 3 bbl/psiGOR = 500 scf/bbl

Choke at injection point


Gas Lift – One Injection PointOil RateOil Rate

6000 2.5

50002.0

Gas lift rate Oil rate

3000

4000

ate

[bbl

/d]

1.5

ft [M

Msc

fd]

2000

Oil

ra

1.0

Gas

lif

0

1000

0.0

0.5


0 5 10 15 20 25 30

Time [h]

Gas Lift – One Injection PointLiquid ContentLiquid Content

70 2.5

G lift t

50

60

l]

2.0

Gas lift rate

30

40

d co

nten

t [bb

1 0

1.5

s lif

t [M

Msc

fd]

20

Liqu

i

0.5

1.0

Gas

Liquid content

0

10

0 5 10 15 20 25 300.0


Time [h]

Gas Lift – One Injection PointBHP PressureBHP Pressure

4000 2.5

3000

3500

2.0

Gas lift rate

2000

2500

ssur

e [p

sia] 1.5

ift [M

Msc

fd]

BHP

1000

1500Pres

0 5

1.0

Gas

l

0

500

0 5 10 15 20 25 300.0

0.5


0 5 10 15 20 25 30

Time [h]

Riser Gas Lift Stabilityy

• Sever riser slugging gg goccurs when liquid accumulates at the riser base and totally fill a

A. Slug formation C. Gas penetration

base and totally fill a section of the flowline and riser for an extended

fB.Slug production D. Gas blow-down

period of time under some flow conditions, especially when there is a p ydownward slope in the flowline at the riser base and the flowrate is lowand the flowrate is low.


Riser Gas Lift Stabilityy


Severe Riser Slugging Mitigationgg g g• Increase GL gas rate (no additional subsea equipment required)

• Reduction of flowline diameter and or riser diameter

• Gas injection in the riser

• Automatic flow rate control system

• Ch ki ( d d ti it )• Choking (reduce production capacity)

• Increase of backpressure (reduce production capacity)

• Splitting the flow into dual or multiple streamsTrend data

TOTAL LIQUID VOLUME FLOW BRAN-1,PIPE-5,3 [m3/h]GAS VOLUME FLOW BRAN-1,PIPE-5,3 [m3/h]

200

• Use of mixing devices at the riser base

• Internal small pipe insertion (intrusive solution)

• External multi-entry gas bypass

m3/

h

150

100

50

External multi entry gas bypass

• Internal coil tbg-packers in pipeline and riser

• External bypass line

S ( f )

0

-50

-100

Time [h]C:\Alicks Shared\Courses\Multiphase Pipelines - Introductory Workshop\3.0 Terrain Induced Slugging\sev ere-slug-405.inp

65.554.543.532.521.510.50

• Subsea separation (2 separate flowlines and a liquid pump)

• Foaming (requires foaming agents and a way to form the foam)Feb. 1 - 5, 2010 2010 Gas-Lift Workshop 19

Integrated Modelling ApplicationGas Lift ExampleR i W ll GL Fl li Ri S t F ilitiReservoir-Well-GL-Flowline-Riser-Separator-Facilities

Gas LiftID=8-in, Depth=120 m

PC

Annulus

ID=8-in, Length=4.6 km

ID=0.2159 m

PCV

PC

Gas Outlet

ID=2 m, Length=6 m

Depth=2840 m

W1 W2 W3 W4

LCV

Production Separator

LC

Liquid Outlet

NLL=0.842 mHHLL=1.687LLLL=0.315

Riser

Tubing ID=0.1143 m

• Quasi-dynamic Reservoir: LCV

Emergency Liquid Outlet

Emergency Drain Valve

Riserincorporated explicitly

• Facilities: Simple model

Integrated Modelling ApplicationGas Lift ExampleR i W ll GL Fl li Ri S t F ilitiReservoir-Well-GL-Flowline-Riser-Separator-Facilities

ion

Rat

eG

as In

ject

i


Single Point Injection Using OrificeSingle Point Injection Using Orifice

Advantages Summaryg y

• Higher reliability than conventional completion using unloading valvesg

• Meets “zero intervention” philosophy set for subsea developments

• Fewer expensive GL mandrels required (less relevant)• Removal of moving parts or parts that could leak when

using an orificeg• Eliminates risk of incorrect pressure settings on bellows

(or inappropriate springs) and T effects• R d th diff ti l i f “h t t t”


• Reduce the pressure differential require for a “hot start”.

Single Point Injection Using OrificeSingle Point Injection Using OrificeDisadvantages Summary

• Less flexible design• Less Range of Application• Requires a minimum gas injection rate for well stabilityRequires a minimum gas injection rate for well stability• Requires a higher injection pressure• Valve orifice erosion becomes an issue

• Operating valve may have to be set higher in the well (less production rate)A ll ith l d l ill i j ll• A well with only one mandrel will require a major well intervention should the operating valve have a problem

• May require more expensive remote controlled GLV


(less relevant)

Surface Controlled GLVs

• Advantages– Eliminates need for extensive orifice sizing– Reduces risk of erosion. Can remain “full open” during

unloading and then close to necessary orifice size.unloading and then close to necessary orifice size.– Orifice size can change as well conditions change

without an intervention– Can be set deeper in the wellbore

Di d t• Disadvantages– Expensive (sometimes it is difficult to justify the cost of this system)

May require duplication (for risk reduction)


– May require duplication (for risk reduction)

Real-Time Online Dynamic SimulationReal Time Online Dynamic Simulation• The stabilization of slugging GL wells is achieved by a dynamic

feedback control solution using the production choke at the wellheadfeedback control solution using the production choke at the wellhead.– The primary input to the dynamic feedback controller normally is a

measurement of the downhole pressure.The injection choke port size can also be controlled– The injection choke port size can also be controlled.

– A dynamic Simulator is critical to develop the control algorithm - SPE 56832

R l ti O li d i i l t• Real-time Online dynamic simulator– Slug flow warning– Gas Lift Optimization Advisor

Vi t l d fl t– Virtual gauge and flowmeter– Erosion, Corrosion monitoring– Hydrate Advisor

MEG MeOH inhibitor monitoring


– MEG, MeOH inhibitor monitoring– Operator training simulator

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