Gas Lift for SAGD

2006 ASME Gas Lift WorkshopHouston, TX

Outline

• What is SAGD and why is it being used?• Typical Operating Conditions for a SAGD

producer• Gas Lift Design for SAGD: Then and Now• Can we do better?

Horizontal Length ~ 750 m

5 - 7 m

450 - 750 m

Source:www.encana.com

Production Rates increase over time as the steam chamber grows.

Typical Operating Conditions for a SAGD Producer (currently)

• Bottomhole pressures: 290 – 580 psi (2000 – 4000 kPa)

• Bottomhole temperature: 355 – 480ºF (180 – 250 ºC)

• Fluid rates: 2500 – 8000 bfpd (400 – 1270 m3pd)

• Water cuts: 50 – 90%• Possible H2S, CO2, sand, slugging

Gas lift used to be the preferred method of lift for SAGD

Why?

- simple poor boy design cheap

- high volume and high pressure gas source available

- flexible to lift the low rates (early production) and the higher rates as the steam chamber expands.

- did not have gas locking and temperature sensitivity issues like the beam pump

- very economic: use source gas for lift and then after separation, use it for steam generation.

What was the problem?

• Slugging• Did not get rates anticipated

The impact of steam

For a SAGD well, 5-10% of the water slowly flashes into steam as it travels up to the surface. 500 bbls of water can progressively flash into 25,000 bbls equivalent of steam. Adding lift gas causes even

more steam to flash.

Most gas lift design programs are unable to account for the steam lift effect and as a result may over-

predict the amount of lift gas needed.

Example of a SAGD Completion with Gas Lift:- single or dual production strings (3.5” – 5.5”),

however the dual design is more prevalent.

- coiled tubing gas lift string inside one or both production strings (various configurations for the entry of lift gas into the production stream)

Instrument string

Lift Gas Entry Configurations

• Perforated stingers • Nozzles (variety of hole sizes and orientations)• Open ended

Note: A common complaint among SAGD operators using gas lift was that that slugging was more prevalent.

Why not a conventional gas lift completion?

Examples of answers received from the industry:

“There is not enough room to run proper gas lift mandrels.”

“Gas lift valves and seals do not work at these higher temperatures”

“May not be able to retrieve valves once they have been heated (ie become stuck in mandrel).”

“Poor boy systems pose less risk and are much cheaper”

Stingers and Nozzles: How many holes and what size?

Hole Size (mm)

Number of Holes

Total Flow Area (mm2)

Equivalent Port Size

11 1* 94.9 27/64”

9 1* 50.4 5/16

4 2 25.12 3/16-4/16”

3 2 14.13 5/32”

3 3 21.2 3/16-4/16”

- multiple holes of this size were used in a 6 ft stinger configuration.

Examples of hole sizes used or recommended for 0.5MMscfd passage

The point is that many large “holes” were used to pass a small amount of gas.

Nozzle Orientation

Upwards: inject in same direction as fluid fluid, minimizing turbulence. Concern with sand fall-back and plugging

Perpendicular: Concern is erosion of tubular walls (if placed inside production tubing)

Downwards: Less risk for sand fall back, but the concern is creating a tighter emulsion from the fluid shear and choking back inflow.

Feedback on direction of lift gas entry is appreciated. Are the concerns or justifications valid? Which orientation do you prefer?

Attempt to model the gas lift entry via perforated stinger

• Since the objective was to determine minimum gas injection rates for continuous injection via a given stinger configuration, a transient program (Dynalift) was used.

• Limitations:• Only one hole per foot• Cannot “directly input” a coiled tubing stinger

inside the production string configuration.• Program kept crashing at the larger hole size• Could not take into account the steam lift effect

Question: Does the lift gas really pass through all the holes

along a 6 ft stinger ?

-4000.0

-2000.0

0.0

2000.0

4000.0

6000.0

8000.0

10000.0

12000.0

0 1000 2000 3000 4000 5000 6000 7000

Elapsed Simulation Time (minutes)

Lift

Gas

rate

(m3/

d) a

nd In

ject

ion

Pres

sure

(kPa

)

Surface Injection Rate Gas rate thru hole #1 Gas rate thru hole #2 Delta P across hole #1 Delta P across hole #2

Continous lift gas injection does not occur until the surface lift gas rate exceeds 5.7 E3m3/d

This is the operating window for this given stinger configuration, between the minimum rate needed for stability and the maximum rate where the holes reach critical velocity

Dynalift results for two 4mm holes at the end of a 1.5” coiled tubing string (for a given set of conditions)

The value in this work was demonstrating to SAGD completion engineers the effect of

current perforated stinger design. As a result, the industry is now leaning towards nozzles with smaller and less frequent holes for gas

passage.

Need feedback

What options do I have to run on the end of that coiled tubing?

What about some checking capability and ways to prevent plugging of the holes?

Some other interesting gas lift concepts that have actually

been field tested

E-Lift™: Patented by Ken Kisman (www.rangewest.ca)

Chamber Lift?

Since this lift type is not affected by temperature nor GOR, it was modified to suit thermal, primarily SAGD applications. High pressure gas, which is usually available at SAGD locations for steam generation, is used to actuate the pump.

(taken from SPE 97683)

Weatherford Hydraulic Gas Pump System

Could the reciprocating systems (beam or HGP) have a negative impact on the chamber and fluid

drainage for a SAGD well?

Is there still a place for gas lift technology in SAGD wells?

Yes• Still the cheapest

method of lift since there is already a high pressure gas source being used for steam generation.

• Has the best range of production capacity

No• Cannot control

withdrawal and subcools as well as ESPs, etc.

• Not effective at the lower chamber pressures.

• Creates a tighter emulsion

What is your opinion?

Feedback, comments, questions?

Back-up slides

Source: www.hfthimm.com

Heated OilFlows to Well

Flows to Interface and

Condenses

Oil and CondensateAre Drained

Continuously

Sample outflow curves on a SAGD gas lift well

Source: www.choa.ab.ca

Steam however it is applied is the most prevalent force for enhanced oil recovery processes and in most cases the most profitable choice to

assist in the production of heavy oil or oil sands reservoirs.