critical velocity/ nodal stability gas well...

Originally Presented at:Originally Presented at:

Gas Well De-Liquification Workshop

Adams Mark Hotel, Denver, Colorado

March 5 - 7, 2007

Critical Velocity/ Nodal Stability Critical Velocity/ Nodal Stability Gas Well PredictionsGas Well Predictions

By

J F Lea, PLTech LLC

Lynn Rowlan, Echometer

Charlie Reed, Devon

European Conference Gas Well European Conference Gas Well DeliquificationDeliquification2525--26 September 200726 September 2007




March 5 - 7, 2007

Liquid Loading

Mar. 5 - 7, 20072007 European Gas Well Deliquification

Conference, Groningen, The Netherlands

3

GAS WELL GRADIENT COMPOSED OF GAS WELL GRADIENT COMPOSED OF GAS WELL GRADIENT COMPOSED OF GAS WELL GRADIENT COMPOSED OF

FRICTION AND GRAVITYFRICTION AND GRAVITYFRICTION AND GRAVITYFRICTION AND GRAVITY

(dp/dl) = (dp/dl)el + (dp/dl)f + (dp/dl)acc

HOLDUP (LIQUID) BUILDS WITH TIME AND LOWER PRODUCTION



4



5

Determine Liquid Loading

from “Critical Velocity”

Droplet in

flowing gas

Buoyant

weight of

droplet in gas

Drag from

flowing gas

tending to lift

the droplet



6

( )6

3d

g

gF GL

C

Gravity

πρρ ×−=

2

, )(2

1dGdDG

C

UPDrag VVACg

F −= ρ

Whereg = gravitational constant = 32.17 ft/s2

gC

= 32.17 lbm-ft/lbf-s2

d = droplet diameter

rL

= liquid densityr

G= gas density

CD

= drag coefficient

Ad

= droplet projected cross-sectional areaV

G= gas velocity

Vd

= droplet velocity



7

( )( )

( )sft

P

P

P

PV waterC /

0031.

0031.67434.460

0031.

0031.67593.1

2/1

4/14/1

2,

−=

−=

( )( )

( )sft

P

P

P

PV

condC/

0031.

0031.45369.320

0031.

0031.45593.1

2/1

4/14/1

2,

−=

−=

( )( )

sftP

PV waterC /

0031.

0031.67321.5

2/1

4/1

,

−=

( )( )

sftP

PV

condC/

0031.

0031.45043.4

2/1

4/1

,

−=

Coleman, et al., (Exxon)

Turner et al., (with 20% adjustment)



8

Sample of Turner’s data: Mostly at Higher WHP’s



9



10

Example: Using Turner, 2 3/8’s,

100 psi, read~320 Mscf/D

Turner Unloading Rate for Well Producing Water

0

500

1000

1500

2000

2500

3000

0 50 100 150 200 250 300 350 400 450 500

Flowing Pressure (psi)

Rat

e (M

cfd

)

4-1/2 OD 3.958 ID

3-1/2 2.992

2-7/8 2.441

2-3/8 1.995

2-1/16 1.751



11

Other References Related to Critical Velocity or Rate

• Lea, J.F., Nickens, H.V., and Wells, M.: Gas Well De-Liquification, first edition, Elsevier Press, Cambridge, MA (2003).

• Turner, R.G., Hubbard, M.G., and Dukler, A.E.: “Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wells,” J. Pet. Tech. (Nov.1969) 1475-1482.

• Coleman, S.B., Clay, H.B., McCurdy, D.G., and Lee Norris, H. III: “A New Look at Predicting Gas-Well Load Up,” J. Pet. Tech. (March 1991) 329-333.

• Veeken, K., Bakker, E., and Verbeek, P.: “Evaluating Liquid Loading Field Data and Remedial Measures,” presented at the 2003 Gas Well De-Watering Forum, Denver, CO, March 3-4.

• Li, M., Li, S.L., and Sun, L.T.: “New View on Continuous-Removal Liquids from Gas Wells,” paper SPE 75455 presented at the 2001 SPE Permian Basin Oil and Gas Recovery Conference, Midland, TX, May 15-16.

• Nosseir, M.A., Darwich, T.A., Sayyouh, M.H., and El Sallaly, M.: “A New Approach for Accurate Prediction of Loading in Gas Wells Under Different Flowing Conditions,” paper SPE 37408 presented at the 1997 SPE Production Operations Symposium, Oklahoma City, OK, March 9-11.

• Duggan, J.O.: “Estimating Flow Rates Required to Keep Gas Wells Unloaded,” J. Pet. Tech.(December 1961) 1173-1176.

• Yamamoto, H. and Christiansen, R.L.: “Enhancing Liquid Lift from Low Pressure Gas Reservoirs,”paper SPE 55625 prepared for presentation at the 1999 SPE Rocky Mountain Regional Meeting, Gillette, WY, May 15-18.

• Bizanti, M.S. and Moonesan, A.: “How to Determine Minimum Flowrate for Liquids Removal,” World Oil, (Sept. 1989) 71-73.

• Ilobi, M.I. and Ikoku, C.U.: “Minimum Gas Flow Rate for Continuous Liquid Removal in Gas Wells,”paper SPE 10170 presented at the 1981 SPE of AIME Annual Fall Technical Conference and Exhibition, San Antonio, TX, Oct. 5-7.



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Critical Rate: SummaryCritical Rate: Summary

•• Turner, Coleman and other models do not Turner, Coleman and other models do not

agreeagree

•• Critical gas rate independent of liquid rateCritical gas rate independent of liquid rate

•• Theoretically better to use at pressure Theoretically better to use at pressure

downhole but seldom attempteddownhole but seldom attempted

•• Simple modelSimple model

•• Must be considered approximate but Must be considered approximate but

widely widely used with successused with success




March 5 - 7, 2007

Nodal Analysis



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Nodal Analysis ™ :

A Model of the Well



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Nodal Analysis ™ (Schlumberger)

Rate

Pre

ssu

re

InflowOutflow

Inflow to the node

PR – ∆P (upstream components press drop’s) = Pnode

Outflow from the node

Psep + ∆ P (downstream components press drop’s) = Pnode




March 5 - 7, 2007

Inflow Curves



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Inflow or Reservoir CurveInflow or Reservoir CurveInflow or Reservoir CurveInflow or Reservoir Curve

Rate

Pre

ssu

re

Inflow

Reservoir Inflow curve often represented by:

Q = C ( Pr2 – Pwf2)n …. (back pressure equation)




March 5 - 7, 2007

Outflow Curves



19

Nodal Analysis ™ (Schlumberger)

FrictionLiquid

Buildup

Rate

Do

wn

-ho

le p

ress

ure

Tubing J-Curve

At low rates, liquid builds up in the tubing

and requires more pressure to flow

(Use various correlations, Gray, etc. )



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Liquid LoadingLiquid Loading

•• Liquid loading Liquid loading

occurs when occurs when gas gas

rate is too lowrate is too low to to

efficiently remove efficiently remove

the produced the produced

liquidsliquids

•• Liquid Loading Liquid Loading

symptoms symptoms of of

unstable flow unstable flow

behaviorbehavior and and

potential potential logging logging

off of the welloff of the well

0 800 1600 2400 3200 4000 4800 5600 6400 7200 80000

80

160

240

320

400

480

560

640

720

800

880PSIAPSIAPSIA

Gas Rate (mscf/d)Gas Rate (mscf/d)Gas Rate (mscf/d)

Tubing CurvesTubing CurvesTubing Curves

ISABEL A1ISABEL A1ISABEL A1

S1 - Tubing Flow - Ptbg = 250 psig



Cond .0 bbl/MMscf

Water 29.6 bbl/MMscf

S1 - 2.875" at 3220 ft

S2 - 3.5" at 3220 ft

S3 - 4.5" at 3220 ft

Gray Correlation

S1

S2

S3

S1 S2 S3



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Nodal Analysis : Effects such as Size of the

Tubing Diameter vs. Flow Rate can be studied



22

BIGGEST ERROR in Multiphase Flow Predictions

Nodal “TurnNodal “Turn--Up” PointsUp” Points



23

0 200 400 600 800 1000 1200 1400 1600 1800 2000340

380

420

460

500

540

580

620

660

700

740

780

820

860

900

Flowing BHP (psig)Flowing BHP (psig)Flowing BHP (psig)

Gas Rate (mscf/d)Gas Rate (mscf/d)Gas Rate (mscf/d)

Liquid Loading J-Curve with GrayLiquid Loading J-Curve with GrayLiquid Loading J-Curve with Gray

Tbg - Critical Rate (Min BHP) = 547 mscf/d

Pfwh 125psig

Cond .0 bbl/MMscf

Water 15.0bbl/MMscf

2.375" at 10000 ft

Stable flowHigh frictionMay have some liquid buildup

Unstable flowHigh liquid buildup

LIQUID LEVEL PRESENT IN WELL

Liquid loading occurs when gas rate is too low to efficiently remove the produced liquids

This results in unstable flow behavior and potential logging off of the well

Optimal Operation

Liquid LoadingJ-Curve with Tubing to Perfs




March 5 - 7, 2007

Nodal Stability



25

Nodal Analysis : Stability

Stability

Rate

Dow

n-h

ole

pre

ssu

re

B

D

C

A

Flow around A & B is unstable

Flow around C and D is stable



26

BPD Rate Increasing ->

Psi on perfs

Inflow or rsvr curve

Tubing crv, no flow

Tubing crv, more flow

Tubing crv, flow

Tubing crv, flow but unstable

Intersections are flow pts




March 5 - 7, 2007

Model Gas Well



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Example Gas Well • Data:

• Reservoir:

• C = .0001414 Mscf/D

• n = 1.0

• Pr=1500 psi

• Tubing:

• 2 3/8’s to 10,000’

• Liquids:

• 50 bbl/MMscf

• Pressures/Temps/Fluid Properties

• Pwh: 100 psi

• Twh: 100 F

• BHT: 200 F

• GG: .7

• 50 bbl/MMscf

• WG: 1.03

• WOR: 1.




March 5 - 7, 2007

Example Output



30

Well flow unstable

according to shape of

outflow curve at point of

intersection with IPR




March 5 - 7, 2007

Effects of Tubing Size



32

Smaller tubing such as 1.61 or 1.38 (or smaller) ID stabilizes flow.

Critical rate for 1.61 is 245 mscfd

Critical rate for 1.38 is 152 mscfd

So 1.61” or smaller stabilizes and flows above critical rate




March 5 - 7, 2007

Effects of Surface Pressure



34

Adding constant surface

pressure such as higher

separator pressure does

not stabilize or tend to flow above critical rate




March 5 - 7, 2007

Effects of Restrictions at Bottom of Tubing



36

Adding a choke restriction at bottom

hole of .15” diameter or .14” diameter

stabilizes flow. It is still below critical flow however




March 5 - 7, 2007

Effects of Restrictions at Surface



38

Adding a choke of .21” diameter or .18”

diameter at surface stabilizes flow. It is

still below critical rate however

When the Slope of the Tubing Curve

is up and to the left, then Gas Flow

from the Well is stabilized and mist is

lifting all liquids from the Well.

When the Slope of the Tubing Curve

is DOWN and to the left, then Gas

Flow from the Well is unstable and

liquid loading is occurring in the Well.




March 5 - 7, 2007

Effects of Flowline



40

A flowline of more

and more pressure

drop has a stabilizing

effect but flow is still below critical rate



41

Case History: ChokeCase History: Choke

•• The well was drilled towards the end of 2005 and in The well was drilled towards the end of 2005 and in the beginning of 2006. It is completed in the Cotton the beginning of 2006. It is completed in the Cotton Valley and Travis Peak formations. The interval is over Valley and Travis Peak formations. The interval is over 3,000’3,000’

•• Recently, we lost our stock tank on location to lighting Recently, we lost our stock tank on location to lighting and we had to have our production pushed to the tank and we had to have our production pushed to the tank battery, a much further distance away. The well was battery, a much further distance away. The well was not strong enough to flow against the back pressure not strong enough to flow against the back pressure from the longer line and the well died. Strangely from the longer line and the well died. Strangely enough, we found once we shut the well in and enough, we found once we shut the well in and brought it back on with a slight choke the production brought it back on with a slight choke the production became more stable. We have seen that on some became more stable. We have seen that on some other wells once the production has fallen below the other wells once the production has fallen below the critical rate. The choke seems to flatten the critical rate. The choke seems to flatten the production curve rather then having to shut the well in production curve rather then having to shut the well in and flowing intermittently.and flowing intermittently.



42

Well With Choke Added



43

Choke: Summary:Choke: Summary:

•• Choke on well above critical just reduces rateChoke on well above critical just reduces rate

•• Choke on artificially lifted well adds HP or Choke on artificially lifted well adds HP or

reduces rate… except for special casesreduces rate… except for special cases

•• “May” be window on wells that are loaded “May” be window on wells that are loaded

(and maybe best on wells intermitting) that (and maybe best on wells intermitting) that

seems to allow wells to once again flow seems to allow wells to once again flow

continuously instead of having to intermit.continuously instead of having to intermit.




March 5 - 7, 2007

Summary & Conclusions



45

Summary & Conclusions

• Smaller tubing has stabilizing effect but if too small will add too much friction (well known)

•• Adding constant pressureAdding constant pressure to the surface of the well reduces ratereduces rate and does not stabilize the well or tend to flow below critical

• Adding lower constant pressurelower constant pressure to the surface of the well stabilizes the well and tends to flow above critical rate (compressioncompression)



46

Summary & Conclusions Continued

• The effects of a flowlineflowline (rate dependent pressure drop) has a stabilizing effectstabilizing effect on the

flow but flow continues below critical if below to start with as FL pressure drop is added.

• Adding too muchtoo much of a rate dependent pressure drop will (choke) can reduce flowrate to zerochoke) can reduce flowrate to zero

•• AddingAdding a rate dependent pressure drop

(chokechoke) to a loaded well has a stabilizing effectstabilizing effectbut well remains flowing below critical rate



47

Possible Uses of AnalysisPossible Uses of Analysis

• If a well is loaded and it must be intermitted to continue production, consider using a choke to get the well to flow continuously once again. The cost is low to try this. DO NOT add DO NOT add chokes across the field indiscriminately or you chokes across the field indiscriminately or you will have problems. will have problems.

• Thanks to Mohan Kelkar, Tulsa University, for pointing out the stabilizing effects of adding chokes to loaded gas wells. At least stabilizing as far as Nodal Analysis predictions are concerned.

critical velocity/ nodal stability gas well...

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