1.0 a introduce, recognize loading.pdf

Introduction:Introduction:Solving Gas Well Solving Gas Well Liquid Loading

P blLiquid Loading

P blProblemsProblems

ObjectivesObjectives

Understand: Concepts of Liquid Loading

Fi ld S t Field Symptoms Critical Velocity/Rate Nodal Analysis Concepts Nodal Analysis Concepts

2

U.S. Gas Well ProductionU.S. Gas Well Production

U.S. Historical Gas Well Facts70 000 700

60,000

70,000

F

D

600

700

M

C

F

D

/

W

e

l

l

ProductionWell CountAvg Well Rate

40,000

50,000

u

c

t

i

o

n

,

M

M

C

F

400

500

g

G

a

s

R

a

t

e

,

M

20,000

30,000

v

g

D

a

i

l

y

P

r

o

d

u

200

300

t

,

0

0

0

'

s

o

r

A

v

g

10,000

A

v

100

W

e

l

l

C

o

u

n

t

3

J F Lea PLTech LLC 3

01965 1970 1975 1980 1985 1990 1995 2000 2005 2010

0

Source: EIA

Canadian Gas Well Production No CBMCanadian Gas Well Production No CBM

Canadian Historical Gas Well Facts25,000 250 2,500

20,000

25,000

D

200

250ProductionWell CountAvg Well Rate

,

2,000

W

e

l

l

15,000

c

t

i

o

n

,

M

M

C

F

D

150

o

u

n

t

,

0

0

0

'

s

1,500

R

a

t

e

,

M

C

F

D

/

W

10,000

G

a

s

P

r

o

d

u

c

100

W

e

l

l

C

o

1,000

500

A

v

g

G

a

s

R

0

5,000

0

50 500

0

4


1970 1980 1990 2000 2010

YearSource: HPDI

Canadian Gas Well Production With CBMCanadian Gas Well Production With CBM

Canadian Historical Gas Well Facts25,000 250 2,500

20,000

25,000

D

200

250ProductionWell CountAvg Well Rate

,

2,000

W

e

l

l

15,000

c

t

i

o

n

,

M

M

C

F

D

150

o

u

n

t

,

0

0

0

'

s

1,500

R

a

t

e

,

M

C

F

D

/

W

10,000

G

a

s

P

r

o

d

u

c

100

W

e

l

l

C

o

1,000

500

A

v

g

G

a

s

R

0

5,000

0

50 500

0

5


1970 1980 1990 2000 2010

YearSource: HPDI

Canadian Gas Well LocationsCanadian Gas Well Locations

S

6


Source: HPDI

MS Streets & Trips

USA-Canada Gas Well LocationsUSA-Canada Gas Well Locations

S

7


Source: HPDI

MS Streets & Trips

USA-Canada Gas Well Locations (Post 2000 Production)USA-Canada Gas Well Locations (Post 2000 Production)

S

8


Source: HPDI

MS Streets & Trips

Shale: New Shale finds also

9


Horizontal WellHorizontal Well

Horizontals Horizontal Well Ideal CaseHorizontal Well Ideal Case

10


Complex Horizontal Well ProfilesComplex Horizontal Well Profiles

Complex Horizontal Well Profiles10 10010,100

10,150

Well 1Well 2Well 3Well 4

10,200

10 250

c

a

l

D

e

p

t

h

,

f

t

Well 5Well 6Well 7Well 8Well 910,250

10,300

T

r

u

e

V

e

r

t

i

c

Well 9

10,350

10 400

11


10,4000 1,000 2,000 3,000 4,000 5,000 6,000 7,000

Departure, ft

Complex Horizontal Well Profiles: SPE 149477Complex Horizontal Well Profiles: SPE 149477

Paper shows:

Updip gives most recoverable reserves

Undulating wellbore worse gthan downdip for recoverable reserves

12


Hydrostatic/Friction loss in Horizontal Hydrostatic/Friction loss in Horizontal

What would impact the back pressure the pmost Vertical hydrostatic head or horizontal frictional

Assume ~ 500 ft of hydrostatic

horizontal frictional loss?

head

Assume ~ 2000 ft of

How length of horizontal frictional Assume 2000 ft of

fricitional loss due to bubble flow loss would be

equivalent to 500 ft of hydrostatic head

13

hydrostatic head (~200psi)?

13

Horizontal well complexitiesHorizontal well complexities

Horizontal does not mean straight/constant. Inclination and azimuth varyInclination and azimuth vary

Gravity affects velocities, fluid collection, and flow regimesFrac ports liners and other IDFrac ports, liners, and other ID changes. Introduces friction, turbulence,

flow restrictionsflow restrictionsCased vs Open hole. Friction, corrosion, further flow

t i tirestrictionsSand production and accumulation.

14

Introduces friction, turbulence, flow restrictions

14

Horizontal Fluid AccumulationHorizontal Fluid Accumulation

This and following:

15

This and following:

Courtesy of BP-Calgary/ EPTG Noel15

Horizontal Two-phase Flow (cont.)Horizontal Two-phase Flow (cont.)

Flow regimes are very complicated. Flow has multiple variables Stratified Smooth Flow has multiple variables. Changes with angle, rate,

gas/fluid densities, temperature

Stratified Smooth

Stratified Wavy Flowp

Multiple flow types exist across all parts of well (horizontal and vertical)

Plug Flow

Slug FlowAlso two-phase flow has an negative influence on production rate.

Pressure lost due to friction

Slug Flow

Annular Flow

Pressure lost due to friction Changes to critical flow rate Changes in flowing gas

d it d t i t

Dispersed Bubble Flow

16

density due to moisture.

16

Simplified ModelSimplified Model

Pressure Loss

Figure 8: Gas-Liquid Flow Simplified Model

17

Figure 8: Gas Liquid Flow Simplified Model

17

Progression of Liquid Loading Progression of Liquid Loading

Gas Flow

Mist Annular Slug Bubble

Flow

Decreasing Gas Velocity

18

Topics CoveredTopics Covered

Introduction

1. Introduce, Recognize Loading

2. Introduce Solution Methods

3. Velocity string y g

4. Compression

5. Plunger

6 Beam P mping6. Beam Pumping

7. Gaslift

8. Hydraulic Pumping

9. Foaming

10. Injection Systems

11. Field Examples

19

p

12. New Techniques

Flow Regimes in Gas Well with timeFlow Regimes in Gas Well with time

HOLDUP (LIQUID) BUILDS WITH TIME

20

HOLDUP (LIQUID) BUILDS WITH TIME AND LOWER PRODUCTION

Flow Regimes in Gas/Liquid Flow Flow Regimes in Gas/Liquid Flow

Bubble Flow The tubing is almost completely filled with liquid. Free gas is present as small bubbles, rising in the liquid. Liquid contacts the wall surface and the bubbles serve only to reduce the density.

Slug Flow - Gas bubbles expand as they rise and coalesce into larger bubbles, then slugs. Liquid phase is still the continuous phase. The li id fil d th l f ll d d B th d li idliquid film around the slugs may fall downward. Both gas and liquid significantly affect the pressure gradient.

Slug Annular Transition The flow changes from continuousSlug-Annular Transition The flow changes from continuous liquid to continuous gas phase. Some liquid may be entrained as droplets in the gas. Gas dominates the pressure gradient, but liquid is still significantsignificant.

Annular-Mist Flow - Gas phase is continuous and most of liquid is entrained in the gas as a mist. The pipe wall is coated with a thin film of

21

entrained in the gas as a mist. The pipe wall is coated with a thin film of liquid but pressure gradient is determined predominately from the gas flow.

Flow Regimes with Time and DepthFlow Regimes with Time and Depth

22

Flow Regimes with Time and DepthFlow Regimes with Time and Depth

23

Effects of Liquid LoadingEffects of Liquid LoadingGas velocity in the tubing has dropped below the minimum required to move liquids up and out of the wellbore.

Liquids are settling in the bottom of the tubing

Gas flow is beginning to flowing heads (slug flow) where it has not before onset of liquid loading.

There are other symptoms as well

24

Problems from Liquid LoadingProblems from Liquid Loading

Less or no production. Less means production drops below the decline curve trendPossible damage or a water/condensate block onPossible damage or a water/condensate block on formation.More corrosion with more liquids resident in the tubingRequires artificial lift or other remedial measures and associated expenseand associated expense.

25

Source of LiquidsSource of Liquids

Produced along with gas

P d d f t tProduced from separate water zone

Condensed from the saturated gasCondensed from the saturated gas

Coned into gas zone with timeg

Other

26

Wet GasWet Gas

27

View of Condensation in Gas WellView of Condensation in Gas Well

ONE SOURCE OF LIQUIDS: WATER CONDENSING IN TUBING DOWNHOLE

28

CONDENSING IN TUBING: DOWNHOLE CAMERA

Other Sources of LiquidsOther Sources of LiquidsW t b d i f bWater may be coned in from an aqueous zone above or below the producing zone.

If the reservoir has aquifer support, the encroaching water will eventually reach the wellbore.

Water may enter the wellbore from another producing zone which could be separated some distance from the pgas zone

Free formation water may be produced with the gasFree formation water may be produced with the gas

Water and/or hydrocarbons may enter the wellbore in the vapor phase with the gas and condense out as

29

in the vapor phase with the gas and condense out as a liquid in the tubing

Effects of Loading on DeclineEffects of Loading on Decline

Normal Decline

Rate, MCFDMCFD

Loading

30

LoadingTime After Phillips & Listiack; SWPSC

Effects of Loading on DeclineEffects of Loading on Decline

Normal Decline

Rate, MCFD Goal ofMCFD Goal of

Artificial Lift

Loading

31

Time

Loading

After Phillips & Listiack; SWPSC

Well Loaded: Being cycled before lift addedWell Loaded: Being cycled before lift added

Sh t i

32

Shut inAfter Phillips & Listiack; SWPSC

Cycle to Liquid LoadingCycle to Liquid Loading

Fl iSh t i

33

FlowingShut in

Cycle to Liquid LoadingCycle to Liquid Loading

Flowing L diSh t i

34

Flowing Loading upShut in

z Flow Rate Declines (see Turner Curve)

Cycle to Liquid LoadingCycle to Liquid LoadingFlow Rate Declines (see Turner Curve)

z Velocity in Tubing Dropsz Settling Fluid Creates Back Pressure and Continues to Drop Flow Rate

High LinePPressure

Friction

Fl i L d OffL diSh t i

35

Flowing Logged OffLoading upShut inA well loads up when it is FLOWING at LOW gas rates!.

Shut-In WellShut-In Well

L d d

36

Loaded Shut inA well DOES NOT load up when it is shut in.


Tubing / Casing Pressures Tubing / Casing Pressures


100 PSI

130 PSI

100 PSI

100 PSI

100 PSI

220 PSI

100 PSI

80 PSI130 PSI 100 PSI

x

220 PSI

x

T bing

37

Normal Tubing Leak

Loaded Casing Leak

Pressures with a Packer in PlacePressures with a Packer in Place

0 PSI

100 PSI

0 PSI

130 PSI

0 PSI

100 PSI 101 PSI

0 PSI0 PSI 0 PSI 0 PSI 0 PSI


38

Flowing Unloaded

1-MinuteShut-in

Flowing Loaded

1-Minute Shut-in

Loading & Well IPRLoading & Well IPRLoading & Well IPRLoading & Well IPR

IPR = Inflow Performance Relationship

39

Typical IPR for Gas WellTypical IPR for Gas Well

800

s

i

a

500600700

s

s

u

r

e

,

p

s


300400500

n

g

P

r

e

s

100200

F

l

o

w

i

00 50 100 150 200 250 300

40

Rate, mcfd

Hi/Lo Shut-In Pressures for Gas WellHi/Lo Shut-In Pressures for Gas Well

700800

p

s

i

a

Higher Pressure Gas Well

400500600

r

e

s

s

u

r

e

,

Higher Pressure Gas Well

200300400

o

w

i

n

g

P Lower Pressure Gas Well

0100

0 50 100 150 200 250 300

F

l

41

0 50 100 150 200 250 300

Rate, mcfd

Effects of Loading on IPREffects of Loading on IPR

100 PSI

130 PSI

100 PSI

300 PSI


N l L d d

42

Normal Loaded

IPR: Reacting to Hi/Lo pressures IPR: Reacting to Hi/Lo pressures

350400

e

,

p

s

i

a

200250300

P

r

e

s

s

u

r

e

100150200

F

l

o

w

i

n

g

P

050

0 50 100 150 200 250 300

F

43

0 50 100 150 200 250 300

Rate, mcfd

Single Phase Radial Flow Gas EquationSingle Phase Radial Flow Gas Equation

44

Gas Well Back Pressure EquationGas Well Back Pressure Equation

n22Mscf/D )PwfC(PrQ, =

Exponent n reflects total turbulence effects- reservoir and completionand completion For low turbulence n ~ 1 For high turbulence n ~ .5

C and n are determined from multipoint flow tests

Flow after Flow Isochronal Modified Isochronal

45

Recognizing Liquid LoadingRecognizing Liquid Loading

Producing Symptoms

C iti l V l itCritical Velocity

Nodal AnalysisNodal Analysis

46

Slugs of Liquid through Gas Measure DeviceSlugs of Liquid through Gas Measure Device

Production of slugs of liquid g q

when previously not present.

Charts may not be used still look for slugging throughslugging through DP transducer?

47

Slugs still present but reduced Slugs still present but reduced

L li ?Lower line pressure?Reduced tubing size?Added heat??

48

Drop off decline curve indicates loadingDrop off decline curve indicates loading

Could be tubing leak Could be salting or sand over perforations

Decline w/wo Liquid Loading

But if not other problems then indicates liquid loading

Expected

Decline w/wo Liquid Loading

Actual with L dio

n

R

a

t

e

Loading

P

r

o

d

u

c

t

i

o

49

Time

Increase in CP minus TP: Loading likelyIncrease in CP minus TP: Loading likely

Tubing Pressure

Increase in Casing minus Tubing Pressure

ti i di t

C i

vs. time indicates loading

Casing Pressure

g Ps

iC

sg

Tbg

Time

50

Tubing survey or Echometer shot: LoadingTubing survey or Echometer shot: Loading

Results of Pressure Survey

Pressure

hD

epth

Gas

Liquid

51

Tubing Pressure Profile: What is Happening?Tubing Pressure Profile: What is Happening?

Tubing Pressure

Dep

Condensation

Gradient

Gas & liquid vapor

pth

Gas & liquid vapor gradient

Liquid over the perforations

52

Pressure

Loading Prediction: Critical Velocity or RateLoading Prediction: Critical Velocity or Rate

Buoyant weight of

Droplet in flowing gas

gdroplet in gas

Drag from flowing gasflowing gas tending to lift the droplet

53

Turner used Droplet model Not film modelTurner used Droplet model Not film model

( ) 3dgF ( )6g

gF GLC

Gravity =

2, )(2

1dGdDG

CUPDrag VVACg

F = Cg

Whereg = gravitational constant = 32.17 ft/s2gC = 32.17 lbm-ft/lbf-s2d = droplet diameterrL = liquid densityrG = gas densityCD = drag coefficientAd = droplet projected cross-sectional areaV = gas velocity

54

VG = gas velocityVd = droplet velocity

Equate Weight of Droplet to Uplift on DropletEquate Weight of Droplet to Uplift on Droplet

DG FF =

( ) 232

16 CdDGGL

VACdg =( )26 CdDGC

GLC gg

Substituting A = d2/4 and solving for V givesSubstituting Ad = d /4 and solving for VC gives,

( )GL dgV 4 ( )DG

GLC C

gV =

3

55

Hinze AICHE Journal Sept 1955 shows that droplet diameter dependence

Literature Correlation Predicts Droplet SizeLiterature Correlation Predicts Droplet SizeHinze, AICHE Journal Sept 1955, shows that droplet diameter dependence

can be expressed in terms of the dimensionless Weber number

302

== GCWE gdVN

Cg

Solving for the droplet diameter gives

g230CG

C

Vgd

=and substituting into Equation A-1 gives

( )2303

4

CG

C

DG

GLC V

gCgV

=

or

4/14/140

= GLCggV

56

2

= GDC CV

Substitute values of Cd and Surface TensionSubstitute values of Cd and Surface TensionTurner assumed a drag coefficient of CD = .44 that is valid for fully turbulent conditions. Substituting the turbulent drag coefficient and values for g and gC gives:

fV GL /514174/1

sftVG

GLC /514.17 2

=

WhereWhererL=liquid density, lbm/ft3rG=gas density, lbm/ft3s=surface tension, lbf/ftWritten for surface tension in dyne/cm units

i th i lbf/ft 00006852 d / iusing the conversion lbf/ft = .00006852 dyne/cm gives:

sftV GLC /59314/1

= sftV

GC /593.1 2

WhererL=liquid density, lbm/ft3r =gas density lbm/ft3

57

rG=gas density, lbm/ft3s=surface tension, dyne/cm

Calculate Gas Density: Real Gas LawCalculate Gas Density: Real Gas Law

Evaluating Equation A-4 for typical values ofGas gravity G 0.6Temperature T 120FTemperature T 120FGas deviation factor Z: 0.9gives:

3/0031.9)120460(

6.715.2 ftlbmPPG =+= 9.)120460( +

Typical values for density and surface tension areTypical values for density and surface tension areWater density 67 lbm/ft3Condensate density 45 lbm/ft3Water surface tension 60 dyne/cmCondensate surface tension 20 dyne/cm

58

Condensate surface tension 20 dyne/cm

C l l (E )

Field Equations: Turner & ColemanField Equations: Turner & Coleman

( ) fPPV /0031.674344600031.675931 4/14/1

Coleman, et al., (Exxon)

( )( )

( ) sftPPV waterC /0031.434.4600031.593.1 2/12, ==

( )PP 003145003145 4/14/1 ( )( )( ) sftP

PP

PV condC /0031.0031.45369.320

0031.0031.45593.1 2/12,

=

=

Turner et al (with 20% adjustment)

( ) sftPV /0031.673215 4/1=Turner et al., (with 20% adjustment)

( ) sftPV waterC /0031.321.5 2/1, =( ) sftPV /0031.450434 4/1

59

( )( ) sftPV condC /0031.043.4 2/1, =

Use Critical Velocity to find Critical RateUse Critical Velocity to find Critical Rate

Turner et al., (with 20% adjustment)

( )( ) sftP

PV waterC /0031.0031.67321.5 2/1

4/1

,=

( )( ) sftP

PV condC /0031.0031.45043.4 2/1

4/1

,=

2/1

4/12

, )0031(.)0031.45(

)460(0676.

)/(P

PZT

dPDMMscfq ticondensatet

+=

2/1

4/12

, )0031(.)0031.67(

)460(0890.

)/(P

PZT

dPDMMscfq tiwatert

+=

60

View Comparing Turner/ Coleman WHP DataView Comparing Turner/ Coleman WHP Data

61

Results from Shell Paper Results from Shell Paper

Evaluating Liquid LoadingField Data & Remedial MeasuresField Data & Remedial Measures

By Kees Veeken & Eelco Bakker, NAMNAM

Paul Verbeek, ShellThe NetherlandsThe Netherlands

2002 Denver Forum

62

Comparing to TurnerComparing to Turner

Turner Ratio vs Best Fit Combination of A and FTHP

4.00

3.00

3.50

y = 3.4441x-0.1717

R2 = 0 2085

2.00

2.50

T

R

(

-

)

R = 0.2085

1.00

1.50

0.00

0.50

0 100 200 300 400 500 600 700 800 900 1000

63

A0.5 x FTHP

Example of Using Shell CorrelationExample of Using Shell Correlation

Turner Ratio (TR) is ratio between actual and TurnerBest fit TR = 3.77 (A0.5 x FTHP) -0.172

Inflow resistance A ~ (Pdd / Q)xPr [ bar2 / 1000 m3/d ]

OR:TR = 3.77 (A0.5 x FTHP, psi/ 14.5) -.172

Example:

A = (0.1678)(Pwf,psi)(Pr,psi) / (Mscf/D)

Example:

Pwf=500Pr=3000Mscf/D = 2000Example:

Pwf = 300 psiPr = 800 psiMscf/D = 300

Mscf/D 2000A=12FTP = 1500TR 1 37A = 134

FTP = 100 psiTR = 3.77(134^.5 x 100/14.5) -.172 = 1.77 ... or actual predicted crit vel

TR = 1.37

64

velis 1.77 times the Turner value...

Critical Rates at Low PressuresCritical Rates at Low Pressures

CRITIAL RATE VS. FTP, DIA=1.995

1.4

1

1.2

1.4

A=1 TURNER

0 6

0.8

1

M

M

S

C

F

/

D

A=100A=200A=50

A l

0 2

0.4

0.6

M

COLEMAN

A values denote using Shell-Nam model

0

0.2

0 200 400 600 800 1000

FTP PSI

Nam model

65

FTP, PSI

Conclusions on Critical Rate at Low PressureConclusions on Critical Rate at Low Pressure

Depending on the A parameter, Shell Nam predicts different degrees of rate in addition to either Turner or Exxon at low pressuresor Exxon at low pressures

A Stripper Well Consortium Project will examine critical velocity requirements at low pressure and compare the data to existing methods

66

Critical Rate with assumptions includedCritical Rate with assumptions included

Using Turner s simplified assumptions of 20 and 60 dynes/cm surface tensions for condensate and water, 45 and 67 lbm/cu.ft. densities, gas gravity of 0.6 and 120 F for temperature gives:

4/1

2/1

4/1

)0031()p0031.( = Cv criticalgas 2/1, )p0031(.criticalgas

Turner: C= 5.34 water, or 4.02, condensate, p >1000 psiColeman: C= 4.43, water, or, 3.37, condensate, p < 1000 psi

67

, , , , , p p

Critical Velocity Cast as Critical RateCritical Velocity Cast as Critical Rate

AvpDMM fQ criticalgas ,

06.3)/(

zTDMMscfQ criticalgascritg +=

,, )460(

)/(

ftareaAwhere= 2

:

psiapftareaA

== ,

FTpp

=o

68

factorilitycompressibz =

Turner Critical RateTurner Critical Rate

DMM fAPVg /

067.3DMMscf

ZTq gg /)460( +=

2/1

4/12 )0031.45(0676.)/( PdPDMMscfq ticondensatet= 2/1, )0031(.)460()/( PZTDMMscfq condensatet +

4/12 )003167(0890 PdP2/1, )0031(.)0031.67(

)460(0890.

)/(PP

ZTdPDMMscfq tiwatert

+=

69

Divide rate by 1 2 for

Turner Critical Rate: Water: SimplifiedTurner Critical Rate: Water: SimplifiedDivide rate by 1.2 for Exxon correlation which is really better for pressures lower than 1000 psi

P is psia in below

Turner Unloading Rate for Well Producing Water

30004-1/2 OD 3.958 ID

2000

2500

)

3-1/2 2.992

2-7/8 2.441

2-3/8 1.995

2-1/16 1.751

1000

1500

R

a

t

e

(

M

c

f

d

0

500

70

0 50 100 150 200 250 300 350 400 450 500

Flowing Pressure (psi)

Example: Critical-2 3/8s, 100 psia, 320 Mscf/DExample: Critical-2 3/8s, 100 psia, 320 Mscf/D


2500

30004-1/2 OD 3.958 ID

3-1/2 2.9922-7/8 2 441

2000

M

c

f

d

)

2 7/8 2.441

2-3/8 1.995

2-1/16 1.751

1000

1500

R

a

t

e

(

M

0

500

71

00 50 100 150 200 250 300 350 400 450 500


Problem One: Critical Velocity Problem: Concept: Critical velocity charts like the below are usually used with the surface tubing pressure and may indicate if the well is above or below critical flow. However it can also be used to indicate what you might consider as severalHowever it can also be used to indicate what you might consider as several approaches to solve the problem, if it exists.


1500

2000

2500

3000

e

(

M

c

f

d

)

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

0

500

1000

0 50 100 150 200 250 300 350 400 450 500


R

a

t

e

Given 3 tubing and Pwh = 300 psi and a 1 MMscf/D rate.

1 - Would 2 7/8s tubing put the well above critical flow?2 - To what pressure would you have to lower the wellhead pressure in order to

obtain above critical flow (with a compressor and 3 inch tubing)3 - If foam reduces the critical flow rate by a factor of 2/3rds. Leaving 1/3 of

original critical rate for 3 at 1 MMscf/D would you then be above critical

72

original critical rate for 3 at 1 MMscf/D would you then be above critical flow?

Critical: Canadian Units Critical: Canadian Units

73

Weatherford

Problem One: Critical Velocity Problem: Canadian Version: Concept: Critical velocity charts like the below are usually used with the surface tubing pressure and may indicate if the well is above or below critical flow. However it can also be used to indicate what you might consider as severalHowever it can also be used to indicate what you might consider as several approaches to solve the problem, if it exists.

Given 3 tubing and Pwh = 689 kPa and a 28.3 E3m3/day rate.

1 - Would 2 7/8s tubing put the well above critical flow?2 - To what pressure would you have to lower the wellhead pressure in order to

obtain above critical flow (with a compressor and 3 inch tubing)3 - If foam reduces the critical flow rate by a factor of 2/3rds. Leaving 1/3 of

original critical rate for 3 at 28 3 E3m3/day would you then be above

74

original critical rate for 3 at 28.3 E m /day would you then be above critical flow?

Coleman Critical Rate: WaterColeman Critical Rate: Water

Coleman Unloading Rate for Well producing Water2500

2000 4-1/2 OD 3.958 ID3-1/2 2.9922-7/8 2.441

1000

1500

R

a

t

e

(

M

c

f

d

)

2-3/8 1.9952-1/16 1.751

500

00 50 100 150 200 250 300 350 400 450 500


75

Coleman: Water: Coiled TubingColeman: Water: Coiled Tubing

Coleman Unloading Rate for Well Producing WaterCoiled Tubing

800

900

1000

2.875 OD 2.499 ID

2.375 2.063

2.00 1.732

1 50 1 25

400

500

600

700

R

a

t

e

(

M

c

f

d

)

1.50 1.25

1.25 1.06

100

200

300

400

R

0

100

0 50 100 150 200 250 300 350 400 450 500


76

Turner: WaterTurner: Water

Turner Unloading Rate for Well Producing Water3000

2000

2500

4-1/2 OD 3.958 ID3-1/2 2.9922-7/8 2.4412-3/8 1.9952-1/16 1.751

1500

2000

R

a

t

e

(

M

c

f

d

)

500

1000

00 50 100 150 200 250 300 350 400 450 500


77

Turner: Water: Coiled TubingTurner: Water: Coiled Tubing

Turner Unloading Rate for Well Producing WaterCoiled Tubing

1000

1200

2.875 OD 2.499 ID2.375 2.0632.00 1.732

600

800

e

(

M

c

f

d

)

1.50 1.251.25 1.06

400

R

a

t

e

0

200

0 50 100 150 200 250 300 350 400 450 500

Fl i P ( i)

78


Above Critical at Surface: Below Surface? Above Critical at Surface: Below Surface?

Critical Flow Rate - Pressure with GrayCritical Flow Rate - Pressure with GrayCritical Flow Rate - Pressure with Gray0

1

2

Depth (1000 ft MD)Depth (1000 ft MD)Depth (1000 ft MD)Critical Flow Rate Pressure with GrayCritical Flow Rate Pressure with GrayCritical Flow Rate Pressure with Gray

Pfwh 312 psigFormation Gas Rate 2153 MscfdCondensate .0 bbl/MMscfWater .5 bbl/MMscf

2

3

4

5

Tubing String 1

5

6

7

8

ACTUAL

800 1000 1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600

8

9

Gas Rate (Mscfd)Gas Rate (Mscfd)Gas Rate (Mscfd)prob2prob2prob2

79

Problem 2: Critical with DepthProblem 2: Critical with Depth

Background: Usually the critical rate is evaluated at the top of the tubing. However the formulas for critical rate can apply at any point in the tubing. Program PRODOP calculates the required critical rate vs. depth and shows the user if the actual rate is above or below the critical over the entire tubing string.

WHT 100F (37 8 C) BHT 245 F (118 3 C)WHT: 100F (37.8 C) BHT: 245 F (118.3 C) Gas Rate: 555 Mscf/D (15.7 E3m3/d or 15700 m3/d) Condensate rate: 7.7 bbl/MMscf ( 43.26 m3/MMm3/d)Water rate: 111 bbl/MMscf (623.6 m3/MMm3/d)( )GG: .65 API: 43.3 WG: 1.03Tubing Pressure: 100 psi (689.4 kPa)2 3/8s to 9450 feet (60.325mm to 2881 meters) 1.8530 (47.066mm) ID Roughness: smooth pipe 0018 ( 04577mm)Roughness: smooth pipe .0018 (.04577mm)

Run on PRODOP and determine the critical rate required over the tubing depth vs. the actual rate.

80

tubing depth vs. the actual rate.

Note: you can adjust Prodop to SI units. Same for Snap

Problem 8: Critical in Casing and Tubing?Problem 8: Critical in Casing and Tubing?P bl Ei ht C iti l Fl ith D th d C i Fl t B tt f W llProblem Eight: Critical Flow with Depth and Casing Flow at Bottom of Well Concept: Tubing set a little above the perforations. Some casing flow above the

perforations. Check critical flow vs. actual flow for flow in the casing and in the tubing.

Run on PRODOP:Run on PRODOP:WHT: 100F (37.8 C)BHT: 245 F (118.33 C)Gas Rate: 444 Mscf/D (12.57 E3m3/d or 12565 m3/d) Condensate rate: 7.7 bbl/MMscf (43.26 m3/MMm3)Condensate rate: 7.7 bbl/MMscf (43.26 m /MMm )Water rate: 307 bbl/MMscf (1724 m3/MMm3)GG: .65API: 43.3WG: 1.03WG: 1.03Tubing Pressure: 100 psi (689 kPa)1.3151 to 9450 (33.4 mm to 2881meters) 0.9570 ID ( 24.3 mm ID)5 casing to 10,000 (139.7 mm casing to 3048.78 meters)Roughness: smooth pipe 0.0018 (.0457 mm)Roughness: smooth pipe 0.0018 (.0457 mm)Is well loaded at surface of tubing?Is well loaded at bottom of the tubing?Is well loaded in the casing? What is critical rate for the casing flow? Average rate?

81

What is critical rate for the casing flow? Average rate?

Problem: Casing or Tubing Flow:Problem: Casing or Tubing Flow:Problem Ten: Tubing or Casing Flow? 2 3/8 tubing 1.995 ID (60.325mm tubing 50.673mm ID)4 casing 3.958 ID (114.3 mm casing 100.533 mm ID)6000 depth (1829.3 meters)22 bbl/MMscf condensate (123 m3/MMm3)22 bbl/MMscf water (123 m3/MMm3)WG 1.03Condensate: 40 APIGG: .65Pwh: 100 psi (689 kPa)BHT: 150F (65.56 C)WHT: 100F (37.78 C)( )Rate: 1400 Mscf/D (39620 M3/D)Compare in PRODOP or SNAP the calculated flowing BHPs for

tubing and casing flow and critical rates and stable rates in

82

each.

Problem 12: Tapered Tubing StringProblem 12: Tapered Tubing Stringt t bi i d th d th f h P bl T l T d T bi St itwo tubing sizes and the depths of each. Problem Twelve: Tapered Tubing String: Background: Usually the critical rate is evaluated at the top of the tubing. However

the formulas for critical rate can apply at any point in the tubing. Program PRODOP calculates the required critical rate vs. depth and shows the user if the actual rate is above or below the critical over the entire tubing string. g g

WHT: 100F (37.78 C)BHT: 245 F (118.3 C)Gas Rate: 375 Mscf/D ( 10618 M3/d)Condensate rate: 7.7 bbl/MMscf (43.26 m3/MMm3)( )Water rate: 111 bbl/MMscf (623.6 m3/MMm3)GG: .65API: 43.3WG: 1.03Tubing Pressure: 100 psi or 689.4 kPa2 3/8s to 9450 1.8530 ID (60.325mm tubing to 2881m ) 47.066 mm ID Roughness: smooth pipe .0018 (.04572mm)If the bottom of the string has current flow blow critical, then insert a new string of g , g

tubing in PRODOP so that flow will be above critical flow for the bottom of the string as well as the top of the string. Insert the largest but still smaller string to cover the bottom of the string (and little more depth for safety factor) such that flow over the entire depth of the well is above critical flow.

Report the tapered string you determine and the

83

Report the tapered string you determine and the

Turner Critical: Smaller Tubing SizesTurner Critical: Smaller Tubing Sizes

1000

700800900

1000

t

e

,

m

c

f

d

400500600700

d

i

n

g

R

a

t 2.3752.0161.90

100200300400

n

U

n

l

o

a

d

1.66

0100

0 200 400 600 800

M

i

n

84

Surface Pressure, PSIA

Critical Changes with InclinationCritical Changes with Inclination

85

Critical Changes with InclinationCritical Changes with Inclination

( ) ( )( )[ ]907.1sin59341 38.025.025.0 glweNv ( )( )[ ]740767.0305934.1 2 = ggwe

cv

86

Question? Question?

Does well liquid load when: Flowing? Shut-in?

87

Question? Question?

Does well liquid load in the: Casing? Tubing?

88

Tubing size: Large-Loading, Small-FrictionTubing size: Large-Loading, Small-Friction

There must be a balance between liquid loading and friction. You need enough velocity to be above critical velocity but not so much as to have too much frictiontoo much friction.

89

Critical Questions: Which are 100% True?Critical Questions: Which are 100% True?Producing below the Critical Rate will cause the well to load up and quit flowing.Producing below the Critical Rate will cause the gwell to continue to flow but at a lower rate.Producing below the Critical Rate will damage the formationformation. Producing below the Critical Rate will not affect the production.Producing below the Critical Rate will create a higher pressure loss in the tubing and the well will either produce at a lower rate or could load up and die.

90

Does well quit flowing when below critical? Does well quit flowing when below critical? Exxon said on average with their data, production was 40% lessSutton, et al., Marathon, SPE 80887 modeled flow with gas bubbling through static liquid column.

91

Nodal Analysis: A Model of the Well Nodal Analysis: A Model of the Well

92

Inflow to the node

Nodal Analysis: TM of SchlumbergerNodal Analysis: TM of SchlumbergerInflow to the node

PR P (upstream components press drops) = PnodeOutflow from the node

Inflow

Psep + P (downstream components press drops) = Pnode

InflowOutflow

P

r

e

s

s

u

r

e

93

Rate

P

Reservoir: Gas Inflow CurveReservoir: Gas Inflow Curve

Reservoir Inflow curve often represented by:

Inflow

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

Inflow

P

r

e

s

s

u

r

e

94

Rate

P

Well Testing to Obtain Reservoir Inflow Well Testing to Obtain Reservoir Inflow

Objective is to calculate reservoir inflow at varying flowing wellbore pressures (the IPR)

Pr = average reservoir pressurePr = average reservoir pressurePwf = flowing well pressure at mid - perf depth or top of perforations

PR

PWF

95

Q

Well TestingWell Testing

Desirable to have 3 or more flow rates with pressure and rates recordedUsually short duration hours or daysUsually short duration - hours or daysReservoir is often in transient flow during testingNeed to be able to evaluate short term tests toNeed to be able to evaluate short term tests to accurately predict long term (years) behavior

96

Well TestingWell Testing

Flow after FlowIsochronalM difi d I h lModified IsochronalLaminar Inertia Turbulence (LIT) MethodJones Blount & Glaze Method (SPE 6133)Jones, Blount & Glaze Method (SPE 6133)

97

Pseudo Steady State Radial Flow for GasPseudo Steady State Radial Flow for Gas

qsc= 703 x 10-6 kgh (PR2-Pwf2)/ gZT {ln(.472re/rw) + (st+Dq) }(2-44) Golan p 2-9 WPM

qsc = gas flow rate, Mscfd,

kg = permeability to gas, md,gh = reservoir thickness, ft.

PR = average reservoir pressure, psia,

g = gas viscosity at T, P=.5 (PR + Pwf), cpZ = gas compressibility factor at T, P

T=reservoir temperature, R,

re=drainage radius, ft, and,

98

rw=wellbore radius, ft.

(st+Dq) =total skin plus pseudo skin due to turbulence

Deliverability Equations for GasDeliverability Equations for Gas

Jones et al - DArcy pseudo-steady solution for turbulence effects

P2R - P2WF = A qSC + B q2SC

Rawlins and Schellhardt postulated that the it ff t ld b t d i thcomposite effect could be represented in the

familiar gas well equation: q = C (P2 P2 )nqSC = C (P2R - P2WF)n

99

Gas Well Back-Pressure EquationGas Well Back-Pressure Equation

Gas Well Backpressure EquationqSC = C (p2R - P2WF)n

Exponent n reflects total turbulence effects-reservoir and completion-For low turbulence n ~ 1-For low turbulence n ~ 1 -For high turbulence n ~ .5 C and n are determined from multipoint flow tests

Flow after Flow IsochronalIsochronal Modified Isochronal (tests solve for constants in deliverability expressions)

100

Flow After Flow TestFlow After Flow Test

Start from shut - in condition Open choke and flow until gas rate and PWF stabilizeR d t d PRecord gas rate and PWFRepeat for at least three additional choke settings For best results P should be measured directlyFor best results, PWF should be measured directly with pressure bomb PWh can be used to calculate PWF but results are less reliable

101

Conduct of Flow After Flow Tests Conduct of Flow After Flow Tests

q1q2

q3q4

qsc

q1

Pr

time

P

Pwf1

Pwf3Pwf2

102

time

Flow After Flow Test CommentsFlow After Flow Test Comments

Must have stabilized flow for all rates (less than .1 psi change is surface pressure in 15 min.

Pseudo - stabilization (surface pressures stabilize before BHP fully stabilized) may occur

If a well is tubing limited (high tubing friction)

May be able to use static casing annulus pressure to determine stabilized flowdetermine stabilized flow

103

Time to Pseudo Steady StateTime to Pseudo Steady State

The time required for attain flow stabilization a circular drainage reservoir can be estimated fromcircular drainage reservoir can be estimated from

950 C (1 - Sw ) r2etS =

t =stabilization time, hoursit

kS

= porosity = viscosity k = perm , md

C = is total compressibility 1/psi C = is total compressibility, 1/psi re= radius of drainage, ft

Takes a long time for low k in the denominator

104

Analysis of Flow after Flow Tests: OilAnalysis of Flow after Flow Tests: Oil

Rewrite backpressure equation by taking log of both sides and rearranginglog (P 2 P 2) = (1/n) log (q ) (1/n) log(C)log (PR2 PWF2) = (1/n) log (qO) - (1/n) log(C)

Plot log (PR2- PWF2) vs log (qO) -slopePlot log (PR PWF ) vs log (qO) slope = 1/n - intercept = log (C)/n

105

Analysis of Flow After Flow Tests: GasAnalysis of Flow After Flow Tests: Gas

Rewrite backpressure equation by taking log of both sides and rearranging

log ( P2R - P2WF)=(1/n) log (qSC) - (1/n)log(C)

Plot log (P2R - P2WF) vs log (qSC) slope = 1/n intercept = log (C) /n

106

Flow After Flow Test Plot: GasFlow After Flow Test Plot: Gas

10,000 Reflects a zero sandface pressure

Reflects the

1,0002 )

sandfacepressure related to a particular back pressure0

Absolute open flow

(

P

r

2

-

P

w

f

2 pressure

Slope = 1/n

Sandface potential at

1 10 10

100

Absolute open flow potential

Sandface potential at the particular back pressure

qsc

107

1 10 100

qsc

Flow After Flow ExampleFlow After Flow ExampleDuration pwf, psia MMscf/D

0 201 0.0

3 196 2 733 196 2.73

2 195 3.97

2 193 4 44

Back Pressure Plot0.01

2 193 4.44

4 190 5.5

1 10

w

f

^

2

)

/

1

0

^

6

0 001

(

P

r

^

2

-

P

w

108

0.001

MMscf/D

Back Pressure PlotBack Pressure Plot

You should do a least squares curve fit of the points but you can just do a best straight line as shown previously. Once line is drawn, you can use any two

)l ()l (

previously. Once line is drawn, you can use any two points on the line to calculate n and C:

)log()log()log()log(

21

222

212

wfrwfr PPPPqqn

=ff

qC = nwfR PP

C)( 22

109

Flow After Flow Example Flow After Flow Example

Sample calculation: )log()log()log()log(

21

222

212

ff PPPPqqn

=)log()log( 12 wfrwfr PPPP

n=(ln(5.5)-ln(4.44)/ {ln(2012-1902) ln(2012-1932)}( ( ) ( ) { ( ) ( )}

= (1.7-1.49)/ (8.36-8.06)=.2141/0.3108= .6888

C = 5 5/(2012-1902)0.688 = 0173 MMscf/D/ psi2C = 5.5/(201 190 ) = .0173 MMscf/D/ psi

So: q = .0173(Pr2 Pwf2)0.6888

Check: q=.0173(2012-1902)0.688=.0173(4301).6888

= 5 5 MMscf/D So equation duplicates

110

= 5.5 MMscf/D .. So equation duplicates point!!

200

Enter C and n to Nodal Program for Inflow

150

200

g

50

100

P

r

e

s

s

u

r

e

,

p

s

i

g

0 5000 10000 15000 20000 25000 300000

Gas Rate, Mscf/DInflow @ Sandface (1) Not Used Inflow (1) Outflow (A) Not Used Not Used Not Used Not Used

11

Not Used Not Used Not Used Not Used Not Used Not Used Cond Unloading Rate Water Unloading Rate Max Erosional Rate Reg: james f lea - ttu

111

Q aof=.01573(2012)0.7= 26.37 Mscf/D

Problem 18: Find C and n from test dataProblem 18: Find C and n from test dataP bl Ei ht (18)Problem Eighteen (18):

Gas Back Pressure Equation: Normally we want a four point test for determining the gas flowNormally we want a four point test for determining the gas flow

equation and the AOF. Assume we have only the below 2 points.

What is C, MMscf/D/psi2n ? (or in m3/D / (kPa2n)What is nDoes this well exhibit any turbulence or is it all Darcy Flow? What is the AOF in MMscf/D? (Q when Pwf=0)F i d th b k ti iFor a reminder the back-pressure equation is:Remember to separate variables:

Pwf, psia MMscf/D or Pwf, kPa E3m3/D201 0 13485 6 0201 0 13485.6 0193 4.44 1330.5 125.6190 5.5 1309.86 155.6

Data: two point test

112

Data: two point test

Tubing Outflow Curve:Tubing Outflow Curve:

At low rates, liquid builds up in the tubing and requires more pressure to flow

s

s

u

r

e

Tubing J-Curve(Use various correlations, Gray, etc. )

FrictionLiquidho

l

e

p

r

e

s

FrictionLiquidBuildup

D

o

w

n

-

h

113

Rate

Nodal Analysis: StabilityNodal Analysis: Stability

114

Liquid Loading in Casing Below EOTLiquid Loading in Casing Below EOT

Critical Gas Rate Pressure with GrayC iti l G R t P ith GCritical Gas Rate Pressure with Gray

0

1

Depth (1000 ft MD)Depth (1000 ft MD)Depth (1000 ft MD)

Critical Gas Rate - Pressure with GrayCritical Gas Rate - Pressure with GrayCritical Gas Rate - Pressure with Gray

Pfwh 125 psigGas Rate 2000 mscf/dCond 0 bbl/MMscf

2

3

4

5

Cond .0 bbl/MMscfWater 15.0 bbl/MMscf2.375" at 10000 ftGray Correlation

Unloading

5

6

7

8Loading

Current Rate

0 800 1600 2400 3200 4000 4800 5600 6400 7200

9

10

11

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

Loading

115

Rate (mscf/d)( )( )

J-Curve Tubing PerformanceJ-Curve Tubing Performance

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

820860900

Flowing BHP (psig)Flowing BHP (psig)Flowing BHP (psig) Tbg - Critical Rate (Min BHP) = 547 mscf/dPfwh 125 psigCond .0 bbl/MMscfWater 15.0 bbl/MMscf2.375" at 10000 ft

Liquid loading occurs when gas rate is too low to

620660700740780

2.375 at 10000 ft

Stable flowHigh frictionMay have some liquid buildup

Unstable flowHigh liquid buildup

efficiently remove the produced liquidsThis results in unstable flow behavior and

460500540580620 behavior and

potential logging off of the well

0 200 400 600 800 1000 1200 1400 1600 1800 2000340380420460

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

Optimal Operation

116

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

Liquid Loading Liquid Loading

Liquid loadingLiquid loading occurs when gas rate is too low to

1600

1800 PSIAPSIAPSIANodal PlotNodal PlotNodal Plot

S1 - Tubing Flow - Ptbg = 500 psigS2 - Tubing Flow - Ptbg = 500 psigS3 - Tubing Flow - Ptbg = 500 psigPbar = 1450 psiaPbar = 1250 psia Pbar = 1050 psiaStable Flow

Cond .0bbl/MMscfWater 15.0bbl/MMscf

efficiently remove the produced liquids 1000

1200

1400

1600S1 - 2.375" at 10000 ft S2 - 1.9" at 10000 ft S3 - 1.66" at 10000 ft Gray Correlation

liquidsThis results in unstable flow b h i d 200

400

600

800

behavior and potential logging off of the well

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 13000Gas Rate (mscf/d)Gas Rate (mscf/d)Gas Rate (mscf/d)

117

Nodal Analysis: Tubing Size and Flow RateNodal Analysis: Tubing Size and Flow Rate

118

Predictions of Tubing Turnup: Biggest ErrorPredictions of Tubing Turnup: Biggest Error

119

Nodal Analysis Summary: Can Study Below:Nodal Analysis Summary: Can Study Below:

Effects of diameter sizeEffects of surface pressure (compression)Eff t f h t l d th t biEffects of where to land the tubingEffects of flow line pressure dropEffects of adding artificial lift such as gaslift orEffects of adding artificial lift such as gaslift or pumping methodsEffects of completion such as Shots-Per-Foot for a perforation jobEtc.

120

Problem 11 Problem 11

121

Problem 11 Continued: Duplicate below? Problem 11 Continued: Duplicate below?

122

Problem 13: Inflow with no well testsProblem 13: Inflow with no well testsP bl Thi t D t i P f ith NO W ll T tProblem Thirteen: Determine Performance with NO Well Tests: Use PRODOP use Modified Gray for multiphase flow gradient. Although it is best to have flow-after-flow tests or for tighter wells, Isochronal and for still tighter (lower

permeability) , modified Isochronal tests, and yet tighter analyze reservoir performance using reservoir models, and type curves, it is possible to estimate reservoir performance using numbers from our tubing flow correlations to build a reservoir expression for q=C(Pr^2-Pwf^2)^n. The accuracy of this method depends on the correlation used in the tubing but in many cases is sufficient to allow modeling of a gasdepends on the correlation used in the tubing but in many cases is sufficient to allow modeling of a gas well or liquid loaded gas well.

Tubing ID: 1.867No casing flow. Depth: 5000Use GrayWell is flowing @ 552 Mscf/D(15621 m3/D) The Pr is 785 psia (5441 kPa) given here and always required

either guess, measured, or from P vs. time decline curve. Pwh: 200 psigGG: .7WG: 1.02100% water100% water50 bw/MMscfTwh: 100BHT: 150 FWhat is the value of Pwf calculated using 552 Mscf/D (the current flow point). What is value of C in back pressure equation for N=1?p qWhat is value of C in back pressure equation for N=0.5What is AOF for N=1 in back pressure equation?What is AOF for N=0.5 in back pressure equation?If surface pressure reduced to 50 psia from compression, what is rate for N=1?If surface pressure reduced to 50 psia from compression what is rate for N=0.5? Thi h ld b k t th fl t f th d d P h i i d d t d ll t t f C

123

This should bracket the flow rate for the reduced Pwh using compression and you do not do well tests for C and N using flow-after-flow or any tests. But you do rely on the flowing BHP at the given rate to be calculated or measured correctly.

You can do same to evaluate different tubing sizes or different WHPs or other conditions.

QuestionQuestion

Based on the unloading curve, should you choke a well to prevent loading?

124

Effects of ChokeEffects of Choke

125

Choke Gas Wells for Help With Loading? Choke Gas Wells for Help With Loading?

However more recent evidence shows a choke may t d t bl fl b l iti l flextend stable flow even below critical flow

126

Select Solution to Loaded Well: Problem 7Select Solution to Loaded Well: Problem 7St bilit C iti l Fl P bl P blStability or Critical Flow Problem Problem: Concept: Dewatering can be solved by several approaches. Here you are asked to investigate some possibilities to see if

the Nodal Predications can be made to show stable flow although it may still be below critical.GG: 0.7230 bbls total /MMscf25% WC1.05 WG52 condensate APITubing: 9000 , 2 3/8sPwh: 1000 psiBHT 190 FBHT: 190 FTwh: 95FWell Test Data: Pr: 3600psiRates, Mscf/D Pwfs, psi225 3000225 3000275 2790325 2350390 1910Simulations Requested: Run as isRun with compression, with Pwf 800,600,400,200,100 and 50 psiRun with smaller tubing 1.095 IDRun with 12/64s choke at surfaceComment on each situation with respect to the fact it is solution or not depending on whether or not the

minimum in the tubing curve is to the left of the intersection of the tubing and reservoir curve or not?? Also note where a Turner Critical Rate would be

127

Also note where a Turner Critical Rate would be.

Inflow for Liquids (Oil and Water)Inflow for Liquids (Oil and Water)

For reference at this point two commonly used equations for liquid inflow, BPD are introduced.PI is for liquids coming into the well in absence ofPI is for liquids coming into the well in absence of any gasThe Vogel IPR is for the inflow of liquids, BPD, along with gas flowThe equation for PI and IPR are shown on the next two slidestwo slides We will use the liquid inflow equations when dealing with pumps and other lift techniques.p p q

128

Productivity Index (PI) BPD FlowProductivity Index (PI) BPD Flow

Simplest and most widely used relationship

Straight Line PI

1000

1200

1400

1600

s

i

)relationshipStraight linePI often called J in

0

200

400

600

800

1000

P

r

e

s

s

u

r

e

(

p

s

some text booksUnits stbpd/psiN t li bl t

0 200 400 600 800 1000 1200

Rate (STBLPD)Test Point PI Test Point

Not applicable to gas wells )(Pr Pwf

QPI =

129

Vogels Equation for Liquid Production when some gas is also flowing: Flow belowis also flowing: Flow below the bubble point

130

Composite IPR: Vogel/PI matched at PbComposite IPR: Vogel/PI matched at Pb

Vogel

Pb=Pr

131

Progression from PI to Vogel as in put Pb changes

Vogel: BPD Flow Vogel: BPD Flow

As watercut increases the IPR may approach PI modelPI model becomes straight line

rather than curved

Similarl skin effects orSimilarly skin effects or additional gas may cause the IPR to move to

the left become more curved

132

1.0 a introduce, recognize loading.pdf

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