Optimizing the productivity of gas-condensate wells - (2006).pdf

8/12/2019 Optimizing the productivity of gas-condensate wells - (2006).pdf

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SPE 103255

Optimizing the Productivity of Gas/Condensate WellsC. Shi, R.N. Horne, and K. Li, Stanford U.

Copyright 2006, Society of Petroleum Engineers

This paper was prepared for presentation at the 2006 SPE Annual Technical Conference andExhibition held in San Antonio, Texas, U.S.A., 2427 September 2006.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than300 words; illustrations may not be copied. The abstract must contain conspicuous

acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractGas-condensate reservoirs exhibit complex phase and flow

behaviors due to the appearance of condensate banking in the

near-well region. A good understanding of how the condensateaccumulation influences the productivity and the composition

configuration in the liquid phase is very important to optimize

the producing strategy, to reduce the impact of condensate

banking, and to improve the ultimate gas recovery.

This study addressed several issues related to the behavior of

the composition variation, condensate saturation build-up and

condensate recovery during the gas-condensate producingprocess. A key factor that controls the gas-condensate well

deliverability is the relative permeability, which is influenced

directly by the condensate accumulation. The accumulatedcondensate bank not only reduces both the gas and liquid

relative permeability, but also changes the phase composition

of the reservoir fluid, hence reshapes the phase diagram of

reservoir fluid and varies the fluid properties. Different

producing strategies may impact the compositionconfiguration for both flowing and static phases and the

amount of the liquid trapped in the reservoir, which in turn

may influence the well productivity and hence the ultimate gas

and liquid recovery from the reservoir. Changing the manner

in which the well is brought into flowing condition can affectthe liquid dropout composition and can therefore change the

degree of productivity loss.

In this study, compositional simulations of multicomponent

gas-condensate fluids were conducted at field scale to

investigate the composition and condensate saturation

variations. Different producing strategies have been compared,and the optimum producing sequences are suggested for

maximum gas recovery. A core flooding experiment with two-

component synthetic gas-condensate was designed andconstructed to model gas-condensate production behavior

from pressure above the dew-point to below. Experimental

observations of gas-condensate production confirm the

dramatic changes in the liquid composition seen in the

simulations.

IntroductionLiquid forms in a gas-condensate reservoir when the bottom-

hole pressure drops below the dew-point pressure. The

accumulated condensate in the vicinity of the well bore causea blockage effect and reduces the effective permeability

appreciably, and also causes the loss of heavy components atsurface. These effects depend on a number of reservoir andwell parameters.

The productivity loss caused by the condensate buildup is

striking. In some cases, the decline can be as high as a factor

of two to four, according to the case studies of Afidick et al.and Barnum et al.2. Even in very lean gas-condensate

reservoirs with a maximum liquid drop out of only 1%, the

productivity may be reduced by a factor of about two as thepressure drops below the dew-point pressure1. In order to

predict well deliverability and calculate gas and liquid

recovery, it is necessary to have a detailed knowledge of liquid

banking in gas-condensate fields.

Fevang and Whitson3 addressed the well deliverability

problem in their gas-condensate modeling, where they

observed that well deliverability impairment resulting from

near well-bore condensate blockage depends on PVTabsolute and relative permeabilities, and how the well is being

produced.

The relative permeability effect has been reported in field

observations. Variations of reservoir fluid PVT properties a

discovered condition have been observed and discussed formany reservoirs around the world (for example reference 4 for

mid-eastern reservoirs and reference 5 for North Seareservoirs). Lee6 also presented an example to show the

variation of composition and saturation of the gas-condensate

system due to the influences of capillary and gravitationaforces.

Roussennac7illustrated the phase change during the depletionin his numerical simulation. According to Roussennac, during

the drawdown period, with the liquid building up in the well

grid cell, the overall mixture in that cell becomes richer in

heavy components, and the fluid behavior changes from theinitial gas-condensate reservoir to that of a volatile/black oil

reservoir.


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2 SPE 103255

The well producing scheme may impose significant impacts

on PVT properties. However, the manner by which the

producing scheme influences the PVT properties has not yetbeen sufficiently addressed. This study aims to investigate the

producing strategy and its influences on productivity and

composition.

Compositional simulations of a multicomponent gas-condensate system and a binary-component gas-condensate

system were conducted here. To confirm the compositionalvariations resulting from producing strategy, a core flood

experiment has also been designed and constructed to

investigate the gas-condensate flow behavior in porous media.

The simulation models, the experimental apparatus and theprocedures are described here. Following that, the simulation

results and the experimental results are presented. Finally,

some conclusions are drawn.

Simulation models

Multicomponent simulation model

The primary objective of the simulation was to understand the

impact of producing scheme on the condensate banking and

compositional variations. A hypothetic cylindrical reservoir

model, with radius of 5200 ft and permeability-thickness of 20

md50 ft has been chosen, and a simulator E300 (2005a,Eclipse) with fully implicit (FULLIMP) method was used to

simulate the performance under different producing strategies.

The multicomponent fluid properties are shown in Table 1.Additional laboratory liquid dropout data were used to

correlate with equation of state (EOS) phase-behavior

calculation. The PVT program used in this study was PVTi byGeoquest. The Modified Peng-Robinson EOS was used to

perform the fluid characterization. Figure 1 shows the liquiddropout calculation from a tuned EOS, which matches well

with the measured data. Figure 2 shows the phase envelope for

this multicomponent gas-condensate system. The EOSpredictions were then used as the input to the simulator.

Table 1: Fluid composition of gas-condensate

Component

N2CO2C1C2C3

iC4nC4iC5nC5C6C7C8C9

C10+C10+MW

C10+density (g/cm3)

Fluid (mol%)

0.00850.0065

0.8358

0.0595

0.0291

0.00450.0111

0.0036

0.0048

0.00600.0080

0.0076

0.00470.0103

183

0.8120

0.5 1 1.5 2 2.5 3

x 107

0

0.5

1

1.5

2

2.5

3

3.5

4

Pressure (MPa)

Liqu

idd

ropout

liquid dropout (simulated)

liquid dropout (experimental)

Figure 1: Liquid dropout from constant volume depletion (CVD)experiment.

Figure 2: Phase diagram of a multicomponent condensatesystem.

In the simulations, small radii around the well-bore were

chosen to allow for accurate pressure drop calculation in the

near well-bore region.

In porous media, PVT properties are controlled by the in-situreservoir temperature, pressure and the porous media

properties. In this study, no temperature change has been

considered. Hence, the PVT properties are determined by the

in-situ reservoir pressure and the way the heavy components

accumulate. In order to investigate how the producing strategyinfluences the condensate blockage and hence, the final gas

recovery, two sets of simulations were conducted, one with

fixed bottom-hole pressure (BHP) strategy with different BHPsettings and the other with varying BHP as a function of time,.

Binary-component simulation model

To investigate the composition and saturation change resultingfrom the producing scheme, a binary-component gas-

condensate system was selected to conduct the core flooding

experiment. Figure 3 shows the phase diagram of the C1/C4(85%/15%) synthetic gas-condensate system. This system haslow critical temperature (Tc = -13.2 C) and critical pressure

(pc= 1760 psi), which makes the experiment easy to perform

under room temperature and within relatively low pressure


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4 SPE 103255

These four sampling points are shown in Figure 3. All gas

samples were collected in the sampling bags and sent to the

gas chromatograph for composition analysis.

Results and Discussion

Experiment results

Figure 5 shows the gas chromatograph results for all the gassamples. Notice that the first batch of gas samples, which were

collected before the flow test, show slightly differentcomposition for the same component (C1 or C4) at different

sample ports and these compositions also differ slightly from

the initial compositions. The samples taken at the sample port

2 and 6 are the only two samples exactly equal to the initialcompositions. Sample 1, 3 and 4 show higher C4percentage

and sample 5 shows lower C4 percentages compared to the

initial 19% C4percentage. This may be due to the fact that the

core was presaturated with pure methane at pressure 1,800 psi.

When the upstream pressure drops, more gas condensate drops

out into the core, and the accumulated condensate liquid,which is richer in heavier component, can not flow until the

condensate saturation reaches the threshold saturation on the

relative permeability curve. Hence the flowing phase consists

of lighter component; this is confirmed by the composition

decrement in C4component in the second and the third flowtest.

When the core system pressure drops below the pressure

corresponding to the maximum liquid drop-out point, thecondensate starts to revaporize. A higher percentage of heavier

component was expected to be seen at this stage. This is

confirmed by the composition results from the last batchsamples (batch 4), where the sampling pressure was only 61.5

psi and the C4composition is as high as 57.5%. At this pointin the experiment, the accumulated heavy component was

revaporized and recovered.

0

10

20

30

40

50

60

70

1 2 3 4 5 6

Port

C4(%)

Batch 1

Batch 2

Batch 3

Batch 4

Flow direction

original

composition

0

10

20

30

40

50

60

70

1 2 3 4 5 6

Port

C4(%)

Batch 1

Batch 2

Batch 3

Batch 4

Flow direction

original

composition

Figure 5: Gas sample results for the mole fraction of C 4 in theflowing phase.

Multicomponent simulation results

In the field scale simulation results, Figure 6 shows the

condensate saturation profiles vs. radius rfor different times.

The region of interest here is the two-phase zone. As expected

as the production proceeds, the pressure-drop expands to

regions further away from the producing well. Once thepressure drops below the local dew-point pressure, condensate

drops into the reservoir and accumulates until the accumulated

liquid saturation reaches the relative permeability threshold

From the figure, we can also see that the near well region has

the greatest liquid accumulation resulting from the early liquiddrop-out.

Figure 7 shows mole fractions of C7for the liquid phase. The

trend is similar to that of saturation profiles, noticing that the

heavy component (C7, in this case) accumulation is more

prominent in the near well region.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.1 1 10 100 1000 10000

Radius r (ft)

S

c(fraction)

t = 0.5 day t = 1.5 days t = 102 days t = 206 days t = 345 days

t = 575 days t = 670 days t = 755 days t = 840 days t = 900 days

t = 940 days t = 980 days t = 990 days t = 1000 days

increasing producing time

Figure 6: Saturation profiles at different times.

0

0.01

0.02

0.03

0.04

0.05

0.06

0.1 1 10 100 1000 10000

Radius r (ft)

C7

inliquidphase(fra

ction)

t = 0.5 day t = 1.5 days t = 102 days t = 206 days t = 345 days

t = 575 days t = 670 days t = 755 days t = 840 days t = 900 days

t = 940 days t = 980 days t = 990 days t = 1000 days

increasing producing time

Figure 7: Mole fraction profiles of C7in liquid phase.

a) Strategy of fixed BHP

In a PVT cell, the liquid drop-out from the gas-condensate

system can be revaporized if we either lower the BHP orincrease the BHP. However, in a porous medium, the

liquid drop-out is immobile unless the liquid accumulation

reaches the critical condensate saturation value on the

relative permeability curve. The accumulated condensate isgenerally made up of heavier components and hence

changes the local phase composition. Whether the

condensate build-up can be revaporized is mainlydetermined by the local fluid composition. Figure 8 shows

the saturation profile for different well BHPs. We can see


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SPE 103255 5

that the liquid saturation still accumulates as the BHP

drops, and no revaporization appears to happen for this

particular fluid system.

As the BHP drops, more C7, one of the heavy components,

drops to the liquid phase (Figure 9). Although the total gas

production (Figure 10) increases as the BHP decreases, the

well productivity (Figure 11) drops dramatically as liquidsaturation builds up.

Figure 12 and Figure 13 show that as the BHP decreases,

the two-phase region expands, and more heavy-

component will be left in the reservoir.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 100 200 300 400 500 600 700 800 900 1000

Time (days)

SC

(fraction)

BHP = 2000 psi BHP = 500 psi BHP = 1000 psi BHP = 1500 psi


decreasing BHP

Figure 8: Condensate saturation profile for different BHP.

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0 100 200 300 400 500 600 700 800 900 1000

Time (days)

C7inliquidphase(fracti

on



decreasing BHP

Figure 9: Mole fraction profiles of C7in liquid phase.

0

5000000

10000000

15000000

20000000

25000000

30000000

35000000

40000000

45000000

50000000

0 100 200 300 400 500 600 700 800 900

Time (days)

W

GPT(mscf)



decreasing BHP

Figure 10: Total gas production profile for different BHP.

0

20

40

60

80

100

120

140

160

180

200

0 100 200 300 400 500 600 700 800 900

Time (days)

WPIG(mscf/day-p

si)

BHP = 2000 psi BHP = 500 psi BHP = 1000 psi BHP = 1500 ps

BHP = 2500 psi BHP = 3000 psi BHP = 3500 psi BHP = 4000 ps

decreasing BHP

single phase

two phases

Figure 11: Well productivity index (WPIG) profiles for differenBHP.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.1 1 10 100 1000 10000

Radius r (ft)

Sc

(fraction)



decreasing BHP

Figure 12: Comparison of condensate saturation profiles fordifferent BHP at t = 1000 days.


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6 SPE 103255

0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

0.08

0.09

0.1 1 10 100 1000 10000

Radius r (ft)

C7

inliq

uidphase(fraction



decreasing BHP

Figure 13: Comparison of mole fraction profiles of C7 in liquidphase at t = 1000 days.

In this case, we can decrease the BHP to achieve greater

pressure difference; hence temporarily to produce more gasfrom the reservoir. However, lowering the BHP will cause the

expansion of the two-phase region, and the accumulation ofmore heavy-component in the reservoir. Hence, lowering the

BHP may not be a good strategy for maximizing total fluidrecovery.

b) Strategy of BHP ramping as a function of time.

Instead of setting BHP at a fixed value, we can also control theBHP such that it ramps as a function of the producing time.

For all simulation tests in this case, the initial reservoir

pressure and the final well bottom-hole pressure control werethe same.

Figure 14 shows the ramping strategies used in this study.

Increasing the ramping time, the gas production rate increasesat the late producing life, although the initial production rate islow due to the smaller pressure difference (Figure 15). The

well loses some gas production in total when the ramping time

increases (Figure 16). However, the well productivity index

reduction is delayed from the high productivity of single-phase flow to low productivity of two-phase flow (Figure 17).

The accumulation of condensate saturation (Figure 18) and

heavy component (Figure 19) are also delayed.

1500

2000

2500

3000

3500

4000

4500

5000

5500

0 100 200 300 400 500 600 700 800 900 1000

Time (days)

WBHP(psi)

Increase ramping time

Figure 14: BHP ramps as functions of time.

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

0 100 200 300 400 500 600 700 800 900

Time (days)

WGPR(mscf/day)


Figure 15: Gas production rate profiles for different rampingstrategies.

0

5000000

10000000

15000000

20000000

25000000

30000000

35000000

40000000

45000000

0 100 200 300 400 500 600 700 800 900

Time (days)

WGPT(mscf)


Figure 16: Total gas production profiles for different rampingstrategies.

0

20

40

60

80

100

120

140

160

180

200

0 100 200 300 400 500 600 700 800 900

Time (days)

W

PIG(mscf/day-psi)


Figure 17: Well productivity index profiles for different rampingstrategies.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0 100 200 300 400 500 600 700 800 900

Time (days)

Sc

(fraction)


Figure 18: Condensate saturation profiles for different rampingstrategies.


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SPE 103255 7

0

0.01

0.02

0.03

0.04

0.05

0.06

0 100 200 300 400 500 600 700 800 900 1000

Time (days)

C7

inliquidphase(fraction)


Figure 19: mole fraction profiles for C7in liquid phase at differentramping strategies.

From Figures 20 and 21, we can see that by increasing theramping time, the two-phase region can be effectively shrunkby a factor as much as 10, and less heavy-component can beleft in the reservoir. This is very meaningful from the point ofthe long-term field development since it has been reportedfrom many field cases that the heavy components are difficult

to recover once they have been left in the reservoir.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.1 1 10 100 1000 10000

Radius r (ft)

Sc

(fraction)

ramp = 0 ramp = 1000 ramp = 100 ramp = 200 ramp = 300 ramp = 400

ramp = 500 ramp = 600 ramp = 700 ramp = 800 ramp = 900

Producer


Figure 20: Saturation profiles for different ramping strategies att = 1000 days.

0

0.01

0.02

0.03

0.04

0.05

0.06

0.1 1 10 100 1000 10000

Radius r (ft)

C7inliquidphase(fraction

ramp = 0 ramp = 1000 ramp = 100 ramp = 200 ramp = 300 ramp = 400

ramp = 500 ramp = 600 ramp = 700 ramp = 800 ramp = 900

Producer


Figure 21: Mole fraction profiles of C7in liquid phase for differentramping strategies at t = 1000 days.

Two-component simulation results

Figures 22 to 29 show the simulation results for the binary-component methane/butane system. These are a representationof flow in the experiment described earlier. The generaconclusions for the BHP strategy are the same for bothmulticomponent and binary-component systems. That is, thetotal gas production increases as a result of greater pressure

difference between the reservoir and the well, but at the sametime, lower BHP also brings more heavy-component into thereservoir and generates a larger two-phase region. For thiparticular binary combination of C1 and C4, the saturationprofile (Figure 22) shows decreases after the accumulatedcondensate saturation reaches a maximum value. Noticing thathis maximum condensate saturation (Scam =0.53) is greaterthan the critical condensate saturation (Sac=0.25) from therelative permeability curve. The mole fraction of C4 in theliquid phase also drops as the well continues producing. Thereason is that some revaporization of the in-place liquid phasetakes place; thus the two-phase zone varies as the well keepsproducing.

Figure 25 shows that the well gas productivity dropssignificantly from single-phase flow to two-phase flow and thelower the BHP, the greater the drop in gas productivity.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 5 10 15 20 25 30

Distance (cm)

Sc

t = 0.005h t = 0.01h t = 0.015h t = 0.02h

t = 0.025h t = 0.035h t = 0.055h t = 20h

flow direction

Figure 22: Saturation vs. distance for binary-componencondensate system at BHP = 75 atm.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

0 5 10 15 20 25 30

Distance (cm)

C4inliquidphase

t = 0.005h t = 0.01h t = 0.015h t = 0.02h

t = 0.025h t = 0.035h t = 0.055h t = 20h

flow direction

Figure 23: Mole fraction of C4 vs. distance at BHP = 75 atm.


8/9

8 SPE 103255

0

10000000

20000000

30000000

40000000

50000000

60000000

0 5 10 15 20 25

Time (hour)

WGPT(scc)

BHP = 75 atm BHP = 25 atm BHP = 35 atm BHP = 45 atm


BHP = 105 atm BHP = 115 atm

decreasing BHP

Figure 24: Total gas production profiles for different BHP.

0

200000

400000

600000

800000

1000000

1200000

1400000

1600000

0.001 0.01 0.1 1 10 100

Time (hour)

WPIG(scc/hour-atm)




increasing BHP

singlephase

region

twophasesregion

Figure 25: Well gas productivity profiles for different BHP.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.001 0.01 0.1 1 10 100

Time (hour)

Sc

(fraction)


BHP = 55 atm BHP = 65 atm BHP = 85 atm BHP = 95 atmBHP = 105 atm BHP = 115 atm

increasing BHP

Figure 26: Condensate saturation vs. time for different BHP.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0.001 0.01 0.1 1 10 100

Time (hour)

C4

inliquidphase




decreasing BHP

Figure 27: Mole fraction of C4vs. time for different BHP.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 5 10 15 20 25 30

Distance (cm)

Sc

BHP = 75 atm BHP = 25 atm BHP = 45 atm


flow direction

decreasing BHP

Figure 28: Saturation vs. distance for different BHP at t = 20h.

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 5 10 15 20 25 30

Distance (cm)

C4

inliquidphase(fraction



flow direction

decreasing BHP

Figure 29: Mole fraction of C4vs. distance for different BHP at t =20h.


9/9

SPE 103255 9

In summary from the simulation results, we can conclude that

there is no standard way to optimize the producing strategy.

Using low BHP or rapid ramping time for BHP, we canachieve high total gas production temporarily, however, to

minimize the condensate banking blockage and hence to

enhance the ultimate gas and liquid recovery, higher BHP or

slower ramping time for BHP may be a better strategy. The

optimal approach is likely to be dependent on the originalcomposition.

Conclusions1. In gas-condensate flow, local composition changes

due to relative permeability effects.

2. Composition and condensate saturation changesignificantly as a function of producing sequence.

The higher the BHP, the less the condensate banking

and a smaller amount of heavy-component is trapped

in the reservoir; increasing ramping time of BHP will

also help to alleviate the condensate banking andheavy-component trapping.

3. Gas productivity can be maximized with properproducing strategy. The total gas production can be

achieved by lowering the BHP or dropping the BHP

quickly instead of ramping slowly to a preset BHP

value.

4. Productivity loss can be reduced by optimizing theproducing sequence.

5. The condensate drop-out will hinder the flow

capability, due to relative permeability effects.

NomenclatureN2 nitrogen

CO2 carbon dioxideC1 methane

C2 ethaneC3 propane

iC4 i-butane

nC4 n-butaneiC5 i-pentane

nC5 n-pentane

C6 hexaneC7 heptane

C8 octane

C9 nonaneC10+ decene

MW molecular weight

CVD constant volume depletion

BHP bottom-hole pressureScc critical condensate saturationSc condensate saturation

WPIG gas productivity index of a well (mscf/day-psi or

scc/hour-atm)

WGPT well total gas production (mscf or scc)Tc critical temperature (K or C)

pc critical pressure (psi or atm)

AcknowledgementsWe would like to express our appreciation to Saudi Aramaco

and the members of SUPRI-D (Research Consortium onInnovation in Well Testing) for financial support and usefu

discussions.

References

1. Afidick, D., Kaczorowski, N.J., and Bette, S., 1994Production Performance of a Retrograde Gas: A Case Study

of the Arun Field, paper SPE 28749 presented at the SPEAsia Pacific Oil & Gas Conference held in Melbourne

Australia.

2. Barnum, R.S., Brinkman, F.P., Richadson, T.W. andSpillette, A.G., 1995 Gas Condensate Reservoir Behavior

Productivity and Recovery Reduction Due to Condensation,

paper SPE 30767 presented at the SPE Annual Technica

Conference and Exhibition, Dallas, TX.

3. Fevang, O. and Whitson, C.H., 1996 Modeling Gas-

Condensate Well Deliverability, paper SPE Res. Eng., P221-230.

4. Riemens, W.G. and de Jong, L.N.J.: Birba Field PVT

Variations Along the Hydrocarbon Column and Confirmatory

Field Tests, paper SPE 13719 presented at the SPE 1985Middle East Oil Technical Conference held in Bahrain, March

11-14, 1985.

5. Schulte, A.M.: Compositional Variation within aHydrocarbon Column Due to Gravity, paper SPE 9235

presented at the 55th Annual Technical Conference and

Exhibition held in Dallas TX September 21-24, 1980.

6. Lee, S.T.: Capillary-Gravity Equilibria for HydrocarbonFluids in Porous Media, paper SPE 19650 presented at the

64thAnnual Technical Conference and Exhibition held in San

Antonio TX October 8-11, 1989.

7. Roussennac, B., 2001 Gas Condensate Well Tes

Analysis, MS report, Stanford University.

SI metric conversion Factorsatm 1.013250 * E+05 = Paft3 1.589873 E-01 = m3

F (F-32)/1.8 = C

in.3 1.638706 E+01 = cm3

psi 6.894757 E+00 = kPa

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