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BACK-PRESSURE TESTS ON . GAS-CONDENSATE WELLS f

BSTR CT

A

method is proposed for the determination of baek-

pressure tests on gas-condensate wells. It is a modifica-

tion of the regular back-pressure test conducted on low-

pressure dry gas wells, as outlined.in Bureau o f Mines

Monograph

7.

A modification is required due to the

presence of liquid in the well stream and the error in

INTRODUCTION

The back-pressure tes t on ga s wells is a result of t he

gas industry's search during the past decade for a re-

liable standardized method of determining the ability

of gas wells to produce gas.

Many people have con-

tributed t o its development, an d a comprehensive report

on the subject by Rawlins and Schellhardtl was made

available

1936 with the publication of B z t r e w ~ of

Mine s Mo logrnpk :

Back-Pressure Data on Natural-

Gas Wells and their Application to Production Prac-

tices, which ha s become th e st an da rd guide and refer-

ence source on the subject.

The method is basically sound in theory, and has

been proved practical in actua l use. However, all th e

original development of the method was done on wells

which were of relatively low pres sure and liquid hydro-

carbon content. With the advent of th e deep high-

pressure gas-c6ndensate wells, the method, without

modification, could not be applied with any great re-

liability. A modified method, identi cal in gen era l prin-

ciple, is proposed. Thi s method is discussed herein.

The principle of the back-pressure test is that the

gen eral steady-st'ate equati on of flow of a ny g as well,

is of the form:

Q =

C ( P f 2 e 2 ) 1 )

W h e r e :

Q = ra te of flow at a sand-face pressu re of P s

P. =

sand-face pressure a t ra te of flow,

Q

Pi = reservoir pressure.

C =

a consta nt fo r any given well.

n a consta nt fo r an y given well.

The modified method assumes equation ( 1 ) to ap-

ply. The presence of liquid sat ura tio n

in the reservoir

ha s been shown by Rawlins an d Schellhardt,' Lev ere tt

a nd ~ e w i s , ? nd others to change the effective permea-

bility; but, a s the change in amount of liquid satura-

tion with reduced flowing pressures is approximately

State of Louis iana Del ~ar tn~ entf Conservation Division

of Aline rals B at on Rouge. La remcbved. Apr. 1942, to Cruf t

Laboratory Hnrvar d University. Cambridge, Mass.; removed.

Peb. 1943: ' to Radiation Laboratory, Infisnchusetts Ins tit ute of

Technology. Cambridge, Mass

? Presented a t sprlng meeting, Southwestern District, Divi-

sion

of

Production. Dallnci. Texas, Beb.

26-27,

1042.

P i g ~ ~ r r sefer to

REFERENCES

on p. 86

Weyn~outh s friction formula as noted by Miller. De-

terminations of sand-face pressures from well-head

measurenlents are obtained from published data on den-

sities of gases and pressure drop due to flow. Necessary

precautions to be observed in making well-head mea-

surenlents are outlined.

linear over the normal drawndown pressure range, a nd

as the change in effective permeability is also approxi-

mately linear over this same range, i t follows tha t one

might expect the characteristic flow equation ( 1 ) of

a

gas-condensatG well to have a sm all er value of t he ex-

ponent

z

and the coefficient

C

than it would have if it

were a dry gas well.

Difficulties arise in insuring stabilized flow in the

well, and in determining sand-face pressures.

~t~h i l i za t ionf as ~ondeisate Wells

As already mentioned, the general flow equation

( 1 )

of a gas well applies to the steady state, i.e., the well

mus t be stabilized. I n the simplest terms, sacrificing

rigor for the sake of simplicity, a well is stabilized

when both the r at e of flow and well pressu res individu-

ally become and rem ain constant. The reservoir itself,

depending on its permeability, porosity, fluid content,

an d, configuration, requires a certain amount of time

to set up stabilized flow. When th e fluid gets into the

well bore, if it is all gas it will flow up the tubing to

the surface, and stabilized flow within the tubing will

he established in a ma tt er of a f ew minutes. However,

if the fluid is part liquid, as in most gas-condensate

wells, this liquid will tend to be raised to the surface

by the gas; in other words, the liquid will tend to be

gas-lifted j ust a s in th e case of flowing oil wells or

artific ial gas-l ift oil wells. If the well is not flowed

hard enough, the liquid will not be lifted except in

er rat ic slugs -Land th us stabilization will be pre-

vented. I t ha s been found by Flaitz and Parks: in

connection with .sampling gas-condensate wells, t ha t a

linear velocity of

15

to 20 f t per sec in the tubing is

usually sufficient to in sur e stabilized flow. However,

the a ut ho rh as found linear velocities of 6 to 1 0 f t p e r

sec sufficient to give stabilized flow for back-pressure

tests on wells with gas-oil ratios of approximately

25,000 cu f t per bbl. These figures cannot be taken

exactly, as a lot depends on the gas-oil or gas-conden-

sate rat io; the sn~all erhe ratio, the higher is the ra te

of flow necessa ry to ins ure stabilized flow. Th e im-

portant point is that there is a certain minimum rate

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of flow below which a gas-condensate well will not

stabilize. I n most wells with 2t-in. tubing th is minimum

ra te of flow is a t least 3,000,000 cu f t per day. The

following formula is convenient for determining linear

velocities in connection with these rule-of-thumb criteria

for stabillzed flow:

Linear velocity (fe et per second) = o QTZ (2)

Pd'

i n

which the symbols have the same meaning and units

a s used later in the paper.

Wells with tubing set high above the producing for-

mation are prone to stabilize slowly, and some require

severa l days' flow before they stabilize. In genera l,

there a re several factors which may be-use d to note.

the presence o r absence of stabilization. The ra te of

flow and well-head pressures should be recorded every

15 min. I t would be desirnble to have the gas-oil ra tio

every 1 5 min also, but

lt

is not practical to measure-

the small amount of condensate produced into a lease

tank in that short a time.

A

small calibrated tank is

very he lpfu l in t h ~ sonnection. If th e separator is the

type that dumps the same volume every time, the rate

of condensate production may be obtained by tilnlng the

dump intervals. If t he dump intervals remain constant

over a period of time, a s well a s the r at e of g as flow

as indicated by th e orifice meter, then it follows th at th e

gas-oil ratio is remain ing constant-which is a require-

ment of stabilized flow. The dunlps of the se par ato r

show up on the orifice-meter chart by a small decrease

in the differential, so that a convenient record is auto-

matical ly available. Observ ations of th e liquid level

in the separa tor gag e glass also can be used

i n

a similar

manner. A fluid meter on the outlet of the separator to

measure the condensate would be a better alternative

to obtain the gas-oil ratio in small intervals, but such

an installation is not common.

If the gas-oil ratio, r at e of g as flow, and well-head

pressures become and remain constant, stabilized flow

exlsts . The difficulty comes in knowing when the y ar e

constant, and the only reliable way is to determine

them often and thus follow the behavior until no

changes ar e noticed. Observations a t longer intervals

can be misleading, and do not give enough background

to judge if stabilization ex~s ts .

down the tubi ng; but, in co m~ ng p, the wire line will

only pull fr om a fi:ed position, which in man y cases

will not fix the bomb a t the best angle t o get through.

A

second disadvantag e, in t he c ase -of flowing bottom-

hole-pressure tests, is the hazard due to the possibility

of the bomb being shot up the tub ing a t the high rat es

of flow w h ~ c h re required f or stabillzed flow. The de-

gree to which this possibility is a disadvantage and

hazard depends upon the experience of the operator.

A

third disadvantage is that a liquid level usually

will exist in a closed-in gas-condensate well which

makes the determination of ,reservoir pressure, P f un-

reliable unless the pressure gradient of the liquid and

its height can be determined. In a good many cases the

tubing is more than 100 f t above the producing sand,

and th e liquid is not detected. The height of condensate

which one

might expect in the hole is shown by the

following formula:

.~c~lzeve

he symbols have the following meaning and

value for a typical example:

Example

H

=

h e ~ g h t f condensate in tubing (feet).

145

L = length of tubi ng or depth of reservo ir

feet) 10,000

P = average tubing pressure (psi).

4,000

T

= average tubing temperature (deg Ran-

ine) 610

Z = average compressibility factor.

0.9

=

gas-condensate ratio in tubing (stand-

ar d cubic feet per ba rr el ). 100,000

On th e basis of a liquid gra die nt of 0.4 psi pe r foot

and a g as grad ien t of 0.1 psi per foot, the foregoing

example of 145 f t of liquid would cause an er ro r of

43.5 psi. Of course, when th e well is shut In and t he

bottom-hole ,pr ess ure becomes reservoir pressu re, t he

Ilqu~d and g as lnlght be expected to r etu rn to t he

equilibrium single-phase, except a s disturbed by t he

gravitational effect and temperature gradient in the

tubing; but a long tlme probably is required, before

equili brium is reached. However, when bottom-hole-

pressure ~neasurementsdetect a liquid level and allow

th e determination of all its gra die nt and height, back-

.

Determination of Sand-Face Pressure

pressure tests based on such nleasurements are the

most reliable and most accurate.

Dlrect determination of sand-face pressure with a

bottom-hole pressure bomb avolds calculations employ-

ing well-head pressure, gravlty, conlpressibility, tem-

perature, rate of flow, and size and length of tubing-

which elimination is very desirable. However, the re ar e

certai n disadvantages also. In many gas-condensate

wells a packer

IS

set between the tubing an d the casing;

and, in order to malntain the seal, a considerable por-

tion of th e weight of t he tubing re sts upon the packer.

This weight also causes the tubing to bend or cork-

screw a t sufficiently sh arp angles a t places to make

ru nn in g a bomb exceedingly difficult or impossible. The

bomb usually will go down withou t trouble, as i t will

natura lly assume the best position under grav ity to ge t

I n those cases where bottom-hole pressu re bombs can-

not be used satisfactorily for back-pressure tests, cal-

culatlon of sand-face pressures from well-head pres-

sures, a s herein described, have been f ound satisfactory.

The calculation of sand-face pressures from well-

head pressures involves the consideration of the

weight of the gas-condensate column and t he pres sure

drop due to flow. The weight of th e col un~n s calcu-

lated by means of the theorem of reduced states,

based upon the pseudocritical temperatures and pres-

sures and compressibility factors of Standing and

Ka tz 5 fo r hydrocarbon gases containing more th an

8

per cent of combined methane an d heptanes plus (sum

of mol per cent of methane, heptanes, and heavier

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fractions ). Although ther e is a certai n aniount of con-

dens at~o n n the tubing, densities arrived a t by this

method have not deviated appreciably from measure-

ments obtained by pressure-depth measurements in the

tubing. Moreover, the calculated sand-face pressures

ar e only subject to about one-fourth th e err or in the

decsi ty . P~~essurerop due to flow is calculated ac-

cording to Miller?

M o n o g r u : p l ~

7

proceeds to calculate the sand-face

pressure from the surface pressure by first obtaining

P,, which is a fictitious pressure that would be the

sand-face pressure according to Weyniouth formula if

the gas column weighed nothing. I t then arrives a t the

'actual sand-face pressure by considering

PI

the sur-

face pressure and adding the weight of the column of

gas, using a correction facto r F to account for t he pres-

sure drop 111 the tubing due to flow (PI Pla). Rigor-

ously, such a procedure is not correct, but In many cases

Subs t~ tu t lngor

d R 2 )

:

In thk same differential length of pipe dL he pres-

sure dr op due to the weight of t he column of g as

clPtut.

is given by:

520 P

w h e r e p = density of

(ideal gas) air = 0.07633

4.7 T

lb per cu ft.

Substituting for 7 :

I

0.018751 PG dL.

dPWt. =

TZ

In the differential length of plpe dL the total pres-

sure drop is equal to the pressure drop due to flow

plus the weight of t he column of g as or :

the err or so incurred is small. Wha t is more important,

this method leads to cumbersonle and lengthy calcula-

tions.

Hereinafter is derived an analysis in which the pres-

sure drop due to flow and the weight of the column of

gas are calculated simultaneously for each increment

of length' of the pipe, and the sand-face pressure then

arrived at by

integration

over the total length of the

pipe. This derivation could sta rt fronl the fundamental

differential equation of fluid flow, but the following

approach will he more familiar.

Starting with the Weyinouth fonnula:

(PI2--PM2) h5Z

. . . . . . . . . .

= 1.090 M

.\i LTG

,. (4-a)

Q = rate of flow, million cubic feet of gas per day

a t 60 deg F, 10 oz above 14.4 psi, absolute.

PI = inlet pressure, psi, absolute.

P, =

discharge pressure, psi, absolute.

d internal diameter of pipe, inches.

G

=

specific grav ity of ga s condensate (ai r ):

L = length of pipe, feet.

T = flowlng temperature, d e g Rankine (deg F

,460 deg).

Z = compressib~lity f gas condensate.

M correction factor according to Miller?

Equation (4a) can be written,

PI =

V P w Z +R ,where

R =

1.090dsM

which may be expanded by th e binomial theorem into

the infinite series:

I n a differentla1 length of pipe dL the pressure drop

due to flow dP is given by:

In equation '(6) let

Then

which is a non-linear differential equation reducible to

linear form.

Integrating

w h e r e : a and

b

contain T and 2 hich ar e functions of

L.

Although approsinlate linear functions of

L

may be

used for P and

2

the final solution of the differential

equation

1s

of a form not practical f or convenient calcu-

lation.

T

and

2,

therefore, are assumed constant;

and av erage values a r e used in the final equation.

Equation (7) t,hen becomes:

a

when

L

= 0 = P J r ; and, therefore, c = PI2 g

Therefore

:

p =

p w ? e 2 b L &(c21,~.-1),

b

which may be written in the form:

In equation (8-a) just derived, which is the one used

to calculate sand-face pressures, a factor III is in-

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cluded to correct the Weymouth formula according to

Miller. Miller s correction ha s been calculated for sev-

era l sizes of pipe, and is shown in Fig.

1

where the

Q

correction factor M

=

-is plotted as the ordinate and

Q

the actua l ra te of flow, Q a s the abscissa.

Substitution of PW, Z, T, L,

M

and in the de-

rived equation allows the calculation of

Psa.

I t will be

noted t ha t no differences of squ ares are involved in t he

calculation, which simplifies it considerably.

Determination of ' ~ r a v i t ~nd Compressibility

G

The ratio which is the ratio of gravity to

z

compressibility of the gas-condensate mixture a t a

given tempera ture and pressure, is the rat io of th e

weight of 1 cu f t of t he gas-condensate mixture a t

that temperature and pressure to the weight of

1

cu f t

of ai r a t the same temperature and pressure, a ir being

considered a perfect gas.

G

is not the gravity of the ga s from the separator,

nor is the compressibility of the separa tor gas be-

cause some condensate has already dropped out in the

separa tor. However, an approximate value of G may

be obtained by adding the weight of the condehsate to

the gas and estimating the increase in volume as shown

hereinafter. The formula for

G

[equation (9 )] i s ar-

rived a t by taking 1 cu f t of separator gas of g ravity

Go and adding to i t the condensate produced with it.

This causes both an increase in weight and volume.

The second term of the numerator represents the in-

creased weight, and the second term of the denomi-

nator represents the equivalent increased volume.

.6146

Where

G

=

separator gas gravity (air

=

1) .

G

=

specific gravity of condensate (water

=

1).

R

=

gas-oil ratio, cubic feet per barrel.

62.42 = weight of

1

cu f t of wate r, pounds.

Correction Factor for Weymouth Formula for 2-In. and 2 -111. Tubing and 6-In. Casing

(After Miller

).

FIG

1

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0.07633 weight of

1

cu f t of a ir a t 760 mm and 60

deg F, pounds.

5.6146 cubic fee t in 1 bbl (42 U.S. gallons).

200 approximate cubic feet of gas equivalent to

1 cu f t of condensate.

Fig. 2 shows the correlation of Stan ding and Ka tz '

between gravities of gases containing more tha n 83 per

cent of combined methane and heptanes plus, and

pseudo-critical p ressures and tempera tures. Almost all

gas-condensate systems fall in this class, and the use

of Fig. 2 is much simpler th an th e computation of

pseudo-values from reservoir or composite flow analyses,

which are not always available. With th e pseudo-

critical values obtained from Fig. 2, reduced pseudo-

pressures and -temperatures may be calculated which

are used in Fig. 3 to obtain the compressibility factor

Z. Fig. 3 is the correlation of Stan ding and Katz;

based on actua l density measurements of gases a t the

higher pressures and temperatures, and is a revision of

the older compressibility chart s based on the ext ra-

Pseudo-critical Temperatures and Pressures of Hy-

drocarbon Gases Containing More Than 83 Per Cent

Combined Methane and Heptanes Plus (After Stand-

ing and Katz

).

FIG. 2

polation of low-pressure determinations using methane

a s a guide.

In the derivation of equation (8-a) it was pointed

out that Z and

T

were assumed constant, and average

values would be used in applying it. I t appears tha t an

arithmetic av erage between the compressibility a t th e

well-head pressure and temperature, ZW,and the com-

pressibility a t the sand-face pressure and temperature,

Zs, gives a sufficiently accurate average. However, in

order to determine Zn, it is necessary to know the

sand-face pressure. Thus, a trial-and-error method must

be resorted to. A graphica l solution by the use of

Fig. 4, as shown in th e calculations in Table 1, simpli-

fies the trial-and-error method considerably. The value

L

of f o r he well under test is located as the abscissa

T

P

of Fig . 4, and th e various values of

for different

Pw

values of the parameter Z read as the-ordinate . T is

the arithmetic average of the reservoir and well-head

temperatures, and Z is the arithmetic average com-

pressibility used in equation (8-a ). ZB changes very

slowly as the assumed Z changes, so that only two or

three trials a re necessary to arr ive a t the proper Z

to give the arithmetic average of Zn and ZW.

Example Back-Pressure Tests Using Proposed

Method

Table

1

shows the back-pressure test data on a gas-

condensate well and calculations by the proposed method.

Compressibility Factor as a Function of Pseudo-re-

duced Pressures and Temperatures (After Standing and

Katz 9).

FIG. 3

Chart for Determining Average Compressibility Factor.

FIG. 4

Fig. 6 shows the plot of these calculated data. Fig. 5

gives the results of pressure-depth surveys made in

wells A and B with a bottom-hole pressure bomb

while the wells were shut in. I t will be noted th at th e

last point of well B indicates a n encounter of liquid,

which point has been connected with the reservoir

pressure calculated in Table 1 Well A had been

blown before the bomb was run in, and shows a very

small difference in Fig.

5

between the reservoir pres-

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TABLE

1

Back-Pressure Test o a Gas-Condensate Well: Well B

G, =

0.610

(a ir =

1 ) .

G = 0.756 g per in].

Elapsed Time

Q

between Flows (MMCF

(Hours) Per Day)

4 after shut-in.. 0

. . . . . . . .2

after opening..

3.907

. . . . . . . ..1

afte r shut-in.

0

. . . . . . .

.4

after opening.

4.860

1.6 . . . . . . . . . . . . . . . . . . . . . 6.055

2.3 . . . . . . . . . . . . . . . . . . . . . . 5.297

.2

after shut-in..

0

Tubing Pres-

sure

-(PSI,

Absolute)

L

= 9,946 f t o f 21 in. tubing.

Reservoir temperature =

206

deg

F.

Well-Head

Temperature

(Deg F)

R,,,,,,,,, = 27,487 cu f t per bbl.

Pseudo-critical temperature, T,,

= 387

deg Rankine.

Gas-Oil Ratio

(Cu Ft Per

Bbl)

Remarks

Not stabillzed

Changing choke

Stabilized

Stabilized

Stabilized

Pseudo-crltical pressure,

PI,, 662

psi, absolute.

29 444

B

[equations

(8-a

and 8-c)

]

=

0.1923.

2.441 3.

Xllllio~lcr~h ic eet

DETERMINATION OF Z FOR

m

= 3,622 AND Tlu = 98+460

=

558 DEG RANKINE

Assumed Average Z . .

. . . . . . . . . . . . . . . . . . . 0.800 0.900 0.890

(P, P

r

2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.3094 1.2710 1.2741

P, P,

P,,'

=

5.471

P,' . . . . . . . . . . . . . . . . . . . . . . .

.164 6.953 6.971

T,' = 1.442 T.' . . . . . . . . . . . . . . . . . . . . . . 1.721 1.721 1.721

. . . . . . . . . . . . . . . . . . . . . . .

,= 0 . 810 Z 0.978 0.968 0.970

Average of

Z O

and

Zs . . . . . . . . . . . . . . . . . 0.894 0.889 0.890

l rillletl pressure?;

sli

t eu lp e ra tr~ res a r e I IS ~ U ~ O-r a1 u t . s

DETERMINATION OF.SAND-FACE PRESSURES

P. (10 ) . . . . . . . . . . . . . . . . . . .

. . . . . .

21.0737

20,7598 20.7344 20.4935

\

PI (10')

. . . . . . . . . . . . .

21.2918 21.2946 21.2946 21.2946 21.2946 21.2946

Pf3

-

P, ( l o u ) . . . . . . . 0.2209 0.5348 0.5602 0.8011

P. . . . . . . . . . . . . . . . . . . .

4,614.2 4,614.7 4,590.6 4,556.3 4,553.0 4,475.2

P I - P a . . . . . . . . . . . . . . . . . . . . . 0 24.1 58.4 61.7

139.5

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sure calculated and that obtained by extrapolating

the pressure-depth curve on the assumption of no liquid

level. It should be pointed out that shut-in well-head

pressures should only be ta ken a ft er t he well is flowed

a t a stabilized rate . The well-head pressure should then

be observed until it reaches a maximum, which it

usually will do in a few minutes. The tes t da ta of

well "B" in Table 1 show three closed-in pressures.

The last two are valid, and the reservoir pressures

calculated therefrom compare satisfactor ily. The firs t

shut-in pressure is low because of the liquid level shown

in Fig.

5.

CONCLUSIONS

A proposed method is outlined for the determination

of sand-face pressures f rom well-head measurements,

using published data on densities of gases and pres-

su re drop due to flow. A sufficient varie ty of gas-

condensate wells ha s not yet been tested by thi s method

to w arr ant any general conclusions as to its ap-

plicability, but it i s hoped t ha t thi s paper will stimu-

late further investigation and consideration of this

method.

ACKNOWLEDGMENT

The author wishes to express his gratitude to the

Division of Minerals, De par tme nt of Conservation, St at e

of Louisiana, for permission to publish this paper.

REFERENCES

R

T Hnwlin

rind 51 A Schellhard t . "Baek-Pr~8~ 11re ata

give souiies of other permeabili

J. M.

Plaitz and 4 . S. Parks, "Sarn~111

Wells. Petroleum Tect~nol ogy (T. P 1 37

B~n inr ni n Miller. "Deterrnin

ng Gas-Condensate

' h i 4

[ 5 ]

(1941).

inc Gas-Transmission-Line Ca-

pacity in8 13 [ll] 22 (l J37).

1 . ' ~ . Stan ding an d D. I.. Tiatr. "Density of Na tur al Gases,"

Petrolrum Technologl/ (T. P IYZ3 4 [4] (1941).

DISCUSSION

J. M. Fla itz (Hudson Engineering Corporation, Hous-

ton, Texas) (wri tten )

*

The methods presented in

u r e a u of M i n e s M o n o g r a p h

7 have become a standard

for the petroleum industry, and are accurate for dry

nat ura l-g as wells. However, M o n o g ~ a p h methods are

applicable to gas-condensate wells only, with modifica-

tions which consider the fact that two phases exist

after the fluid leaves the producing formation.

Th e existence of two phases necessitate s revised

methods of calculat ing the weight of t he fluid column.

It

is probably not practical to standardize on a method

of calculating this factor, a s it ca n be done in several

different ways depending upon the available data and

the convenience of obtaining dat a in an y part icul ar case.

The impor tant point i s to consider th e two phases.

The value of M a s shown in Fig. 1 of the paper (or

Presented by S.

It

Buckles, 1Iumble Oil and Hefining Co.,

Ilouston, Texas.

some equivalent) is an import ant consideration. Actual

data on friction drop through tubing in gas-condensate

wells was reported by R. J Sullivan of the Humble

Oil and' Refining Company a t t he 1941 gas-measure-

ment sho rt course of the Univers ity of Oklahoma. Mr.

Sullivan found tha t t he actual friction drop is between

calculated values using W e ~ o u t h ' s nd Nikuradse's

formulas, and his da ta ar e probably t he best available

if specific da ta on a well ar e lacking.

The paper i s valuable in th at it points out the many

factors that must be given consideration when con-

ducting back-pressure tests and using back-pressure

data on natural-gas wells producing condensate, and

the paper is timely because inaccurate and misleading

back-prcssure data on gas-condensate wells are now

prevalent in the industry.

M. A. Schellhardt (Bu rea u of Mines, Bartlesville,

Okla.) (written) :- Mr. Vitter's repor t points out sev-

eral of the factors that distinguish the application of

the back-pressure method for studyi ng the producing

characteri stics of relatively low-pressure dry ga s wells

from i ts application to t he st udy of those of gas-con-

densate wells. However, the high pressure and l arge

fluid-delivery capacity that characterize many gas-

condensate wells make it all the more desirable that

capacity be determined under conditions that do not

exceed the capacity of normal operating equipment and

do not prove hazardous to the well.

Although the gaging of subsurface pressures in oil

and gas wells has become common practice during the

interval since the study reported in u r e a u of M i n e s

M o n o g r a p h 7, the use of subsurface gages in many

gas-condensate wells is limited.

Equipment in many gas-condensate wells provides f or

th e production of fluid deliveries either f rom th e tubing

or from th e annu lar space. However, few wells ar e

equipped with the heaters or high-pressure separators

usually required to obtain satis fact ory flow test s if the

fluid is produced from t he ann ula r space, and flow te sts

usually are restricted to deliveries from the tubing.

Pres sures can be gaged a t the productive zones in many

wells only if th e wells ar e closed in or operated a t

rates of fluid delivery that will not affect the normal

position of the subsurface gage.

Hence, if the delivery

capacity of gas-condensate wells is to be gaged by the

back-pressure method, often it is desirable to compute

pressures a t the productive zone corresponding to the

various operating conditions imposed on the well.

Dat a obtained during the course of the s tudy re-

ported in M o n o g r a p h

7

indicated that, if velocity in the

flow string was materially higher than the normal

velocity of the flow of gas through pipe lines, values

of the pressure drop due to friction calculated by

Weymouth's formula were higher than the values of

the actual pres sure drop. The discrepancy was dis-

cussed on p. 163 and 164 of th e repor t.

l'resented bv Charles

B.

Carne ntrr . Bureau of hlines. Dallas.

Texas.

t Published by permission

of

the director, Bureau of Mines.

I)el>artment of the Int erio r.

b7igures rrfer to REFEREPI'CES on p. 87.

7/21/2019 API-42-079

9/9

J William Ferguson? of the Canadian River Gas

Company, developed a method for computing, simul-

taneously, th e effect of the weight of the g as column

and the friction of the flowing gas in the flow string,

which facil itated the computation of subsurface pres-

sur es in relatively d ry natu ral-gas wells. The method

proposed by Vitter for calculating subsurface pres-

sur es in gas-condensate wells is of part icular interest,

however, because i t not only includes the effect of well

temperature and deviation of the compressibility from

the law for ideal gas, but also includes a correction

developed by Mill ers which reduces th e discrepancy

induced by applying Weymouth's formula for caleu-

lating pressure-drop values under the conditions that

prevail during many flow tests on gas wells.

Fortunately, tubing packers are not installed in

many wells, and operating pressures at the productive

zone can be calculated from well-head pressu res gaged

on the closed-in string, thus eliminating the necessity

for considering the pressure drop caused by the flowing

medium.

Considerable progress has been made by some opera-

tors on the development of gas-condensate well-testing

technique, and under favorable conditions the results

obtained by the application of the back-pressure method

fo r gaging wells of this type have been satisfactory

fo r the purpose f or which they were desired.

Vit ter pointed out that columns of liquid often were

present in closed-in wells.

Information that has been obtained by subsurface

pressures and fluid samples during the progress of a

study of the problem of gaging the delivery capacity

of gas-condensate wells, now being conducted by the

Bureau of Mines in cooperation with the natura l-gas

section of the American Gas Association, shows that

condensed water also is present in many wells. Tests

on some wells have indicated that a condition of

equilibrium may prevail for 24 hours or more, under

which well-head pressures and fluid deliveries are rela-

tively constant, although an accumulation of hydro-

carbon liquid and water sufficient to form a column in

the tubing two or three hundred feet above the pro-

ductive zone was present in the well.

The relationships of the pressure-fluid delivery data

that were presented by Vitter are similar to those

obtained by tests on some wells under relatively stabi-

lized pressure-flow conditions, but before they were

subjected to high ra tes of fluid withdrawals f or pro-

longed periods to insure the removal of accumulated

water before subsequent flow tests were conducted.

The delivery capaci ty of many wells is lar ge com-

pared t o the capacity of the equipment installed to

facilitate normal operations, and often it is feasible to

obtain pressure-flow data over only a very limited

proportion of the potential operating range of the

wells. Hence, the presence of small quan tit ies of un-

accounted-for liquid may change the results of back-

pressure test s materially, and the importance of re-

moving all accumulated liquids from wells to be tested

cannot be overemphasized.

REFEREN ES

1

E.

L. Rawlins and

M.

A Schellhardt Back-Pressure Data

on NfFural-Gas Wells and their ~p pl ic nt i6 n o Productlon Prac-

tices

Bur . Mines Yonograph

7 reprinted (1939).

j

W.

Ferguson, Calculations

o f

Back-Pressure Tests on

Natural-Gas Wellm. O i l

Ga8

J . 7 36 47 (1939).

Benjamin hIiller. Determinin Gas-Transmis sion-Line Ca-

pacity, Ga s

22-0

8-9, Nov. (1987).