FEATURE ARTICLE

A REVIEW of DRILL-STEM TESTING TECHNIQUES

and ANALYSIS

W. MARSHALL BLACK HUMBLE OIL & REFINING CO.

JUNIOR MEMBER AIME HOUSTON, TEX.

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Abstract ether-cuts may be used to detect hy- tion evaluation. Presently, tests in-
drocarbon shows. side casing are about 91 per cent
The present techniques of using mechanically successful as compared
the drill-stem test as a formation 2. Test possibly productive inter-
vals in open hole after drilling deep- with 81 per cent 10 years ago, and
evaluation tool are discussed. The conventional open-hole, wall packer
basic drill-stem test operation is di- er or reaching total depth; normally,
this method requires that a cement testing is mechanically successful
vided for discussion into three phases:
plug be set for each test, unless strad- about 87 per cent of the time as
planning the test, performing the test, compared with 72 per cent 10 years
and interpretation, both qualitative dle packer testing is employed. Side-
wall cores and logs are commonly ago.
and quantitative. The use of small
bottom chokes and large top chokes used to detect the shows. The Drill-Stem Testing Tool
is suggested in order to permit quan- 3. Test possibly productive inter- Modern drill-stem testing tools are
titative interpretation for gas-oil ratio, vals through perforations after casing highly versatile and consequently are
productivity, and permeability. The has been set; log and core data may complex. The various components
importance of measuring chloride be used in selecting the intervals. may be assembled in innumerable
content on a suite of samples taken Drill-stem testing is widely used to combinations, either to provide spe-
from a recovered column of salt wa- confirm or prove the presence and! or cial information or to provide for
ter is illustrated. the producibility of oil and gas that emergencies that may develop. The
is detected by the other services. The following paragraphs briefly outline
Introduction testing program in a well can follow the functions of the more common
anyone of the methods of drill-stem tool components.
A drill-stem test is a temporary testing outlined in the preceding sec- The three basic mechanisms or
completion of the well. Drill-stem tion; however, the method of testing components of a drill-stem test tool
tests are usually made for one or cored shows as the prospective pays are as follows: (1) the tester valve,
both of the following reasons: ( 1) are penetrated is probably most wide- (2) the by-pass valve, and (3) the
to determine the producible fluid ly used at present. Under this meth- packer. These three component
content of a formation, and (2) to od, a test will usually be made after mechanisms will be found in some
determine the ability of a formation penetrating a few feet into the pros- form in any good drill-stem test tool.
to produce. pective zone, and if the results are The functions of each of the basic
Drill-Stem Testing Methods
favorable, subsequent tests may be components in the assembly are as
made in search for fluid contacts. shown below.
The drill-stem test, or temporary
completion, . can be made either in Testing programs during the early FUNCTIONS OF BASIC COMPONENTS OF TOOL
open hole or inside casing through phases of field development are as 1. The Tester or Retaining Valve
o. To prevent drilling mud from entering empty
perforations. A drill-stem testing pro- important as the coring and logging drill pipe while funning in.
gram can be planned for a well so programs for delineation of the res- b. To aid in preventing drilling mud from enter-
ing drill pipe while pulling out and, conversely,
that the tests will be made in accord- ervoirs and for establishing or con- to aid in retaining formation liquid recovery with~
firming the gas-oil and oil-water con- in the drill pipe.
ance with one of three general meth- c. To open the tool, permitting passage of forma·
ods: tacts. tion fluids into the empty drill pipe after the
packer is set.
1. Test possibly productive inter- Trends in Drill-Stem Testing 2. The By·Pass or Equalizing Valve
o. To permit mud under hydrostatic pressure to
vals in open hole as the zones are Since the early days about three- flow downward throug h the packer mandrel at the
conclusion of the test into the hole below the
penetrated; normally, this method is fourths of all drill-stem tests have packer. This action equalizes the pressure above
used in conjunction with coring and been performed in open hole prior and below the packer, making it easier to pull
loose.
to setting oil string casing. This pre- b. To provide additional area through which the
Original manuscript received in Petroleum drilling mud can pass around the packer while
Branch office on Sept. 15. 1955. Revised man- dominance of open-hole testing defi- running in and pulling out of the hole.
uscript received May 1'6. 1956. Paper pre- nitely places drill-stem testing in Note: The new "hydraulic testers" ore unitized
sented at Formation Evaluation Symposium. teater valves and by·pass valves; the respective
Oct. 27-28. 1955. Houston. Teo<. the category of exploratory forma- functions of these are unchanged.

JUNE,1956
SPE 589-G 21
 3. The Packer amount of hole to test; (3) packer a core hole, or hole of reduced diam-
o. To bridge the hole at Q point immediately above
(and also below on straddle tests) the zon,e to size or sizes; (4) location of packer eter, is drilled ahead for exploratory
be tested, thus permitting this zone to be relleve~ purposes. Successful use of conven-
of hydrostatic mud pressure when the tool IS
seat; (5) top and bottom choke
opened and isolating the zone from other forma- sizes; (6) probable length of flowing tional double-end wall packers re-
tions.
Important auxiliary components of and shut-in period and use of dual quires a very close fit to the hole
the drill-stem test tool are as follows: shut-in periods; (7) type of pressure size. Because· of this, a reduction in
the disk valve, the shut-in pressure gauges, manner of placement in the hole size or rathole for the last 300
valve or tool, the formation or bot- tool, and optimum pressure capacity to 500 ft of hole, including the test
tom choke, the anchor pipe, and the and clock speed; (8) use of, type, zone, permits greater packer clear-
pressure recorders. In addition to and location of circulating sub, safety ance while running in and out in
these, a circulating valve, a safety joint, and jar; (9) use of water cush- the full hole. Ratholing is largely
joint, and sometimes a set of jars ion and amount; (10) method of confined to soft formation areas.
may be included in the test tool or handling test production at the sur- It has been found that the ratio
in the drill pipe or tubing string. face; and (11) special packer ar- of hole size to packer size largely
rangements. governs the amount of packer com-
FUNCTIONS OF AUXILIARY COMPONENTS IN pression that will occur at pressure
TYPICAL TEST TOOL STRING
Amount of Hole to Test differentials up to 5,000 psi and that
1. The Disk Valve
o. To aid in preventing drilling mud from enter- In most instances, a more conclu- leakage or rupture of the rubber
ing the drill pipe while running in.
b. To permit the packer to be set firmly and tester sive test can be obtained by testing element will occur if the ratio of
valve opened before the tool is finally opened by
dropping a go-devil to rupture the disk valve (as
the shortest section practical. In thin hole size to packer size is such that
used with certain tool assemblies). sands, where it is desired to locate complete mandrel travel is attained.
2. The Shut-In Pressure Valve or Tool

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o. To permit the test tool to be closed at the con- the gas-oil and oil-water contacts, a A differential pressure of 5,000 psi
clusion of the flow period with reduced likelihood
of unseating the packer or letting pressure equal-
test zone of 2 to 5 or 10 ft is often will produce complete compression
ize around the packer through the by-pass. used in open hole. Where producing when ratio of hole size to packer
b. To aid in preventing drilling mud from enter-
ing the drill pipe while pulling out and, converse- zones of greater thickness are en- size approaches 1.25; 5,000 psi dif-
ly, to aid in retaining the formation liquids recov· countered, it may then be feasible to ferential pressure will cause about
ered within the pipe.
3. The Formaton or Bottom Choke test more hole per test. This is par- 50 per cent compression when ratio
a. To restrict the volume of formation fluids that
flow through the drill pipe to the surface.
ticularly true in long limestone sec- of hole size to packer size is about
b. To hold some backpressure under the packer, tions where the location of the porous 1.08 or 1.10. In the commonly
which reduces the hydrostatic load on the packer,
and to reduce the amount of pressure drawdown in zones may not be known, and it is drilled hole sizes, the 1.08 ratio pro-
the formation. usually desired to determine the over-
c. To allow quantitative drill-stem test interpreta- vides a reasonable balance between
tion. all fluid content and productivity of clearance in true-to-gauge sections
4. The Anchor Pipe
a. To support the open-hole wall packer at the a certain interval. If the volume of of hole and the excess expansion
desired place in the bore hole. the hole below the packer is too
b. To aid in screening out cuttings or junk that available should the packer seat yield
might plug the choke or foul other tool com- great, the drilling fluid may fill the or be washed out.
ponents.
5. The Pressure Recorders pipe to such an extent that a low Somewhat larger clearances can be
a. To provide measurements of hydrostatic mud
pressure, formation flowing pressures upstrea!,"
formation pressure will be insuffi- used with the new "expanding shoe"
from the formation choke, and formation shut-In cient to cause entry of any appre- packers, and in areas where a re-
or bottom-hole pressure. These pressure measure-
ments are necessary for complete test interpreta- ciable quantity of formation fluids duced size hole or rathole need not
tion and formation evaluation; therefore, the pres-
sure recorders are, in a sense, among the most
against the backpressure. Also, the be used, this type of wall packer has
important components of the tool. source of water produced from a excellent application. These packers
b. To provide a graphic record of the proper or
improper functioning of the test tool. long interval is indefinite. were developed in part to facilitate
6. The Circulating Valve
a. To permit test recoveries to be pumped out of Selection of Packer Size
full hole testing by permitting a
the drill pipe by reverse circulation into a pit or
tank.
smaller packer diameter to be used
b. To provide a means of conditioning the mud W'all Packers than is feasible with conventional
in the annul us and thus make testing a safer op-
eration. The open-hole wall packer does packers.
7. The Safety Joint
a. To provide a means of releasing the drill pipe not enjoy the controlled conditions Selection of Wall Packer Seats
and tool from a stuck packer or anchor. of usage of the hookwall packer; it
8. The Jar Open-hole packer seats should be
a. To increase the possibil ity of freeing (] stuck is frequently required to seal off in chosen in true-gauged sections of
tool. (The jar used for this purpose is usually a
special hydraulic tool designed to deliver impact plastic formations and in a hole hard nonplastic formations. Exami-
blows.) whose diameter is known only ap-
b. To facilitate setting the tool for measuring for. nation of cores will provide the best
motion shut-in pressure when a rotating shut-in proximately. Successful use of rub- basis for selection of packer seats;
pressure valve is not used. (The jar used for this
purpose is a simple telescoping slip joint arrange- ber in wall packers requires that the in the absence of visual core exam-
ment.)
9. The Surface Control Head
stresses be kept low enough that the ination, a caliper log will be helpful.
a. To permit control of fluid flow from the drill rubber will act entirely in the elastic Electric logs and sidewall cores may
pipe at the surface through means of valves and
chokes. or solid phase; that is, it must return also be of use. When setting packers
to its original shape when the load is in the top of sand bodies overlain
Planning the Test taken off. This must be done by by soft shale, at least 2 ft of sand
keeping the clearance between the should be allowed for the packer
The Basic Decisions packer and the wall of the hole as seat. If possible, wall packers should
Detailed consideration must be small as practical, by keeping the not be reset in the same seat on suc-
given to a number of factors in plan- axis of the packer parallel to and ceeding tests. In fractured forma-
ning a drill-stem test in order to in- coincident with the axis of the hole, tions, use of dual packers (two wall
sure that the desired information will and by choosing the packer seat in packers run next to each other) is
be obtained and to increase the prob- the least plastic formation possible. often advisable.
ability of a mechanically successful It is important to have a straight
test. Decisions must be made before- true-to-gauge hole and a sufficiently Selection of Choke Size
hand on the following: ( 1) service heavy, rigid anchor pipe. The choice of the bore diameter
company to be employed; (2) Rathole testing is employed wh.::re of the bottom choke depends upon a

22 JOURNAL OF PETROLEUM TECHNOLO(;Y

number of variables, the primary able choke is not available, is to 30 minutes to one hour, has small
considerations being safety, test in- place the position choke up in the effect on the amount of pressure
terpretation, and the possibility of drill pipe string above a suitable drawdown in the sand around the
the choke becoming plugged. Gen- amount of water cushion. This slight- well; and it is truly important only
erally, the size of the bottom choke ly reduces the pressure differential in controlling the amount of recov-
should govern the size of the choke across the face of the well bore when ery at the particular flow rate. The
used in the control head at the sur- the tool is opened and assures that rate of production, as governed by
face; the bottom choke should con- a volume of formation fluid at least the choice of choke size, has a large
trol the amount of flow and should equal to the volume of the water effect on the amount of drawdown.
be small enough in relation to the cushion will be recovered before the Pressure drawdown should be kept
top choke size that, barring difficul- choke plugs. moderate in order to reduce the
ties, excessive pressures will not de- packer load, permit pressure buildup
velop in the drill pipe or tubing at Length of Test in shorter shut-in periods, and re-
the surface. duce coning and fingering of gas or
If the bottom choke is to be used Flow Period water.
as a meter in interpreting for gas-oil Generally, it is better practice to
ratio and productivity, the top choke test moderately to highly productive Shut-In Period
should not restrict the flow to the zones for a long period with a small
extent that the backpressure plus the At the conclusion of the flowing
bottom choke (3/16 to % in.) and period, it is customary to close the
head due to the recovered liquid on relatively small pressure drawdown
the bottom choke is greater than test tool on bottom using a rotating
than to test for a short period with

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about 40 to 50 per cent of the up- shut-in tool. It is highly desirable to
a large choke (¥s to 1/2 in) and obtain a complete buildup of pres-
stream pressure on the bottom choke. more severe drawdown.
Under these conditions, the flow is sure in the test zone to the native
Two factors are of significance in formation pressure for the following
said to be "critical" and is independ-
deciding the duration of the flow pe- reasons:
ent of the downstream pressure.
riod: ( 1 ) the length of time for 1. The shape of the pressure build-
When pressure downstream of the
which it is safe to leave the drill up curve reveals information regard-
bottom choke exceeds about 50 per
pipe undisturbed without danger of ing formation permeability.
cent of the upstream pressure, the
sticking, and (2) whether the bottom 2. The formation pressure is re-
flow rate will progressively diminish
choke is to be used as a meter in quired for estimates of productivity
as the drill pipe fills. Under these
interpreting GOR and productivity, and to ascertain whether an adequate
conditions, the flow is termed "non-
or whether the test is to be flowed (or perhaps excessive) mud weight
critical," and an accurate average
to surface tankage and interpreta- is being maintained.
rate cannot be determined.
tions made by means of surface The length of the shut-in period
Bottom choke bores ranging from
metering equipment. required to obtain a complete build-
3/16 to % in. used with top chokes
ranging from SIs to I in. are satisfac- The common use in many areas up is primarily dependent upon the
tory for the nonflowing type of test of 20Vz - or 25Vz -minute flow periods formation permeability and second-
in moderately to highly productive for 41h - and 5-in. drill pipe, respec- arily upon the degree of drawdown
zones and where the top choke ex- tively, is purely an aid toward sim- caused by the flow period. The feasi-
hausts only air or gas. Bottom chokes plified quantitative test interpreta- bility of waiting for a complete build-
smaller than 3/16 in. are usually tion. For these sizes of drill pipe, up depends largely upon hole condi-
undesirable due to the ease with the number of feet of liquid recov- tions.
which they will plug. For the flow- ered during flow periods of these If experience has proved that the
ing type of test through tubing where lengths happens also to be the num- tool cannot be left shut in long
the bottom choke is not used as a ber of barrels per day that the test enough, plans may be made to ob-
flowmeter, a 3/16- or %-in. bore would produce during 24 hours serve a partial buildup both before
bottom choke used with a top choke through the particular size of choke and after the flow period. This is
of about the same bore may prove under critical flow conditions. This referred to as a "dual shut-in" test
more feasible. Gas zone tests are amount of time, which might be and is described below.
sometimes made with bottom chokes termed as the standard flow period, PROCEDURE FOR DUAL SHUT·IN TEST
ranging from % - to ¥s -in. bore in can be computed for any size of 1. The volume of the hole below the packer is
calculated and the displacement of the anchor is
order to obtain a measurable pres- pipe by Eq. 1. Standard flow periods subtracted. This gives the volume of the mud only.
sure drawdown. Zones of very low are suited to moderately to highly 2. The test fool assembly, using a hydraulic
tester valve, is made up with sufficient drill pipe
permeability which have very low productive areas where it is not de- or tubing placed above the hydraulic tester to
accommodate 10 to 15 per cent of the mud volume
flowing pressures are frequently test- sired to flow the well, large drill below the packer. A disk valve is placed in the
ed without chokes; however, this pipe is in use, and the several thou- string at this point.
3. The tool is set and the hydraulic tester opened
practice is not recommended unless sand feet of oil or water that can in the usual manner, but the disk valve go-devil
be recovered in the standard time is not dropped until the initial shut-in time has
there is sufficient prior experience to elapsed and a flow period is desired. At the con-
indicate that nonrestricted flow is generally will not exert a backpres- clusion of the flow period, the rotating shut-in
tool is closed and the normal shut-in buildup is
safe. sure on the bottom choke in excess taken.
of 50 per cent of the upstream pres- When on bottom and the hydraulic tester opens,
In some areas drill-stem testing is the mud pressure below the packer is relieved into
sure. For such testing, a I-in. bore the empty drill pipe below the disk valve and the
made very difficult due to the choke formation is free to produce; however, the pres-
top choke is often used so as to hold ence of the disk valve restricts the amount that the
or choke screen becoming plugged
backpressure to a minimum. formation can produce and more complete shut-in
with sand grains or pieces of shale, buildup may be obtained in an equivalent time
no matter how thoroughly the hole Computed pressure profiles indi- than can be obtained after the flow period.

is conditioned before the test. One cate that when testing sands of mod- Selection of Pressure Recorders
technique of testing under such con- erate to high permeability, the length No drill-stem test should be run
ditions, where a subsurface adjust- of the flow periods ordinarily used, without two subsurface pressure

JUNE, 1956 23
gauges; if possible, one gauge should mation and stick the anchor; (2) it pacKel carries the larger load. If the
measure the pressures upstream or may cause plugging of anchor per- lower packer fails, the upper packer
below the bottom choke inside the forations or the bottom choke, and assumes the load.
perforated anchor, and the other (3) it contributes to packer failures.
should be blanked-off so as to meas- Flui~ cushions or water blankets Straddle Packer Testing
ure pressures outside the perforated can be placed in the drill pipe above
anchor. Under this arrangement, the the test tool to reduce the pressure Open-hole straddle testing involves
two pressure records should agree differential that occurs across the testing a productive interval which
exactly unless the holes in the per- wall of the bore hole and packer as may be as much as several thousand
forated anchor become plugged, in the tool is opened; however, this feet from bottom. A wall packer is
which case the ~lanked-off gauge procedure may make test interpreta- set in a competent seat above and
will trend toward the formation shut- tion difficult, particularly when the below the interval to be tested so
in pressure while the inner gauge will recovery is small, because the forma- that a selected zone may be isolated
reflect the pressure inside the anchor, tion liquids may mix with the water for testing through means of a per-
either atmospheric pressure or that cushion. forated nipple which is placed be-
due to the head of fluid recovered tween the two packers; convention-
It is sometimes advisable to use
before the plugging occurred. If the ally, the blank anchor extends to
fluid cushions when testing high-
choke becomes plugged but the an- pressure gas sands for reasons of total depth. Use of a straddle packer
chor pipe does not plug, both gauges safety. The cushion will effect lower by-pass tool will permit mud pres-
should trend toward formation shut- surface pressures until it has been sure to be equalized above the top
in pressure. The backwashing that produced out of the pipe. Occasion- packer and below the bottom packer

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occurs when the by-pass is opened at all times. This arrangement per-
ally, water blankets are a necessity
will usually clear the plugging mat- mits leakage of either packer to be
on deep tests in order to prevent the
ter from the perforations and may detected by watching the mud level
drill pipe or tubing from collapsing
clear the choke if run under the in the annulus. It also provides for
due to high external mud pressures.
equalizing valve; proof that plugging easier release of the bottom packer.
occurred cannot always be obtained Gas Cushions Both packers must withstand approx-
solely by examining the tool. Natural gas or bottled nitrogen imately the same pressure differen-
The pressure recorders are built in have been used instead of water to ·tial. The blank anchor below the
a number of pressure capacities as provide an initial reduction in the lower packer is not severely loaded
well as clock speeds. The service pressure differential applied to the as in a conventional test unless the
company should be informed of the formation when the tool opens. This straddle packer by-pass tube is not
maximum expected pressure and the is accomplished by pressuring the used and the formation breaks down
expected period of time that the tool tubing to the desired amount through or filtration processes reduce the vol-
the control head just prior to open- ume of mud trapped in the hole un-
will be on bottom. The pressure re-
corder may then be selected, if avail- ing the tool. This backpressure is der the lower packer. A new develop-
then bled off slowly after opening ment is a sub having dogs that can
able, so that the maximum recorded
the tool. Gas cushions have been be caused to wedge into the wall of
pressure will be approximately two-
thirds to three-fourths of the max- used to good advantage for drill- the bore hole to support the straddle
stem testing during workovers where tool.
imum pressure capacity of the gauge,
and the chart travel during the time high-pressure gas is available from Three pressure recorders should
on bottom will not cause excessive a gas-lift system. be used-two for the test zone in
overlapping of the stylus traces. If the usual fashion and one below the
Method of Handling Test
the test recovery is to be reversed out Production at the Surface lower packer arranged so as to meas-
with pumps, the pressure capacity The fluids recovered should be ure pressure in the zone under the
of the gauge should be sufficient to disposed of in the manner which lower packer.
record the mud pressure plus circula- involves least hazard to the drilling Straddle testing is being applied
tion pressure. rig, surroundings, and to the further extensively in the multi-sand forma-
progress of the well. Consideration tions of Southwest Texas, where
Location of Auxiliary Tool usual interval tested is about 30 ft
Components should also be given to the degree
of accuracy required in measuring or less and the average distance off
The circulation tool is frequently bottom is about 200 ft and ranges
run one to three stands of pipe above the volume of recovery. If at all pos-
sible, the recovered liquids should be up to over 1,000 ft. It is being used
the tester valve. This permits reten- in drilled rather than cored rathole
tion of an uncontaminated sample reversed out into a tank or pit.
intervals in wells where logs are run
of formation liquids, if the recovery every 500 to 1,000 ft; possibly pro-
is reversed out. The jar is placed Special Packer Arraugements
ductive zones for testing are chosen
above and as close to the packer as Dual Wall Packer Testing by log and sidewall core interpreta-
possible. tion. There has also been extensive
Two wall packers of the same or
Water Cushions slightly different size can be run one application in the East Texas area
With the opening of the test tool, above the other to give added assur- to permit complete 50- to 90-ft dia-
the pressure on the formation is re- ance of obtaining a satisfactory seat. mond cores to be cut prior to pulling
duced almost instantaneously from The practice is widely used where out to test.
mud pressure of several thousand psi there is doubt as to the condition of Straddle hookwall packer testing
to the initial flowing pressure or the packer seat, particularly in frac- inside casing may be employed where
sometimes to atmospheric pressure. tured formations. To be effective, there are several perforated intervals
This flash release of pressure is un- both packers should be set in sand and it is desired to test each selec-
desirable for the following reasons: or hard formations. When set in a tively without setting bridge plugs
(1) it may cause caving of the for- hard, competent formation, the lower or squeeze cementing.

24 JOURNAL OF PETROLEUM TECHNOI.OG\

 Performing the Test Opening the Tool has been high, it may be desirable to
Short duration, nonflowing, open- bleed pressure on a small choke
Preparing the Hole
hole tests should not be permitted to while rotating; after rotation has
The hole may have to be reamed exhaust gas or air to atmosphere clo&.ed the tool, the flow line may be
down to reduce the amount of rat- within the derroick unless it is certain reconnected and the pressure blown
hole. Generally, 300 to 500 ft of rat- that surface pFessUlles will be negli- down to the pit or tank,s. During the
hole is the maximum that is cus- gible; this applies particularly to shut-in period, the formation pres-
tomarily carried. After reaming, the power rigs. Flow lines should be sure builds up to its static or maxi-
hole should be washed clean to bot- rigged to the reserve pit and suffi- mum value under the packer. Unless
tom of the remaining rathole and cient flexible pipe should be con- the formation is very permeable, this
should then be circulated at least nected to the control head to permit may require an excessive amount of
one cycle. In circulating the hole the pipe to be picked up with a time.
clean, the bit should be positioned at minimum of delay to close the tester
a point above the packer seat; pipe Pulling Out
valve in the event of an emergency.
should be lowered occasionally to Care should be taken to see that a At the conclusion of the shut-in
clear and condition the rathole in the period, the drill pipe is raised a foot
tool joint will not foul the blowout
test interval. The trip out to test or so while observing the mud level
preventers. Since it may be desired
should not be begun until such time in the annulus. The level may drop
to pump through the drill pipe or
as the tool can be made up, run to sIlghtly when the equalizing valve
tubing in case an open-hole test gets
bottom, and opened with a minimum opens and mud flows into the zone
out of control and since the control
of delay or waiting time. Periodic head may be as much as 30 ft up under the packer. After pressure has

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tests of mud weight should be made equalized across the packer, strain
in the derrick, a surface control head
while circulating so that a reliable may be taken to unseat the packer
to which the kelly can be connected
value of the hydrostatic pressure can and start slowly out of the rathole.
throughout the test will permit hoist-
be calculated to check the accuracy Once the packer is clear of the
ing or pumping to begin with a mini-
of the pressure recorders. rathole, the tool may be pulled out
mum of difficulty and loss of time.
more rapidly. Care should be taken
Making Up the Tool The same precautions apply to tests
to see that the well is not swabbed in
After assembly of the open-hole made inside casing, although the con-
while pulling out; a torn wall packer
tool, measurements should be taken trol head is usually accessible for
may bridge even the larger diameter
to check the packer spacing and to making connections.
main hole. The annulus should be
permit the last joint of pipe added to All safety rules regarding smoking filled after pulling each thribble of
be marked at the point where it or open fires should be rigidly en- pipe until it is clear that no swab-
should be flush with the rotary when forced dwring the drill-stem test. Ex- bing is occurring and then at least
the tool is just touching bottom. This plosion-proof safety lights should be after each three thribbles or more
procedure permits the tool to be dimmed or turned off, while unpro- often, depending on drill pipe size,
eased into contact with the bottom tected light bulbs should always be last casing size, mud weight, and
of the hole and provides a check on turned off. Power rig engines might the mud overload pressure being
the weight indicator; weight indicator best be idled in order that hoisting carried. Should the annulus be filled
readings alone may lead to difficul- power will be available without de- and overflowing continuously, it may
ties if true bottom has not been lay, provided the test flow is directed not be possible to determine whether
reached. A similar procedure should to a pit or tank off the rig floor. .Tust the overflow is from the pumps or
be used for testing inside casing, and before opening the tool, the annulus due to swabbing action. The per-
the mark should be placed so that should be filled if necessary. Close missibility of rotating out of the
the lowest part of the test tool will watch on the annulus mud level hole depends upon what components
be the necessary distance above the should be maintained when the tool are included in the tool string.
top perforation so as to permit the is opened; a sudden drop in fluid
surface control head to be conven- level indicates that the packer is not Reversing Out Test Recovery
iently accessible from the derrick sealing. A very slow loss of fluid is When the recovery is oil, removal
floor. not serious since it is usually caused by pulling wet stands involves a defi-
by a loss of mud or filtrate to a frac- nite fire hazard since the oil is
Running In
tured or porous zone; however, con- dumped from each stand onto the
The speed at which the tool can be stant vigil should be maintained floor and cellar as the stands are
run to bottom should be at least 25 throughout the test and the mud level broken out. In addition, gas pockets
per cent slower than usual; a mod- kept in sight at all times. within the column of oil may cause
erate amount of spudding is possi- heading of the oil from the top of a
Before opening the tool, the high-
ble. From time to time while run- st-and high up in the derrick. The re-
pressure rubber hose provided by the
ning in, the drill pipe should be service company should be connected sulting cold spray can be ignited by
checked for leaks by observing from the control head to the gauge causing hot light bulbs to explode, or
whether or not air is flowing from manifold on the rig floor; the end of by blowing onto magnetos and hot
the pipe and by observing the the hose may be held in a bucket of exhaust manifolds on power rig en-
amount of spill-over that occurs as water to allow the increased hlow gines, or the boilers on steam rigs.
each stand is lowered into the hole. that will occur when the tool is The inclusion in the string of a
If it becomes necessary to shut down opened to be detected immediately. reverse circulating sub which can be
opened to the annulus at the conclu-
with the tool only part way to bot- Shut-In Period sion of the test will permit the oil to
tom, close watch should be kept on At the conclusion of the flow pe- be flowed or pumped by reverse cir-
the annulus mud level to determine riod, the tool is closed by means of culation to a pit or tank with relative
that mud is not entering the pipe the rotating shut-in pressure valve. safety, even at night. This is particu-
through a leaking tool or tool joint. On gas tests, if the flowing pressure larly desirable in the case of hook-

JUNE, 195()
wall packer testing inside casing Salt Water Samples yields only formation water, the mud
since this type of test is usually con- Absence of oil or gas in a tested below the packer is displaced up-
ducted for a long enough period to formation cannot be considered ward into the drill pipe by water en-
permit the pipe to be entirely filled proved unless evidence is obtained tering the well bore. At first this
with formation liquids, and pump that representative formation water water is mud filtrate, followed in
pressure can be applied to the annu- is recovered. During the course of a turn by salt water. Fig. 2 illustrates
lus while the packer is set with min- study of subsurface waters in which the resultant variation of salinity
imum danger of breaking down the a large number of drill-stem tests with depth in the recovered water
formation. Reverse circulation in were made for the specific purpose column. The salinity increases rapid-
open hole is less attractive because of of obtaining representative water ly below the mud to a maximum
this danger, hazard of sticking the samples, a system of sampling was constant value. Any part of the water
pipe, and difficulty in accurate meas- column having this maximum con-
developed by M. S. Taggart, Jr., of
urement of small-volume recoveries. stant salinity is representative forma-
Production Research Division, Hum- tion water, or very nearly so.
When fluid recovery is believed to
ble Oil & Refining Co., which per- From the point of view of sam-
be large, a suggested procedure for
open-hole reversing is indicated mits determining by examination of pling, it may be seen that a sample
below. the samples themselves whether rep- taken just below the mud would have
resentative water is produced. The had a chloride content of only
PROCEDURE FOR OPEN HOLE REVERSING
following examples have been se- 32,000 ppm, whereas the true chlor-
1. At conclusion of flowing period, place 500
to 1,000 ft of fresh water of known chloride in lected from the results of this study ide content of the formation water
the drill pipe. was about 66,000 ppm. Except in ex-
to illustrate the variations of salinity

Downloaded from http://onepetro.org/JPT/article-pdf/8/06/21/2237729/spe-589-g.pdf/1 by guest on 13 March 2023

2. Pull pipe until water is encountered. Check
that pump is primed and ready. of the produced water frequently ceptional cases, such as after acidiz-
3. Open circulation sub and reverse out fresh
encountered under different condi- ing or when the drilling mud is of
water and formation liquids by letting mud "U·
tube" into pipe; keep the annulus filled. Control very high salinity, the water samples
flow from pipe with a suitable choke. If blowout tions of drill-stem testing.
preventer must be closed, use as little pump pres-
with the highest salinity are those
sure as is necessary, and count pump strokes while Typical Su.ccessfu.l Test which more nearly approach true
formation Iiquid~ are flowing to assist in deter-
mining volume; if may be desired to rotate pipe In the usual drill-stem test that formation water.
while reversing, if a swivel-type surface control
head is available.
4. Pull remaining pipe and remove circulation
sub; place a solid-type thread protector or plug in
each of the remaining two to five thribbles, as
each is pulled, and use a sealed mud saver when
breaking out. The purpose of the plugs is to pre-
vent heading of oil from a thribble that has been
raised into the derrick.

Taking the Data

Some type of drill-stem test opera-
tions report should be filled in. A
sample form is 5hown on Fig. 1. It
should be remembered that the re-
sults of the drill-stem test data may
be reviewed years after the test by
reservoir or workover analysts, who
will depend heavily on thorough, <: .... ' .. 0 .nv'..o., o. D 9% _IN __ .!'OL~...DATA_ '... 10..... NOI..Il, .,n D"LD HOLC ~,"
.1lT . . , ~. ~. ~'''.
adequate reports for guidance. TOT .. L oc..... . A#o
II.,.
n_. ,o~ 0"
-
""'''OLC''V .990
- n
n., ....O""'T
.Lin
D' ""V .. O\.C
,,"'THOLC
$D n

Drill-Stem Test Interpretation

Fluid Content -,4~·~So~_,,,.,,.,_.,:t
OPERATIONS TIME RECORD
L .... 'V .."' •• LC'''' .. O\..· "S'8 'o"~rro"~"_

When formation liquids are re- 7 :''6z 'O"p""'_"

~~
versed out or when the pipe is ~----
.,,,",,,""'.."00. ~ _ -_ _
~
pulled from the hole, an account of '''. OUTD' .. OLI:

....."'oo.=o~"~"" .. ~.'"
_ -_ _

the liquids recovered should be taken, ... ~"'~ro~ •• o.'"~".~....

both as to type and the volume in

barrels. The gravity of the oil should
be taken. It is important that the re-
covery of all liquid be measured MEASURED AND COMPUTED PRESSURE DATA

accurately as it is from this measure-

ment that the rate of production in
barrels per day may be computed. ESTIMATED PRODUCTIVITY DURING TEST
The volume of rathole mud recov- uN~ ~~+~.
o
~
P~OOUCTIVITY

-m~---:i!fjli!"~~{
INDEX

ered should be approximately equal p"cltqr+ _

to or less than the volume of mud ;;~~:;':N7. ;;;;".:::::,:;:":~.:::~~: :;::;.:~::~:~.;;;,r:;q.~
~. DllTl".. '''' ...VIO"
"L"'D <:OH,.",.&"'SfIlCMl::f ~. on'[I,,,,,,,,,,,,o .. _ ~00U<:V1VIVV '/ii+JlijiiCb";t
that was originally trapped below the " '..... " •• 0 ..

Bottom -' fcct of 10re ,.",,/ mile' u.ty .. hpJ«

=
packer in the test zone. A larger vol-
ume of mud in the recovery may be
..... ~m
n.,-eIlONII ... VOII,~
indicative of a fractured or vugular ~.~"'''CO OH.~. I
IHftIl",OCO.V:

formation, provided that the mud

level did not fall in the annulus dur-
ing the test. Fig. I - Sample record of a drill-stem test.

26 JOIJRNAL OF PETROLEUM TECID,OLO(;Y

Effect 0/ Leaking Packer pIes, on the other hand, permits the the individual test. The upper portion
Fig. 3 illustrates the effect of a determination from the variation in of Fig. 6 shows the typical configu-
leaking packer on the variation of salinity with depth in the recovered ration, the conventional sequence of
salinity with depth in the recovered water column of whether the pro- events, and the relative magnitude
water column. A sample taken im- duced water is representative. of the corresponding pressures. Sim-
mediately above the tool in this test The per cent of salt water recov- ilarly, charts from tests performed in
would have had a salinity about 24 ered may be estimated by dividing the conventional sequence but which
per cent less than that of the forma- the number of barrels or feet of for- were unsuccessful for one of the
tion water. Likewise, a sample taken mation salt water by the number of more common reasons will have a
near the top of the column would barrels or feet of total liquid, exclu- characteristic configuration which
have had a salinity much too low. sive of rathole mud; however, such discloses the reason for the failure.
percentages may be erroneous when The lower portion of Fig. 6 shows
Effect of Inadequate Yield the test is of short duration and the these typical configurations.
Drill-stem tests sometimes recover amount of recovery is small. Basic but minor differences in gen-
only mud and mud filtrate, the yield eral chart configuration for conven-
Pressure Measurements --
being insufficient to result in recovery Chart Interpretation tional sequence tests of moderately
of formation water. The mud flltrate Test interpretation, aside from the to highly productive zones will oc-
may have become contaminated with visual examination of the liquid drill- cur during the flow period, depend-
salt from the formation or by mix- stem test recovery, requires prelimi- ing on which of the following two
ing with formation water and m<l.y nary interpretation of the pressure conditions prevailed:
be mistakenly presumed to represent charts. The charts should be exam- 1. Critical flow: A small bottom

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formation water. An example of in- ined carefully, first to ascertain that choke (3/ 16 in.) used with a large
sufficient yield to recover represen- the tool operated properly and did top choke (1 in.) will usually cause
tative water is illustrated in Fig. 4. not tend to plug, and second to as- the flow of fluid into the drill pipe
In this particular well, the tested in- certain that the pressures during the through the bottom choke to be
terval was exposed to mud flltration test were measured accurately. The "critical" or independent of the
for an unusually long time prior to accuracy of the gauges must be pressure inside the drill pipe. Critical
the test. The chloride content of the judged by comparison of key pres- flow will produce a nearly constant
water entering the well bore was still sures read from both charts and by pressure throughout the flow period.
increasing at the time the tool was checking the measured initial mud 2. Non-critical flow: A large bot-
closed, and none of the recovered pressure against the computed mud tom choke, or none at all (equiva-
water was representative of the true pressure. lent to % in. choke), used with any
formation contents. The following key pressures size top choke will cause the rate of
should be read from the charts: flow of fluid into the drill pipe to
Difficulty in Cased Hole diminish constantly as the pipe fills.
The sampling of water recovered initial mud, minimum flow, average
flow, maximum flow, shut-in forma- The rise of liquids within the drill
by drill-stem te<;ts in cased holes pipe causes a corresponding increase
through perforations requires special tion pressure, and final mud. To read
these key pressures, a knowledge of in flowing bottom-hole pressure
precautions. Fig. 5 presents a com- which will level off only when the
parison of the results of testing in the exact sequence of events during
the test and the time at which these head or backpressure due to the re-
open and in cased hole in two wells. covered liquid column approaches
The wells were tested at very nearly events occurred is required.
the formation pressure.
the same depth, and both were tested Charts from successful tests per-
formed in the conventional sequence Low permeability formations are
in the same section of the formation. normally revealed on the pressure
Both tests should have produced of operations with no water cushion
charts by extremely low flowing pres-
water of substantially the same sa- will have the same general configura-
sures which often are too low for the
linity, since the salinity of this for- tion, although the magnitude of pres-
gauge to record; however, when the
mation water is known from other sures and time periods will vary with
tool is shut in, enough fluid may en-
tests to vary regularly with depth.
Although the water recovered from "r----,---------------,
'11'", ••
c...."'on 30
the No. B-1 well reached a maxi- -1_
i
mum constant salinity with depth in
the pipe, which ordinarly would he 25 - T
"
--.------~-

Mud Fdt''''e
taken as evidence of representative & Soh w"' ••

formation water, the maximum saIt 8 8

concentration was about 20 per cent
"":xl ----------~--"---___'_<}_--__j -+- ~20

! ~
less than that of representative water ~ I ~
I
recovered from open hole in the No. ~
a:: 15
I 15 --

1 well. Apparently, water traveling

behind the casing from some other
formation was produced during the
g
..
~ ~
i!
I
iii
~

~
-

test in the No. B-1 well.

11 10

The illustrations given show that i

a single sample of water recovered
I'~ ~

~---=-=-____::_l_:c_____,,_L_L--------'
during a drill-stem test is inadequate
for determining the properties of for- ",000
_ 17_ 0
0

mation waters. The single sample CHLORIDE CONTENT: PPM CHLORIDE CONTENT, PPM

may be representative, but this can- Fig. 2 -- Example of usual variation Fig. 3--Example of effect of leaking
of salinity with depth in recovered packer on variation of salinity with
not be determined. A suite of sam- water column. depth in recovered water column:.

JUNE, 1956
ter the test zone to cause a slow where little oil, condensate, or water value of Q, the gas production rate,
buildup of pressure. Such formations is produced can be estimated from in Mcf per day on the horizontal
should not be rejected too hastily in the charts. scale,
view of the potentialities of acid 4. Draw a line through this point
Ability of the Well to Produce
treatment or fo~ation fracturing up and to the right at a 45° angle to
processes. the vertical axis.
Open Flow Potential
Fig. 7 shows schematic examples 5. Draw a line parallel to the hori-
of the several conditions discussed Frequently it will be desirable to
estimate the open flow potential of a
zontal axis along the value of in Ps,"
above. thousands. At the intersection of this
gas sand interval from drill-stem test line with the 45° line, read the value
Gas-Oil Ratio data. A reasonable estimate of open
If little or no water is produced of Q, in Mcf per day, which is the
flow potential based on data for one
during the test, the gas-oil ratio may approximate open flow potential of
rate of flow can be obtained as fol-
be estimated by using the charts, lows: the tested interval.
Figs. 8 and 8-A. The rate of gas 1. Estimate of Mcf per day gas
production during tests of gas zones Productivity Factors and Specific
production rate, Q, during the drill- Productivity Factors
stem test by the procedure described
12r----,-------r-------,-------, e...n,on in the preceding paragraph. An index of the ability of the
\

' ..... ---i-___: .

+ 2. Evaluate: (P si 2 - P/) formation to produce liquid can be
10 -- -",-.. c-=-t-- --+--+---
,
Where, Psi = Formation shut-in
pressure + 15 = psia
obtained from the nonflowing type
of test usually employed for explora-

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,
+ P r = Average flowing pres- tory testing in open hole. This re-
sure + 15 = psia quires very accurate measurement of
3. On log-log graph paper plot the the length of the flow period, amount
value of (P'i 2 - P/) in thousands of recovery, and the formation flow-
on the vertical scale against the ing and shut-in pressures. A produc-

- - CRITICAL FLOW
- - - NON· CRITICAL FLOW

CHLORIDE CONTENT: PPM

Fig. 4-Example of unsufficient yield

to recover representative water.

45

'"
I
I
j\
Well No. 1 ~
TIm.

PRESSURES: A-tNlTlAL MUD

8 • PACKER SQUEEZE
C - AVE. FLOWING
O-SHUlIN
E- FINAL MUD
EVENTS' 0 -I.t THRl88LE IN
e -ON BOTTOM
• - TOOL OPfNEO
1- BUlLO UP COMPUTE
b-LAST THRI88LE IN
d-PJI,CI(£R SET
f -TOOl CLOSEO

tI - EQUALIZING VAL.VE OPENED

DST 5134·5195 ft. --... O-c - ORAWOOWN I - MQ(ER UNSEATED
J - 1st THRUL.E OUT k - LAST THAl88LE OVT
in open ~ol. I - nWE RUNNINe IN
2- FLOW PERIOD
35 TYPICAL CHARTS FROM 5 - SHUT IN PfRIOO
A SATISFACTORY TE ST 4 - TIME PULLING OUT

I
JO
<5 (TOP GAGE NOT BLANKED OFF. BOTTOM GAGE BLANKED OFF)
g LEGEND: - - TOP CHART (OR 80TH CHARTS)
- - - BOTTOM CHART
~ I 0
g ! (CRITICAL FLOW)

'"~ 2S
\

~
a:
-'
-'
ii'
0
"-
20
0 I
Well No. B-1
l'i
z DST 513()'5154 ft. - .....
thrjugh perforct,oi'
~
15

.
!
I PACKER FAIL£D NO SHUT-IN PRESSURE
!, !
10

,/_TJI\

1rt
i I
" i'+-! \ ~ \
. , ,
i '
I I \

i i
. ' \
I A C \ 0 E
j I \
20,000 40,000 60,000 so,ooo
OILORIDE CONTENT: PPM CHOKE PLUGGING ANCHOR PLUGGED TOP CLOCK STOPPED I} STARTED

Fig. 5 - Example of failure to test Fig. 6 - Pressure chart interpretation: Typical charts from a satisfactory test
formation behind casing. and charts from common types of mis-run.

28 JOURNAL OF PETROLEUM TECIlNOLOt;)

 tivity factor or index is computed
from these data.
The productivity, or PF, is defined
as the ratio of a constant formation
2- - 3
liquid production rate, barrels of
oil plus water per day, to the pres-
sure drop opposite the sand face.
The utility of the PF results from
NO PERMEABILITY VERY LOW PERMEABILITY SAND FACE POSSIBLY PLUGGED
the fact that the variation in sand
face pressure in good to strong wells
is usually a linear function of pro-
duction rate. The specific productiv-
ity factor is the PF divided by the
net productive feet of exposed pro-
ducing interval as judged from ex-
amination of cores or logs. The spe-
cific PF has an approximate linear
relationship to the ratio of effective
HI-GH PERMEABILITY ON
3116- BOTTOM CHOKE
HIGH PERMEABILITY ON
1/4- BOtTOM CHOKE
HIGH PERMEABILIty WITH
NO BOTTOM CHOKE
permeability to viscosity, millidarcys
(CRtlICAL FLOW) (CRITICAL FLOW) (NON-CRITICAL FLOW)
per centipoise.
The PF and specific PF can be

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computed from drill-stem test data
as outlined by Eqs. 1 through 4.
- 2 ,-
Use of Produtivity Factors
The relationship given in Eq_ 5
DE
can be helpful in investigating the
possibility of obtaining flowing pro-
EXCESSIVE FLUID HEAD INSIDE PIPE
GAS TEST - UNLOADED WATER CUSHION
duction by assuming a minimum
0- WATER CUSHION RISING TO SURFACE
b- WATER CUSHION BEING PROOUCED
FLOWING PRESSURE UPSTREAM OF CHOKE
REMAINED CONSTANT UNTIL THE BACK
satisfactory tubing pressure and a
c- FLOWING DRY GAS
d- TOOL SHUT IN
PRESSURE DUE TO LIQUID ACCUMULATION
INSIDE PIPE BECAME EXCESSIVE, RESULTING
maximum gradient; for example, the
IN A DIMINISHING FLOW RATE. dead oil gradient corresponding to
the API gravity of the oil or a gra-
Nor€: rH€ RUNNING IN AAO PULLING our PERIODS ON rH€SE CHARrS
ARE SHOWN COMPRESSED ON riME SCALE FOR CLARlrr.
dient corresponding to a mixture of
Fig. 7 - Pressure chart interpretation: various testing conditions. oil and an estimated per cent salt

,,~
,=
..~

," ..
'O~ ....
.>
.. '

..
,~

"
I" "
Ift.o
"

'" ",+H++-H--f1-H+f-1H--+H++-H--+H+---frH '" .'"

:~: .~.Jo
~

"oF'~'I;-'+-H+++-A--+++UP~E. FI(lUR{S FOR 1I4'~, CHOkE

,r'~ "
"
:: :+++~t~f=-1-~t+~t+'=-t---t"-'t-'"-1'-""+'-"H'-+O'-'t-"---t"'-,"+O-"H4/+·l--rH4J<
I
"
,.
. .0

Fig. 8 - Gas-oil ratio chart: ¥s- and *-in. chokes. Fig. 8A - Gas-oil ratio chart: 3/16- and 3/8·in. chokes.
Flow of fluid and gas through 1/8- and 3/16-in. by 6-in. chokes. Flow of fluid and gao through 1/8- and 1/4-in. by 6-in. chokes.
(Plotted from test data for downstream pressures less than 125 psi (Plotted from fest data for downstream pressures less than 125 psi
for values of /10 from 0.5 to 2.0 and API gravities from 32 to 42) for values of /Lo from 0.5 to 2.0 and API gravities from 32 to 42)

JUNE, 1956
water. If substantial production is which agrees closely with the bottom gauge read-
ing of 5,818 psi. The bottom gauge was then
indicated by this method, flowing assumed as reasonably accurate.
2. Check for complete pr~ssure buildup
production is probable since the ac- Since the bottom gauge pressure chart was nof
tual flowing gradient will be reduced available for examination and since the summary
did not indicate whether or not the shut-in pres-
by dissolved or free gas. sure buildup was complete, a check on the normal --- -+ -_.-
shut-in pressure for the depth was made by ex-
Use of Specific Productivity Factors amining initial reservoir pressures measured in
other producing reservoirs of comparable depth in
At times it may be of interest to the area. It was found that an initial shut-in gra-
dient of 0.465 psi/ft subsea was normal for the
make an estimate of the effective area. The elevation of the well in question was
permeability of the tested zone. This taken as 0 ft for convenience since it was known
that a borge rig was in use.
estimate may be made by utilizing Computed normal pressure was:
10,866 X 0.465 = 5,050 psi
the approximate relationship, given This was considered a reasonable check with the
by Eq. 6, between specific PF, the 5,025 psi recorded by the bottom gauge and the
formation pressure was assumed to be 5,050 psi
viscosity of saturated reservoir oil since buildup may not have been complete.
at reservoir temperature and pres- 3. Check for critical flow during test
In order to determine that the recovery entered
sure, and effective permeability. the pipe at a constant rate, the head on the bot-
tom choke due to the recovery was computed and
Subsurface sample analysis is re- found to be less than 50 per cent of the upstream
quired to determine the viscosity of recorded maximum flowing pressure of 4,380 psi.
Head due to 1,100 ft of oil and 180 psi surface VISCOSITY OF SATURATEO RESERVOIR OIL AT Po&. T,. CENTIPOISE
the reservoir oil; however, examina- pressure:
1,100 X 0.35 + 180 = 565 psi Fig. 9 - Correlations of API gravity
tion of a large number of analyses as compared with: 50 per cent of 4,380 = 2,190 with viscosity.
revealed that for reservoir tempera- psi.
tures between 140 and 240°F, the 4. Compute daily production rate during test

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Since critical flow seemed evident, the produc- R = F when Bf X 1,440
viscosities of saturated reservoir oils tion rate during the test was computed using Eq. 1
0$ follows: L
correlated reasonably well with API F
gravity of residual oil after flash R = T X 8f X 1,440 Productivity Factor =
separation at 0 psi. The correlation = 1,100 X 0.01778 X 1;440 Production Rate BID
is shown on Fig. 9. 25.5
Pressure Drawdown (psi)
= 1,100 B/D
Sample Drill-Stem Interpretation 5. Compute estimated productivity factor (2)
The productivity factor was estimated by using
The problem occurs frequently of 1,100 BID production, 5,050 psi formation pres- F
determining whether or not a drill-
sure, and 4,380 psi flowing pressure: L Bf 1,440
stem test has indicated that com-
1,100
(5,050 _ 4,380) = 1.6
4
B
/D . d d
pSI raw own PF = (3)
P,j - P f
mercial production can be attained. 6. Estimate gas-oil ratio
Gas-oil ratio was estimated to be about 1,000
There are methods of analyzing the cu II/bbl Irom Ihe flow chari lor 3/16·in. choke, Specl'fic PF = - - - PF---
test data which at least present a Fig. 8·A, using 1,100 B/D and 4,380 psi flowing Feet of Net Pay
pressure.
basis for founding opinions, even 7. Evaluate possibility of flowi.ng production (4)
by personnel not too familiar with Having evaluated the productivity factor, it was R PF (P" - P t - P f ,. - DX Gr)
possible to check the probability of flowing pro-
the area. It must be realized even the duction as follows: {a} assumed no water produc- (5)
broadest conclusions resulting from tion would occur, and (b) assumed a maximum
gradienl 01 0.370 psi/It due 10 dead 35.5° API K = 1,000 (Specific PF) V (6)
such analyses are subject to unavoid- oil.
The amount of production theoretically possible Symbols:
able error due to the number of even with this extremely high gradient was ,om-
puted as follows, using Eq. 5, and assuming 500 R = Flow rate, BID
variables that exist. Ib combined tubing pressure and friction pressure
loss: F = Liquid recovered, ft
The following is an example of a R = PF (P" - p, - PfT - D X Gr)
complete drill-stem test interpretation = (1.6) (5,050 - 500 - 10,866 X 0.370) L = Length of test, minutes
= 850 B/D
such as might be made from a typ- 8. Estimate effective permeability
Bf = Pipe capacity, blft
ical "morning-wire" drill-stem test The specific productivity factor and effective per- 1,440 = Minutes per day
meability were evaluated using Eqs. 4 and 6. A
summary in the form previously formation volume factor of 1.25 was assumed. The Gr = Flowing gradient, psi/ft
suggested. viscosity of the 35.5° API oil at reservoir condi-
tions was estimated at 0.5 cp from Fig. 9. V Viscosity of saturated oil
DST OF FORM FROM 10,889' 10 10,898'. 7" PF
WAll PKR SET AT 10,889'. 3/16" BTM CK & '/" Speci fie PF = Feet of net pay at reservoir condition
TOP CK. TOOL OPEN 25V, MIN & SI 30 MIN
MAX SURF PR 180#. REC 20' MUD & 1,100' OR 1.64 P" Formation shut-in pres-
19.5 BBlS OF 35.5 DEG API GRAY OIL NO S/W.
CHl OF MUD 7,200 PPM. PR CHART AT 10,861'
9 sure, psi
IMP 5,925# MFP 4,445# AFP 4,445# SIP 5,146# = 0.18 slock·lank B/D/psi/It
FMP 5,995#. PR CHART AT 10,866' IMP 5,818# 0.18 X 1.25 = 0.225 reservoir B/D/psi/It Pf Formation flowing pres-
K = 1,000 (Specific PF) V
MFP 4,380# AFP 4,380# SI P 5,025# FMP
= 1,000 (0.225) (0.05) sure, psi
5,890#.
= 112 md
1. Check accuracy of pressure gauges P t = Tubing pressure, psi
Initial mud pressure from the top gauge WQS
5,925 psi, as compared with 5,818 psi from the P fr = Friction loss, psi
bottom gauge, a difference of 107 psi. A check
indicated that mud weight was 10.2 Ib/gal at the
APPENDIX D = Completion depth, ft
time of the test.
Computed initial mud pressure due to 10.2 F K Effective permeability, md
Ib/gol mud was: R X Bf X 1,440
10.2 X 10,866 X 0.052 = 5,750 psi L PF Productivity Factor
It was noted further that initial mud pressure
due 10 10.3 Ib/gal mud would be 5,815 psi, (1)
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30 JOURNAL OF PETROLEUM TECHNOLO(;\