PLANNING AND CONDUCTING A BETTER DRILL STEM TEST

By: H. L. "Dusty" Rhodes

- - For the Man in the Field - -

INTRODUCTION

Drilling a hole into the earth formations, in the search for oil and gas, has traditionally

involved high risks. The incredible costs associated with the discovery and production of

oil and gas, have caused operators to more carefully analyze prospects before committing

enormous capital.

When you drill for petroleum, a giant puzzle for testing skill or ingenuity is created

and has to be solved, by putting all of the available technology together.

A Drill Stem Test obtains a part of this puzzle, that electric logs, cores, mud log

sampling and other technology does not provide.

The Drill Stem Test (DST) is the most reliable tool available for evaluation of the

prospective pay interval, as it simulates the result to be anticipated from an actual

completion. In addition to obtaining a sample of the formation fluid, it is also possible to

accurately determine reservoir pressure, the average effective permeability, and the

degree to which drilling has altered the permeability from the well bore.

All of this technology is essential for the reservoir engineer to predict the

performance of the pay zone. A properly run an interpreted drill stem test yields more

valuable information per dollar spent than any other evaluation tool.

When you drill for oil, gas or water, you will need to determine whether or not it will

be of commercial value. The decision to set casing, and complete a low productive well,

depends on several conditions; depth location, and the added expense of completing the

well with stimulation, tubing, packer and other hardware required. A decision has to be

made on many wells each year that economics may not justify the added expense of

completing.

A properly run Drill Stem Test can provide you with information that is not available

from any other source.

1

DESIGN OF TEST

Drill Stem Testing is the most hazardous of all drilling operations and should

therefore, be conducted with utmost care. The safety of the men and rig always comes

first. It is imperative that everyone is clear on his assignment and that kill procedures can

be implemented immediately, should equipment fail or an extremely hazardous condition

develops.

PREPARATION AND PLANNING

One of the principal limitations to open hole testing has been the lack of a properly

planned program to include complete well preparation prior to testing. Good hole

condition means fewer miss runs, less plugging, better test results, and eliminating some

of the chance of a blowout, lost circulation and stuck tools. Basically, if the mud program

has been properly maintained, the hole is in good condition for Drill Stem Testing.

OPERATIONAL PROBLEMS - CONDITION OF HOLE

A number of operational conditions should be reviewed to help determine if

problems do exist that may be detrimental to a Drill Stem Test. First, have there been

problems making a trip? For instance, were there any tight spots, dog legs, or key seats

in the hole? These conditions may cause a fishing job. Was the hole taking fluid when

you reached total depth? This could result in a blowout due to a low hydrostatic pressure

on a high pressure zone or a differentially tuck test tool. Is the hole washed out or

sloughing badly? If the fill-up does allow total depth to be reached and plugging is not to

severe on the test, the packer may become stuck. Check all operational problems and

consider how they may effect the test.

MUD CONDITIONS

The mud is probably the most significant concern in Drill Stem Test preparation.

The weight of the mud should be adequate to control the pressure of the producing zone

or any other high pressure zone. Inadequate weight may cause the mud to become gas

cut and cause a blowout, especially when the drill stem test tools starts out of the hole. A

gas pocket may follow the tool to such a point that the hole will unload. This makes it

mandatory to kill the well at that depth or strip drill pipe in the hole.

2

Solids should be kept to a minimum so that an undesirable thick, soft filter cake

does not exist. A thin, firm filter cake is more applicable to good Drill Stem Test

operations, and results in fewer stuck packers

A. GEL STRENGTH

Minimum mud gel strength for properly supporting cutting should be

maintained. High gel strengths will hinder the initial entry of the fluid into a

testing string; therefore, most of the pressures recorded in the early flow

time may be incorrect. The viscosity should also be the minimum for

adequate hold cleaning during circulation. Also, the mud should be

thixotropic enough to prevent settling of the cuttings.

B. FLUID LOSS CONTROL

Fluid loss control is probably the most important mud characteristic that

affects the interpretation of the test results. Low fluid loss control should be

maintained so that the least filtrate exists. Not only does this invasion cause

unstable hole conditions, but more important, it may damage the zone to

such an extent that the formation may not respond. A potentially productive

zone may appear to be barren when indeed it is not. Many operators

maintain a fluid loss of 6-10 cc/30 minutes when cutting the zone of interest.

C. CIRCULATE SUFFICIENTLY

Before pulling out of the hole for a Drill Stem Test, circulation should be

maintained for a sufficient time to insure the removal of cuttings. A high 60-

80 viscosity gel pill of 40-50 bbls. can be circulated around the hole to clean

out any loose cuttings. If "fill-up" is left in the hole, the test tool must "slide"

to bottom. This may result in plugging during the test, thereby frequently

producing inconclusive results. Many stuck Drill Stem Test strings are

caused by this condition. A substantial amount of miss runs are caused by

"sliding" to bottom with differential pressure across collapsed packers

causing destruction of elements and you may have a perfectly good packer

seat. To be sure the hole is in good condition and mud is free of cuttings

that my settle out while tripping out of the hole or tripping back in with Drill Stem

Test tools, an excellent test is to circulate the hole until mud is free of drilling

cuttings, then make a short trip up into a safe area of the hole or casing, set

3

static for an hour or so, return to bottom to check for fill on bottom. After the

short trip is made circulating bottoms up, chain out of the hole to prevent

the drill bit and bottom hole assembly from disturbing the walls of the hole.

Many operators spend a lot of time and money conditioning the mud and hole,

short tripping etc. to eliminate fill on bottom before a Drill Stem Test. Many

make the mistake of rotating out with the drill bit and bottom hole assembly

which disturbs the wall of the hole that may have cuttings in the filter cake

which allows it to settle out during the trip out with the bit and the trip back in

with the Drill Stem Test tools.

PACKER SEAT SELECTION

A packer seat in open hole testing is sometimes very hard to find in softer

formation, while hard rock country formations are very stable and usually offer any

number of selections. The best packer seats may be in this order: hard sandstone,

limestone or dolomite, conglomerates, and shale. Sandstone, limestone, or dolomite

having natural fractures may be poor packer seats. The degree of fracturing will

determine whether a small, insignificant leak exists or the seat is completely lost. Shale

may be a good packer seat if the hydratable clays are not hydrated by fluid filtration or

osmotic action of well bore fluids.

Two packers are normally run on critical or undetermined packer seat in a well.

This intent is simple if one packer seat fails perhaps the other will hold. Hopefully, a seat

can be found at or near the top of the zone of interest, in a true-gauge section of the hole.

ZONES TO BE TESTED

Selecting the interval to be tested is the responsibility of the geologist and reservoir

engineer. The geologist is most interested in identifying the formation fluids, whereas the

reservoir engineer also will desire good pressure and flow data. Where possible, long test

intervals should be avoided, best results are obtained, by testing short intervals.

The test should include one entire productive unit. Data analysis becomes more

difficult if several sands are tested simultaneously, if the test interval crosses a gas-oil or

water contact, or if only a portion of a thick sand is tested. The ideal time test, will be

4

immediately after drilling break occurs, loss of fluid into a permeable zone, or mud logger

gets a show.

The Drill Stem Test is run as early as possible, after conditioning hole for better

reservoir analysis.

Sometimes it will be necessary to drill through the prospective zones, run logs,

then straddle test the zone of interest. In others we may need to set a cement plug and

test off of it. Sometimes it is impossible to find a packer seat above and below a zone of

interest. In others, it may be necessary to actually set pipe and test, if the test interval is

to be adequately restricted.

HYDRAULICS OF DRILL STEM TESTING

It is most advantageous to have some understanding of the surface weights that

may be expected during each operation of Drill Stem Test. It is also important to

understand the slip or anchor load during these operations.

When the test string arrives at total depth, the weight indicator should show

approximately the weight of the string in air, less the buoyancy of the well bore fluid on the

dry drill pipe or tubing. If a water cushion is run, the total weight of that fluid volume is

added. The surface weight should be checked when total depth has been reached, to be

sure that a leak has not allowed fluid to enter the run-in string. Check the drill pipe or

tubing after each row is run into the hole with a sheet of paper, by punching a small hole

in it with a pencil and putting water on it, or with a wet rag over the run-in string is also

suggested. Most Drill Testing operators carry a device to place on top of the drill pipe

filled with water for checking.

When a water cushion is run, a flow of air or bubble may not necessarily indicate a

leak, because when water cushion was put into the drill pipe, air can be trapped or

increase in temperature causing water cushion to expand tripping into the hole. External

or differential pressure on the outside of the drill pipe can cause a slight blow at the

surface. This is caused by inside diameter decreasing caused by external pressure acting

on the drill pipe. Drill pipe will collapse sometimes if the strengths are not adequate to

withstand the external pressure on a string of drill pipe or tubing. This is one reason for

running a water cushion, to protect the collapse strength of the dry tubular goods. We

also have to hold back pressure equivalent to the water cushion that was ran on a Drill

5

Stem Test if the well unloads the cushion that was put in to protect the drill pipe. When

testing a gas well, always close the surface valve before closing the tool on bottom. This

will save some rig time, because during the closed-in period with the surface valve open,

the gas in the drill pipe will unload and when the tool is opened on bottom for another flow

period, the drill pipe has to be filled again or the formation has to produce enough to get

back to a stabilized blow on a choke. This takes time and the idea is to get a stabilized

gas production rate MCF/D.

When a water cushion is run and you get a blow of air out the drill pipe, another

check, when in doubt, will be to take the wiper rubber off and check the mud level in the

annulus to see if it is standing full or dropping. If the hole is standing full, drill pipe is not

leaking and operator may continue trip into the hole, checking as before.

All drilling personnel should realize as you trip into the hole with a Drill Stem Test

tool, that the differential pressure across the drill pipe increases. An external pressure is

being applied to the Drill Pipe.

The rig crew should be alerted, that if a strong blow develops during the trip into

the hole with the Drill Stem Test tools, they should be ready to pick up the kelly and load

the drill pipe with mud as quick as possible to eliminate the differential pressure. They

should also be tied into the annulus with the kill line to load the annulus. A loss of mud

hydrostatic pressure can cause a hazardous condition in a very short item. A possible

blowout or drill pipe can actually be washed into if a tool joint leak develops, causing a

fishing job. A heavy mud or abrasive fluid with a high differential pressure across a tool

joint can wash or cut it out in a few minutes on a Drill Stem Test.

In the process of slacking off weight to set the packer and opening the hydrospring

tester, the weight on the anchor is the slacked off weight. The weight indicator is now

showing the weight when total depth was reached, less the slacked off weight. The

weight on the anchor changes quite drastically when the tester valve opens and the

packer is seated. All the buoyant (upward) forces are basically the hydrostatic head times

the area of the hole. Therefore, the total anchor load of the buoyant forces and slacked

off weight may be as much as 500,000 lb. in some cases. The weight indicator is still

showing the weight when total depth was reached, less the slacked off weight. It is quite

obvious why some slacked off weight is lost and the driller must continue slacking off to

maintain a consistent weight immediately after the hydrospring tester valve opens. The

6

tremendous load on the anchor will cause the anchor to penetrate all soft fill-up until a firm

bottom has been reached.

Consider the difficulty in testing on a cement plug. Suppose the weight on the

anchor is only 200,000 lb. The end area of a five inch anchor is 19.6 sq. inches.

Therefore, the pressure on the cement plug is 10,205 psi. Rarely will be compressive

strength of the cement be more than 4,000 psi (unconfined) at test time. With these

conditions, the anchor will penetrate the cement plug. This is demonstrated when cement

is found very high on the anchor.

The weight on the anchor during a test may be changed by two other hydraulic of

forces; the build-up pressure under the area of the inside diameter of the hole which will

reduce the load, and the recovery weight in the run-in string which will increase the load.

When the test tools are by-passed and pulled off bottom, the weight indicator

should have the same reading as when the tools first reached bottom, provided the test

was dry (no recovery). The actual weight of any recovery is added directly to the weight

indicator reading.

After reversing out the recovery, the weight of the string is now the original weight

when arriving at total depth, plus the actual weight of the mud in the run-in string or close

to drilling weight.

CUSHION AND DOWN HOLE CHOKES

A water, mud or nitrogen cushion used on a Drill Stem Test may have three

purposes: to prevent the collapse of the run-in tubular goods; help control the well, and

relieve part of the sudden differential pressure across the packer seat. While a cushion

may help in these ways, it may be a hindrance to a good Drill Stem Test. Basically, the

lease differential pressure across the face of the formation will result in the most

production rate, or more critical, whether the zone will produce at all. In some instances,

more water cushion head is run than static reservoir pressure and the formation is not

allowed to produce. Generally, the least cushion that can be tolerated may result in the

best test.

It is much easier to obtain and analyze a Drill Stem Test if no cushion or down hole

chokes are used. In-flow of fluids becomes more readily apparent at the surface and in

most cases, the in-flow will be at sufficient rates to lift the rat hole mud above the closed-in

7

valve before initial shut-in. If the latter is not accomplished, doubt arises as to the gradient

to use for correcting measured pressures to actual formation pressure (of course, this is

not as much of a problem where gauges are located inside the anchor pipe and opposite

the producing formation). Actual recoveries also are easier to recognize and measure if

no cushion is used.

The Drilling Engineer/Supervisor must weigh the advantages of no cushion or

chokes, against the risk of not running them. Sometimes in deep, high pressure wells,

cushions must be run to prevent drill pipe collapse; but most of the time cushions and

chokes are run to prevent "shocking the pay zone" excessively; thus, causing sand

production or loss of packer seat, or worse yet, sloughing of formation around the anchor

pipe and sticking the drill stem test tools. Experience in the area, competence of the test

zone, anticipated formation pressure, etc., will aid in making a decision on the amount of

cushion to use. The volume of cushion should be accurately measured and recovered

(lb./gal or psi) so the recoveries can be calculated if the test is non-flowing. Some drilling

supervisors also spot a barrel of heavy gel at the bottom of the cushion to act as a "flag"

to recognize the bottom of the cushion during flow or circulating operations. Others

simply use the rat hole mud as the "flag".

TEST TIME

The Double shut-in pressure test is usually recommended for all DST's. This test

generally requires in excess of four hours on bottom time. If less time is available, then

we recommend a single flow, followed with a buildup equal to 1 1/2 to 3 times the flow

period. In no case would we recommend three flow periods (as has been suggested by

some service companies) as the third flow and buildup is wasting valuable rig time.

Well-site information, generally common well bore knowledge, can lead to an

estimate of maximum time available for testing. For this time, allowance must be made

for trip time. Loss of DST tools usually occurs as a result of:

a. Sloughing of pay around tail pipe,

b. Differential sticking of the drill-stem,

c. Sloughing of formations above the packer

8

It is believed that 95% of the cases, sticking of tools occurs while opening or within

the first few minutes of the test. Once the decision is make to run a test, it is best to use

the necessary time to obtain good data and/or achieve the object of the test (within the

limits estimated for soughing above the packer).

INITIAL FLOW AND SHUT-IN

The initial flow is used to relieve the pressure caused by mud infiltration, commonly

called "supercharge". Ten minutes are usually sufficient, but we generally recommend 20

to 30 minutes for extra safety. This also allows more time for rat hole mud to be pushed

above close-in valve.

The initial buildup not only serves as an important measure of initial reservoir

pressure, it gives us a "guiding star" for the final buildup curve. This point is very

important in our data analysis, and it should be taken on every DST, even though we may

already have obtained the correct formation pressure from a previous test. In other

words, the initial buildup "calibrates the gauges" for analysis of the final flow and buildup,

and it should be dispensed with except in very unusual cases.

FINAL FLOW

This final flow is used to recover a sample of the reservoir fluids and to create a

pressure sink suitable for obtaining data on the final buildup. Where possible, flow rates

should be held constant and the actual flow of various fluid measured accurately. The

following suggestions may be used as a general guide for the final flow period:

a. Ideally, remaining test time should be allocated so that the final buildup will

be 2 to 3 times the final flow period. Flow periods of at least one hour are

generally required; but a test that yields fluid to the surface might require

longer periods, to allow the well to clean-up, to take samples, and to make

gauges on flow rates.

b. Where flow is established at the surface, if feasible, the flow should be

maintained at a constant rate prior to shut-in for a period equal to at

9

least 1/2 the total flow period. Varying flow rates will distort the buildup

curve, making it difficult to analyze.

c. If a well opens with a strong blow and dies, then the fluid entry at the bottom

has ceased and nothing is being accomplished by keeping the tool open.

But if a well opens with a weak blow and dies, that is evidence that the

zone is tight, and the tool should be left open as long as practical to obtain

as much formation fluids as possible.

FINAL BUILDUP

The final buildup is the most important part of the DST. It is the reservoir

engineer's formation evaluation device. From the shape of the buildup curve, it is possible

to calculate the flow capacity of the formation with or without stimulation, and to evaluate

formation damage from drilling fluids.

Generally one hour buildups are sufficient to get good answers, if flow has been

held relatively constant. However, the longer a well is shut-in, the deeper the test will

investigate. Knowing gauge sensitivity, a reservoir engineer also should be able to

estimate the maximum time that the gauges will accurately record pressures. For

example, regular DST gauges have a sensitivity near 10 psi and work satisfactorily so

long as the draw-down or the buildup slope exceeds 50 psi/cycle.

As a general rule, for highly permeable wells, we recommend that the final buildup

be equal to the flow period (or a minimum of one hour). Obviously in some cases, with

regular DST gauges, the buildup will be "instantaneous" and long buildups are wasting

time. But in tight wells where economics may be in questions, we strongly recommend

that the buildup be run as long a practical which usually is about three times the flow

period.

MINIMUM TIME PERIODS TO GET GOOD DATA

Depending on the blow at the surface when the tool opens, the following methods

are recommended as minimum time on bottom testing.

1. Weak Blow at surface in the bubble bucket - (0-3)"

Initial flow period 30 minutes

Initial C.I.P. 90 minutes

10

Final flow period 60 minutes

Final C.I.P. 180 minutes

DST on bottom 360 minutes = 6 hr. test

2. Fair to strong blow at surface (blowing to bottom of bucket).

Initial flow period 20 minutes

Initial C.I.P. 60 minutes

Final flow period 60 minutes

Final C.I.P. 120 minutes

DST on bottom 260 minutes = 4 hr./20 minutes

These times are recommended as minimum time periods to get good data.

MONITORING THE TEST

To obtain the most from pressure data, it is essential that DST activities be

monitored fully and accurately. This currently is the most neglected portion of DST

procedures. Generally it is left to the service company representative to keep time

records, "besides, the clocks in the gauges should do this". The tool operator gets

involved with making the equipment function correctly; consequently down hole times

seldom check with surface recorded data, which too frequently are described in vague

terms.

The keeping of DST activity data is a full-time job and should have one person

designated solely for that purpose. In our opinion, this should be the job of the well testing

(reservoir) engineer. If he is not available, then the drilling engineer/ supervisor should

select a qualified observer, preferably a "company man" or the man in charge of the

chokes and surface test equipment. The observer's watch should be used for timing all

events. All activities that will in any way effect the down hole pressure readings must be

recorded to the nearest minute.

CONDUCTING THE TEST

The drilling engineer/supervisor has full responsibility for conducting the test. His

duties primarily are to make sure the equipment is run and set as planned, to ascertain

that the test is performing satisfactorily, and that safety precautions are being observed.

Service company representatives are present to assist the driller in making the tools

11

function correctly. Also, production people usually are available to operate surface testing

facilities.

PREPARING THE WELL

Before beginning a test, it should be determined that the hole and mud are in good

condition. Mud should be circulated for at least one cycle to be sure that all cuttings have

been removed. The mud weight should be measured during this period so that the

hydrostatic pressure, which will be indicated by the DST gauges, may be checked.

The drilling supervisor generally will require the drilling crew to "strap-out" before

running the test. It is important to know the exact length of drill-string to have control over

operation of the tools; to locate the packer seat and to know exactly the tested interval.

Sometimes cave-ins will fill a few feet of the hole during the trip, which will create a

temporary bottom for the tools. But when the tool is opened, the sudden loading onto the

packer will skid the tools to the bottom. This frequently will cause miss runs.

Confidentially knowing total depth and the length of the drill-string will greatly assist the

tool operator in setting and opening the tools.

The service company which is to conduct the test will have to know several hours

in advance the depth of the hole, hole size, length of test interval, probably duration of

test, mud weight, number and type of packers, number and type of pressure recorders,

bottom hole choke size, type of cushion, and the type of control head, circulating valve

and jars. Usually a service company representative is invited to sit in on preliminary

planning for all DST's to take advantage of knowledge of similar tests taken in the area.

Before starting in to the hole with the tools, the blow-out preventer should be

checked. The speed of running DST tools will be much slower than normal tripping to

prevent excess pressure surges. The mud in the annulus should be watched cautiously.

If mud is being lost, it may be a leading tool joint, or it may be that a weak formation has

been fractured from pressure surges. Of course, the check for leaks must be make with

the pipe stationary. If it is a leaking joint, the leak can be recognized as it will cause air to

blow out the drill pipe.

When bottom is reached, care must be exercised to make sure the tools are set

gently on bottom. Before opening the tools, all should be in readiness to flow the test, or

12

to immediately kill the well in case of some mechanical failure. Surface equipment should

be pressure tested in excess of pressures anticipated. Kill lines usually are left connected

during the test so that mud pumping can begin without delay if the well gets out of control.

Also, the elevators remain latched to the well head so picking up will close the tool and

dump mud on the formation, if surface control is lost on the well. All safety precautions

must be put into effect, such as no smoking, no welding, no open fires, no exposed lights

and above all, don't forget to check and take necessary precautions for hydrogen sulfide

production.

Generally, a bubble hose is connected to the well head on initial opening to check

for entry of formation fluids. With the free end immersed in a bucket of water, (and the

flow line shut-in), a blow of air will signal fluid entry. Sometimes just a few bubbles are

obtained. This may be due to a non-productive formation, too much cushion, a plugged

tool or a malfunctioning tool. Heating of the air column is sufficient to create a few

bubbles; thus such cases, test ones faith in the DST equipment. Generally, it is best to

assume that the tool opened and to continue with the planned short initial flow, followed

with the initial buildup test.

If a strong blow occurs, check immediately to see if mud is being lost from the

annulus. If so, pick up the tools immediately and shut-in the test. Sometimes it is possible

to re-seat the packer and continue with the test; but most of the time it is a miss run and

tools must be tripped out of the hole and new packer-seat selected. If the blow is strong

and no mud is lost, then prepare immediately to flow the well to pits. Do not allow the

cushion to surface without the valves open to pit, as this will cause an artificial buildup of

pressure, distorting the buildup curve.

Periodic checks of the annulus mud level should be made throughout all flowing

tests to make sure that leaks have not developed, creating a blowout.

DOWN HOLE SHUT-IN

Down hole shut-in is very important to both the initial and final buildups and should

be utilized in all DST's. Down hole shut-in aids DST analysis in two ways:

1. It prevents long periods of after flow for tight wells.

2. It prevents redistribution of well bore fluids around the gauges during shut-

ins.

13

CIRCULATION WHILE SHUT-IN FOR FINAL BUILDUP

Provisions are made in most DST strings to reverse out and kill the well while

awaiting the final buildup. This is said to save rig time. Do not commence any of these

procedures until you have obtained adequate data from the buildup. Dropping shear

bars, or any jolt received by the gauges, will alter the slope of the buildup curve and place

doubt on the remainder of the test. Once the buildup is underway, you should not allow

any movement of the pipe until you are ready to terminate the test.

REVERSE CIRCULATE TO CHECK DRILL PIPE RECOVERIES

Pulling pipe "wet" to check for recoveries is very hazardous and should never be

attempted on drilling rig. Frequently trapped gas will unload a partial column of oil, and

while the blowout may be short lived, it is too dangerous for the benefits obtained,

especially so where men cannot readily escape.

Pulling pipe "wet" has the advantage of saving time and permits a more accurate

measure of recovered fluids (if the well doesn't unload); but the rig crew must be fully

prepared for a probably short blow-out. Admittedly, it is frequently done on land based

rigs.

Where recoveries are circulated out, attempts should be made to sample the

recovery at periodic intervals and accurate estimates made of the fluid recovered.

Withdrawing the tools from the hole at the of the test must be done with utmost

care, as the danger of a blowout and fire is very great during this period. The annulus

mud level should be watched closely and it should be filled each time a stand is pulled.

Any sign of an upward flow of mud in the casing is an indication of a blowout and should

be treated as an emergency.

WHY SOME TEST FAIL

About 50% of all failures or miss runs are caused by the conditions of the hole,

improperly conditioned drilling fluid and the speed that tools enter the hole.

The open hole packer does not enjoy the controlled conditions of usage of the

hook wall or casing packer; it is frequently required to seal off in a plastic formation and in

a hole whose diameter is known only approximately. Successful use of rubber in wall

14

packers requires that the stresses be kept low enough that the rubber will act entirely in

the elastic or solid phase; that is, it must return to its original shape when the load is taken

off. This must be done by keeping the clearance between the packer and the wall of the

hole as small as practical, by keeping the axis of the packer parallel to and coincident with

the axis of the hole, and by choosing the packer seat in the least plastic formation

possible. It is important to have a straight true-to-gauge hole and a sufficiently heavy,

rigid anchor pipe.

It has been found that the ratio of a hole size to packer size largely governs the

amount of packer compression that will occur at pressure differentials up to 5000 psi and

that leakage or rupture of the rubber element will occur if the ratio of hole size to packer

size is such that complete mandrel travel is obtained.

A differential pressure of 500 psi will produce complete compression when ratio of

hole size to packer size approaches 1.25; 5000 psi differential pressure will cause about

50 percent compression when ratio of hole size to packer size is about 1.10. In the

commonly drilled hole sizes, the 1.10 ratio provides a reasonable balance between

clearance in true-to-gauge sections of hole and the excess expansion available, should

the packer seat yield or be washed out.

Somewhat larger clearances can be used with the "expanding shoe packers".

These packers were developed to permit a smaller packer diameter to be used than

feasible with conventional packers.

SHORT PACKERS VS LONG PACKER ELEMENTS

The controversial subject of "short versus long" packer elements and which affords

the best seal in isolating a formation during a Drill Stem Test was laid to rest

approximately twenty years ago.

The field has many years of experience with the long packer element. Engineering

research and field evaluation of the shorter element (15") proved that it provided many

distinct advantages over the long element.

The rubber companies that made our packer elements, gave us a criteria to follow

in designing the shorter element. The length of the packer should not be any longer than

3 to 4 times the diameter of rubber element. This design, when compressive loading, will

provide a smooth concentric enlargement of the rubber element. If the rubber element is

15

longer than the prescribed theory, there is a torsional twist under compressive loading that

endangers the rubber about every fifteen inches. These enlargements (or bulges) of the

rubber will be thicker on one side than the other. Also, the second enlargement due to

some loading and torsional twist of the rubber will be located about 15" from the first

enlargement, but the thicker and thinner sections of this bulge will be located 180 degrees

from the first. The long type element is subject to non-uniform loading resulting in

destruction and leakage. Tests in the laboratory and field verify this.

When going in the hole fairly fast with a long packer element fitting close to the

hole size, the piston effect of the fluid rushing around the OD of the packer will cause the

packer to set prematurely, damaging the element before reaching bottom. Shorter packer

elements are not prone to set prematurely because the fluid restriction between the hole

and the OD of the packer is not as long. The short element has only one restriction,

whereas the longer element could possibly restrict the flow in two places, depending upon

its length.

When the packer is set to isolate, the formation and the tester valve is open, a

pressure differential is created across the packer. This heavy loading of the rubber

pushes or crams all the rubber to the bottom support. This bulge on the lower end of the

packer seals against the well bore and the packer mandrel for a length of approximately

four inches. Longer packers do not afford and better seal because the effective sealing

place of any packer will occur near the bottom end where there is support for the rubber to

prevent overflowing of the rubber element.

Longer packers, when set compressively, normally form two bulges or swells

approximately 15 to 20 inches apart, as mentioned previously. However, the top bulge

normally does not seal because the rubber is not supported in this area to prevent

overflow. This second bulge, even though it is not sealing, is wedged in this clearance

between the packer hole and OD of the mandrel. For this reason, longer packers require

more pull above the pipe weight in the hole than a shorter packer. Also, if the packer is

very long, the area in contact with the well bore acts like a differentially stuck pipe and

requires an excessive amount of pull to release and equalize pressure after the test is

terminated.

DRILL STEM TESTING METHODS

16

A. Possible productive zones as they are penetrated.

1. Full-gauge hole

2. Core hole - ream after testing

B. Drill to TD then test zones by plug back or straddle testing.

PLANNING TEST AND PERFORMING

1. Mud condition - the key to a good Drill Stem Test

a. Viscosity - high enough to carry cuttings

b. Good gel strength - hole material in suspension during test

2. The string of tools - typical string, but may vary to suit conditions.

3. Basic items to consider

a. Selection of packer seat

b. Selection of packer size

c. Amount of hole to test

d. Choke size

e. Amount and type of cushion, if any

f. Selection of pressure recorders

g. Probably length of flow time and closed in pressure time

h. Speed to run tools in hole - depending on overall conditions; mud

weight, viscosity, drag, hole size, packer size, and several things you

will not know until you run tool sin different areas of hole. Do not run

tools and break down formation and tear up packers before reaching

bottom.

INDIVIDUAL COMPONENTS OF THE STRING

Operating mechanism of the various tools are controlled by the following:

1. Rotary or vertical movement of the drill pipe or a combination of the two.

2. Hydraulic pressure - supplied by either the mud hydrostatic of the formation

pressure or by pump pressure.

3. Impact of a falling object in the drill pipe.

A. Impact reversing sub or pump out disc sub. Used as an alternate method for

reversing.

17

B. Choke and handling sub bottom hole choke to control flow of fluid from formation in

high pressure area. Small enough in comparison to surface choke, not to cause

excessive pressure on drill pipe. Very small percentage of test use bottom hole

choke. Most use .75 (3/4) inch standard ID for 5 inch OD tool because they get a

better draw down on formation pressure.

C. Dual and triple CIP valve sampler - five and seven position tool. Used for reversing

and taking closed in pressure. Flow time - sufficient for releasing super charge in

formation (consider local conditions). Closed in time - sufficient for 75% closure.

D. Hydrospring tester valve also used as a multiple shut-in valve and sampler with

indexing "J" slot reciprocating shut-in valve keeps drill pipe empty and retains a

sample of the recovery while pulling out of hole. Delayed action opening

combination bypass valve and tester valve (one or the other or closed).

E. AP-BT Case - Flow stream gauge - Recovery flows pass gauge. Two pressure

gauges should always be run on a Drill Stem Test. A blanked off or outside gauge

on bottom of perforations. An inside gauge which flow passes by. Plugging of

perforations or in tools can be pin-pointed.

F. Bourbon Tube - BT gauge operational - no friction accuracy related to repeatability

for best accuracy, use 75% of gauge range. Use as much of the clock as possible.

Availability of clock and gauge ranges. Gauges 750 psi - 20,000 psi. Clock ranges

3 hours - 120 hours most common 12, 24, 48, 72 hour clock for Drill Stem Testing.

G. Rotary Jars - types

1. Hydraulic

2. Oil Filled

3. Gas Filled

Function of jars is to temporarily hold the lower end of the drill pipe only long

enough to put a "stretch" into pipe. When suddenly released, it delivers a

blow or "jar". This temporary holding may be hydraulic pressure or by

mechanical means.

H. Safety Joint - used for detaching the string from the packers or anchor in the event

the they become stuck. Safety joint may be run in anchor below packer.

I. Open-hole Packer Assembly provides seal between wall of the hole and the packer

above zone to be tested. Available 2 1/4" to 11 1/2", larger on special order.

18

Durometer - comparison of hardness 50, 75 and 90 450 series for extremely hot

holes up to 400 degrees F. temperature. Packer size versus hole size, normally

1/2" to 1" clearance from gauge hole depending on size hole. The smaller the

hole, the closer you should run packer tolerance between OD packer and ID of hole.

J. Distributor Valve is designed to regulate pressure between open hole across more

than one packer. Distributing the pressure across two or more packers is

advantageous when testing a weak or vertically fractured formation. A high

differential across any one packer may cause the mud to communicate around the

packer through a vertical fracture. Distributing the load across two or more

packers may also help keep the formation from crushing under excessively high

hydrostatic loading of a single packer. Regulating the pressure between two

packers prevents buildup of excessive pressure (between packers) when the

packers are set and differential pressure created when tester valve opens.

K. Casing Packer Assembly, packer rubbers available in 50, 60, 75, 80, 90, and 95

duo materials.

L. Sidewall Anchor Assembly, used instead of long anchor pipe, works best on

straddle tests because pressure is equalized above and below packers.

M. Anchor, perforated used as support and anchoring force for tool operation. Interval

to test, most satisfactory results are obtained in short in short lengths of 30" or less.

Can determine water/oil contracts, will have less rat-hole mud to contend with.

N. Anchor Shoe Case, location of bottom blanked off pressure gauge and

temperature recorder or thermometers. Can pin-point plugging perforations with this

gauge when inside gauge is run in stream below shut-in valve.

PRESSURE DATA IMPORTANT

Indications are that by the proper application of known physical surface indications

or bubble hose to establish rules of thumb, it is possible to increase the technically

successful DST runs to 90% of the total attempts. This more than doubles the present

37% technically successful DST runs, assuming that the hole and mud will be in proper

condition and that the proper tool will be run. Well site information, generally common

well bore knowledge, can lead to the establishment of total time figure in hours that

represents the maximum length of time the hole can be safe without circulation. From this

19

total time figure, allowance must be made for the trip time involved in running the string of

test tools in and out of the hole. The remaining time is available for on-bottom testing

time.

This testing time will then be divided into four periods: initial flow, initial shut-in,

final flow and final shut-in. We have found that using 20 minutes minimum and 30

minutes if possible on initial flow will in most cases relieve any doubt of a super charged

formation. Initial shut-in should never be less than 45 minutes if initial flow is 20 minutes

and should be 60 minutes or double the flow time.

The remaining time can be divided into two periods; one for final flow and one for

final shut-in. Only after actual observations may this plan be altered successfully.

1. If blow remains strong throughout flow period time, give final shut-in period

at least equal length of time.

2. If blow is weak and dies during flow-period time, shut tool in when blow dies,

and give final shut-in time equal to twice flow period.

3. If blow is extremely strong and formation fluid surfaces during flow period

time equal to at least one half the flow time.

4. Unless local conditions prove otherwise, the final shut-in period should

never be less than 30 minutes.

Use of these suggestions, regardless of time allowed for the test, will greatly

increase the technical value of data obtained from the test.

By applying known technical principles to reliable test data obtained from the

perfect Drill Stem Test, there is provided an engineering and geological tool that will

furnish information not available from any other source. It will provide pre-completion data

that will greatly aid in making completion plans. It is the only method of actually

determining the flow characteristics of a give formation prior to completion.

REPORTING THE TEST

A. Data sheet should be filled out as complete as possible, for it will become a

part of your well file. Responsibility of everyone is to see that data is put on

sheet.

B. Testing folder - Chart reproduction and data sheet, plus special sheets, and

calculations depend on this information.

20

DATA AVAILABLE FROM A FORMATION TEST

The data obtained from a "normal" DST generally includes physical description of

reservoir fluids, volume of recovery, flow times, shut-in times and a bottom hole pressure

time chart shown the well bore pressure measurement during the various tool manipula-

tions.

Reservoir characteristics that may be calculated from the formation test are:

1. PERMEABILITY; The permeability calculated by a formation test is the

average effective permeability of the formation to the actual fluid produced.

The formation test is the only evaluation tool and give a direct means of

calculating effective permeability. Complete core analysis gives absolute

(not effective) permeability measurements, is expensive, and is not always

obtainable.

2. WELL BORE DAMAGE: Whether or not well bore damage has been

incurred by the mechanical drilling action is readily indicated by empirical

calculations. Well bore damage can and does impede fluid flow from

formations. Low recovery on the test may be the result of damage rather

than poor producing characteristics. Well bore damage determinations can

be made only from pressure fluctuations such as those induced by a DST.

3. RESERVOIR PRESSURE: It is possible to make mathematical

determinations for the static reservoir pressure. This pressure value is

useful as a substitute for a missing stabilized or static mechanical

measurement (stabilized initial shut-in pressure reading) and as a check on

other calculations.

4. DEPLETION: If a given reservoir is small enough that its' real extent is

affected by the normal DST, pressure depletion will occur and be detected

by a properly conducted DST. If the relatively small volume of fluid removed

during a normal formation test causes pressure depletion, then an

extremely small reservoir exists and experience has shown that it will not be

commercial.

5. RADIUS OF INVESTIGATION: Because there is physical removal of

formation fluid during a DST, there will be definite effect upon

21

the formation for a determinable distance. This distance is known as the

radius of investigations of the test. This characteristic may be

used in determining spacing requirements and other volumetric calculations.

6. BARRIER INDICATIONS: If a barrier of any other anomaly, such as a fluid

contact exists within the radius of investigation of the test, it may be

reflected in the pressure analysis. Through other evaluation data and

experience in interpretation, it is often possible to determine the exact type

of anomaly.

Much has been written about the use of the DST to define limited reservoirs and/or to

locate barriers. We would like to "lay-down" this utilization, as we believe that the chances

for misinterpretation are too great. Only under ideal test conditions and with extremely

accurate gauges would be attempt such tests. The reservoir limits test requires several

hours, sometimes days, to investigate an adequate distance; hence it is usually

impractical (or too expensive to obtain) with the DST.

PERMEABILITY

Permeability determined by buildup analysis is known as effective permeability.

This value of permeability is the best permeability measurement possible because it is

obtained at reservoir conditions. This value of permeability is the one used in "FRAC -

GUIDE" equations. A discussion of the uses for this parameter will not be given, as it is

the reservoir parameter most familiar to engineers and geologists.

WELL BORE DAMAGE

Perhaps one of the most valuable determinations to be made from test data is

estimating the presence and magnitude of well bore damage. This is particularly true of

test resulting in low fluid recoveries. In the past, low fluid recovery meant only one thing -

poor production potential. As a result, many wells were abandoned needlessly.

Subsequent increase in technical knowledge has shown that some of these abandoned

wells were actually commercial producers that required stimulation. In many cases,

stimulation in the form of a simple acid wash job, can be performed to remove this

damage.

22

Well bore damage is defined as being a zone of reduced permeability immediately

adjacent to the well bore. It is generally the result of or caused by the mechanical action

of drilling a hole into the formation. Well bore damage is also referred to as skin effect,

skin damage, skin, etc. The net effect regardless of what it is called, is to reduce the

amount of fluid entry into the well bore as a result of any given pressure drop induced

during the test. The damage can be so extensive that it can even prevent formation fluid

production completely.

CAUSES

To understand well bore damage, it might help to look briefly at the various causes.

Four common causes of damage are:

1. Invasion of drilling fluid filtrate into the formation.

2. Invasion of drilling solids into the formation.

3. Bit damage.

4. Production damage (relative permeability effects).

Drilling Fluid Invasion Damage The invasion of drilling fluid into a formation occurs

anytime a formation has permeability and the drilling fluid has a fluid loss. This is a

natural result of the physical characteristics of the properties involved. The drilling fluid

has weight and naturally will develop a hydrostatic pressure. This hydrostatic pressure

must be maintained higher than the formation pressure or there will tend to be a blowout.

With the unbalanced force system, there tends to be a fluid movement from the well bore

into the formation to some extent even after a mud cake is established. In water base

mud, this fluid is water that has filtered through the mud cake, or filtrate water. The higher

the water loss property of the mud, the greater the amount of filtrate water that tends to

enter into the formation.

Some formations are not compatible to this foreign water and will react in an

adverse manner. One type of reaction, as an example, is that of a shale sand. For eons,

this shale sand formation has existed in exposure to only a salt water solution. Suddenly,

a fresh water is injected and these shales that have always been salt water wet are

exposed to fresh water for the first time. The shales tend to absorb the water and in the

23

process swell. As a result of this swelling, the openings that slow fluid passage

(permeability) are reduced, and well bore damage is created.

Another type of water damage, is where the small droplets of water of invasion

cling to the formation. Due to the physical characteristic of water known as surface

tension, these water droplets can become semi-permanent and by themselves, will

reduce the natural openings in the formation and create well bore damage.

Drilling Solids Invasion Some formation will have natural openings large enough (high

permeability) to permit the entrance of the mud solids. The difference in pressure

between the drilling fluid hydrostatic pressure and formation pressure may be large

enough to wedge or pack these solids into the formation to such an extent that when the

pressure differential is reversed in favor of the well bore, the wedge will not break. As a

result of this phenomenon, the opening is closed to passage of fluid out of the formation

and well bore damage is created.

Bit Damage The mechanical chipping action of most rotary bits loosens the formation in

front of the bit, the circulating drilling fluid washes these chips away and hole is made.

Quite often, the bit chips away formation faster than the mud can carry them away. When

this occurs, the bit will continue to grind the pieces into still finer particles. These fine

particles may then be small enough to be forced back into the natural openings of the

formation, either by the pressure differential or more commonly, by the pounding effect of

the bit, and a wedge type of blockage may result as above.

The same pounding action of the bit can actually crush the matrix formation, so

that the natural openings are reduced in size. Either effect has the same end result in that

well bore damage is created.

Production Damage The very act necessary for the production of fluid from the formation,

a pressure drop - the driving force, can create conditions that induce a quasi-damage

situation. One type of production damage is gas blockage. The pressure drop created by

opening the test tool may be sufficient to cause gas to come out of solution within the

reservoir. (This is the same affect noticed in opening a warm "coke" bottle. No gas is

evident before the lid is removed, but as soon as the lid is removed, a pressure drop is

created, and gas comes out of the solution, causing the bottle to fizz up and run over).

24

The gas bubbles fill up and block the natural openings and well bore damage effect is

created.

EFFECTS

The end results of all these various forms of damage is to restrict rate of flow of

formation fluid to some degree below that which normally might be expected for the

existing reservoir and pressure drop conditions. At the present time, normal formation

test data analysis is not sufficient to determine the depth and type of the damage, but a

properly run test does generally supply sufficient data to determine the effect of the

damage on the production. Empirical equations have been developed to give a numerical

value to this damage effect, using the formation test data.

By being able to determine there is damage present, and the effect of this damage,

the well owner will be helped in his decision as to what to do with the well. By

supplementing the DST data and analysis with other core, well and electric log data, a

more complete and accurate evaluation of the formation may be made.

WHAT IS A GOOD TEST

The "perfect" Drill Stem Test satisfies all of several conditions. It must recover a

clean sample of formation fluid or gas (if present) in sufficient quantity to allow adequate

analysis. It must yield a good, clear pressure chart showing flow pressure corresponding

to actual flow information, is run in minimum length of time at minimum risk to personnel,

conditions, and shut-in pressure buildups of adequate length to get maximum information.

The perfect Drill Stem Test is obtaining this information is run in minimum length of time at

minimum risk to personnel, hole and equipment.

To obtain this perfect test, there must be complete cooperation and understanding

of purpose existing between the well owner and the testing service company.

DRILL STEM TESTING

GENERAL OPERATING PROCEDURES

The following are some general procedures that have been accepted as good

practice in field operations.

25

1. During the running of drill pipe in the well with a string of testing tools, the

fluid level in the well should be noted from time to time to check for leaks. A

blow of air from the drill pipe should be noticeable if a leak exists.

2. Before seating the packer, allow several minutes for the pressure recorder

to record a measurement of the initial hydrostatic mud pressure.

3. Install a rubber hose in the manifold before opening the tester valve. Insert

the end of the hose in bucket of water so an indication is seen of the rate of

fluid entering the drill pipe as the tester is opened.

4. Watch the mud level in the annulus before and after the tester opens, to

determine if the packer holds when the pressure differential is applied to it.

5. When opening the by-pass valve to equalize pressure, wait a few minutes to

permit the packer rubber to return to shape before pulling or jarring on it.

6. When pulling the drill pipe out of the well, keep the well filled. This should

be done by stopping and filling after pulling each stand or a few stand of

drill pipe. Running the pump continuously prevents immediate detection

if the well is being swabbed in.

SAFETY PROCEDURE FOR DRILL STEM TESTING

The safety of personnel, and control of the well is critical during and following a drill

stem test. Control of the well may be lost more easily during this time since reservoir fluid

and gases are surfaced with only mechanical control existing. Control of the well is

maximized only when the well is circulated and killed with the drilling fluid, and the test tool

removed. Safety regulations should be maintained by both the drilling contractor and the

service company. The following safety regulations may be used as a guide:

1. Follow all safety regulations of the drilling contractor, service company, and

the governmental control agencies.

2. Conduct an informal meeting to discuss safety and procedures prior to

running in the hole, especially on critical wells.

3. Check the blowout preventers and cellar connections.

4. Post "no smoking" signs at each of the stairways to the rig floor.

5. Check the mud system for well stability before the test tool is run in the hole.

26

6. Designate one man to observe the mud level during the test and while

coming out of the hole.

7. Start and pull tests in the daylight hours.

8. Turn off lights and electrical equipment during a test and while coming out of

the hole.

9. Avoid testing during electrical storms.

10. Service company should provide two methods of reversing-out, preferably

an on-bottom and an off-bottom device.

11. Reverse and kill all flowing or high recovery tests. Pull wet only those tests

that are obviously low recovery. This should be done with extreme caution

and awareness of gas pockets that may unload fluids during the process.

12. All personnel should wear full coverage of clothing at all times.

13. A hard hat and hard-toe or safety shoes should be worn at all times while on

locations.

14. The tester should instruct the driller on how to close the test tool in case

control of the well is in jeopardy. That is, pick up on the string to close most

hydraulic testers.

15. Maintain surface flowing pressure within the limits of safety predetermined

prior to the test.

16. Have adequate water spray connections on engine exhausts.

17. Flare all combustible gases to prevent an accumulation in low places.

18. All control head connections and flow lines should be steel rated above the

anticipated operating pressures.

19. Flow lines should be secured to the substructure and reserve pit.

20. BOP stack should be in good working order. The subsea test tree tubing

rams should be closed during the test with pressure on the tubing-casing

annulus.

HYDROGEN SULFIDE GAS

Personnel involved in drilling and testing wells containing hydrogen sulfide gas,

should be familiar with the characteristics, hazards, disposition and control of this gas.

27

Hydrogen sulfide is a colorless, heavier than air (specific gravity of 1.192), and

extremely toxic gas. At low concentrations, it has the smell of rotten eggs, while higher

concentration has a rapidly paralyzing effect on the olfactory nerve. For this reason

dangerous situations cannot always be detected by smell. H2S is almost as toxic as

hydrogen cyanide and is between five and six times as toxic as carbon monoxide. It is

also explosive when mixed with air between 5.9 and 27.2 percent by volume.

The principal personnel hazard is poisoning by inhalation. the following is an H2S

toxicity guide (Goolsby):

10 ppm - 0.0001% Can be detected by smell. Threshold limit, safe for 8 hours

exposure.

100 ppm - 0.01% Can kill sense of smell in 2 to 15 minutes. May sting eyes and throat.

200 ppm - 0.02% Can kill sense of smell in 60 seconds or less stings eyes and throat.

500 ppm - 0.05% Loses sense of reasoning and balance and respiratory paralysis in

30 to 45 minutes. Need prompt artificial respiration.

700 ppm - 0.07% Breathing will stop and death can result if not rescued promptly.

Immediate need for artificial respiration.

1,000 ppm - 0.10% Immediate unconsciousness. Apply immediate artificial respiration.

Permanent brain damage may result.

Since the sense of smell is not a reliable indication of H2S concentration, the use

of some approved type of gas detection equipment is suggested. A small portable H2S

monitor of the type which displays discoloration based on the gas concentration or a strip

detector which has basically the same principle may be successfully used to detect H2S

concentration. Approved breathing apparatus must be available for everyone on location,

at an easily accessible location.

A flare should be lighted on the flow line prior to opening the test tool. H2S burns

with a blue flame and produces sulfur dioxide (S02) gas which is very irritating to the eyes

and lungs and can cause serious injury. At the completion of the test, the hole should be

circulated until free of H2S gas. If it is planned not to produce the water cushion during

the test, a "scrubber" agent may be added to the cushion to neutralize the H2S gas that

may bubble through the cushion. Basically, a high PH solution, such as ammonium or

sodium hydroxide is the simplest method. Approximately 0.2 lb. of sodium hydroxide

(NaOH) will neutralize one cubic foot of H2S gas. Assume the produced gas is 30

28

percent H2S then 0.06 lb. of sodium hydroxide would be required per cubic foot.

However, produced salt water may precipitate magnesium or calcium hydroxide and

cause plugging of the tools.

Approximately 0.04 gal. of 30 percent aqua ammonia will neutralize one cubic foot

of H2S gas. Assuming the produced gas is 30 percent H2S, then 0.012 gal. of 30 percent

aqua ammonia would be required. Since the concentration or the rate of H2S that may

bubble through the cushion cannot be anticipated, most operators use one drum (55 gal.)

mixed in the water cushion. In most cases, this is more than adequate.

Some "scrubbing" action may be provided by a fresh water cushion, but chemical

scrubbers are suggested for maximum safety.

The contact time of the testing tools and drill pipe with a sour gas environment

should be held to a minimum. Hydrogen embrittlement is not only detrimental to the

metal, but poses a safety hazard to personnel through a mechanical failure. Atomic

hydrogen (H) generated in drilling fluids by corrosion processes, bacterial action, or

thermal degradation of organic additives, can be absorbed into and diffuse through the

steel crystal lattice. The atomic hydrogen migrates to and accumulates at the region of

highest stress crating an internal microcrack that grows until failure occurs. Hydrogen

sulfide cracking inhibitors may help protect the internal tool parts, connectors, and

especially the drill pipe pins. Many commercial inhibitors are available that may be

poured in the drill pipe and test tools, or painted on the connectors and tool joints. A

solution of 500 ppm (0.5 gal./1,000 gallons of fluid) is sufficient for most conditions. An

alternate procedure that may be safer is to spot mud containing the proper concentration

of aqua ammonia across the zone to be tested prior to coming out of the hole. This fluid

plus five gallons of aqua ammonia (30 percent) in the drain pipe will protect both the tools

and the pipe.

DRILL STEM TESTING FREES STUCK PIPE

Drill pipe and drill collars that are stuck by differential pressure can be released

with a drill stem testing tool.

What is Differential Sticking?

29

After a permeable, relatively low-pressure formation is penetrated by the drill string,

a pressure differential from the bore hole to the formation exists, resulting in a relatively

high flow of drilling fluid or filtrate into the formation. If the drill string (pipe or collars) is

allowed to rest against the wall of the hole in the permeable formation, pressure

differential will hold the pipe against the wall of the hole. Further loss of filtrate into the

formation will cause an accumulation of mud cake which acts as a pressure seal between

the pipe and bore hole wall and increases the effectiveness of the pressure differential. In

addition, the thick mud cake contributes to the mechanical sticking of the pipe.

The question of differential pressure sticking of drill pipe has been the subject of

much discussion by drillers, with some experienced drilling personnel even denying that

the problem exists. Although the phenomenon is difficult to confirm with actual

measurements, the theory is sound and field experience points to its validity.

Use of Drill Stem Test Tool

A Drill Stem Tester fishing string features use of a hydrospring tester valve above a

packer. When the packer is seated above the stuck pipe, tester valve is opened, creating

a pressure drop inside the bore hole which releases the stuck pipe.

DST FISHING ASSEMBLY

1. Hydrospring Tester Valve - prevents well fluid from entering the drill pipe when

running in or pulling out of the hole. This hydraulic valve includes a bypass valve which

operates by the same action that operated the tester valve. The bypass valve provides

fluid passage through the packer, in addition to that provided around the outside of the

packer when running in or pulling out the tools. The hydraulic time delay system in the

tool permits the tools to be run in with the assurance that the bypass will remain open and

the tester will remain closed. This system also allows the packer to be seated before the

bypass closes and the tester opens. At the conclusion of the testing operations, the tester

valve closes and the bypass opens immediately when weight is picked up. The hydraulic

time delay system is not effective on the return stroke. When the bypass opens, the

pressure is equalized across the packer which helps in unseating the packer.

30

2. Hydraulic Jars - To aid in release of the packer in case the attempt to free the pipe

should fail.

3. VR Safety Joint - A release joint ran above the packer to back-off of if packer

becomes stuck, also an additional bypass closes on down stroke and opens on

the up stroke.

4. Packer - Conventional open hole expanding shoe wall packer assembly consists

essentially of a telescoping mechanism, which includes a rubber wall packer for

sealing against the formation. The expanding shoe is a hard rubber sleeve used

below the softer rubber packer to help prevent the packer from extruding, due to

high temperatures and pressures.

5. Change Over Subs and Drill Collars - For spacing packer above stuck pipe for a

selected packer seat.

6. Bumper Jars - (Optional) Another set of jars to help free the pipe. The bumper

type jars used to jar up or down, also serve as a travel joint when screwing into the

fish or pipe with a guide type fishing sub.

7. Perforated Anchor Pipe - A perforated sub or perforated anchor pipe should be run

on all test attempting to free stuck pipe, regardless of whether this pipe is plugged.

The reason being that when the hydrospring tester valve opens and mud hydros-

tatic is released, causing a sweeping effect of the drilling mud, and releasing drilling

cuttings embedded in the mud filter cake that enters the drill bit nozzles bottom

hole assembly into the drill collars and possibly bridging or plugging the fish. This

creates more problems if the fish is plugged and does come free, making it

impossible to get a free point or string shot down through the drill collars. (Fish)

8. Safety Joint - (Optional) Several types.

9. Screw in Sub - With a guide on threaded pin (Make up shoulder tight to allow

operator to make a manual back off if DST fails to free stuck pipe).

31