EP1064452A1 - Formation testing apparatus and method - Google Patents

Abstract

An apparatus and method for obtaining samples of pristine formation or formation fluid, using a work string designed for performing other downhole work such as drilling, workover operations, or re-entry operations. An extendible element extends against the formation wall to obtain the pristine formation or fluid sample. While the test tool is in a standby condition, the extendible element is withdrawn within the work string, protected by other structure from damage during operation of the work string. The apparatus is used to sense or sample downhole conditions while using a work string, and the measurements or samples taken can be used to adjust working fluid properties without withdrawing the work string from the bore hole. When the extendible element is a packer, the apparatus can be used to prevent a kick from reaching the surface, adjust the density of the drilling fluid, and thereafter continuing use of the work string. The test apparatus can be mounted on a sliding, non-rotating, sleeve on the work string.

Description

1

FORMATION TESTING APPARATUS AND METHOD

BACKGROUND OF THE INVENTION

Field of the Invention - This invention relates to the testing of underground

formations or reservoirs. More particularly, this invention relates to a method and apparatus for isolating a downhole reservoir, and testing the reservoir formation and

fluid.

Background Information - While drilling a well for commercial development of

hydrocarbon reserves,, numerous subterranean reservoirs and formations will be encountered. In order to discover information about the formations, such as whether

the reservoirs contain hydrocarbons, logging devices have been incorporated into drill

strings to evaluate several characteristics of the these reservoirs. Measurement while

drilling systems (hereinafter MWD) have been developed which contain resistivity and

nuclear logging devices which can constantly monitor some of these characteristics while drilling is being performed. The MWD systems can generate data which includes

hydrocarbon presence, saturation levels, and porosity data. Moreover, telemetry

systems have been developed for use with the MWD systems, to transmit the data to

the surface. A common telemetry method is the mud-pulsed system, an example of

which is found in U. S. Patent 4,733,233. .An advantage of an MWD system is the real

time analysis of the subterranean reservoirs for further commercial exploitation.

Commercial development of hydrocarbon fields requires significant amounts of

capital. Before field development begins, operators desire to have as much data as

possible in order to evaluate the reservoir for commercial viability. Despite the

advances in data acquisition during drilling, using the MWD systems, it is often

necessary to conduct further testing of the hydrocarbon reservoirs in order to obtain 2 additional data. Therefore, after the well has been drilled, the hydrocarbon zones are

often tested by means of other test equipment.

One type of post-drilling test involves producing fluid from the reservoir,

collecting samples, shutting-in the well and allowing the pressure to build-up to a static

level. This sequence may be repeated several times at several different reservoirs

within a given well bore. This type of test is known as a Pressure Build-up Test. One

of the important aspects of the data collected during such a test is the pressure build¬

up information gathered after drawing the pressure down. From this data, information

can be derived as to permeability, and size of the reservoir. Further, actual samples of the reservoir fluid must be obtained, and these samples must be tested to gather

Pressure-Nolume-Temperature data relevant to the reservoir's hydrocarbon

distribution.

In order to perform these important tests, it is currently necessary to retrieve the drill string from the well bore. Thereafter, a different tool, designed for the testing,

is run into the well bore. A wireline is often used to lower the test tool into the well

bore. The test tool sometimes utilizes packers for isolating the reservoir. Numerous

communication devices have been designed which provide for manipulation of the test

assembly, or alternatively, provide for data transmission from the test assembly. Some of those designs include signaling from the surface of the Earth with pressure pulses,

through the fluid in the well bore, to or from a down hole microprocessor located

within, or associated with the test assembly. Alternatively, a wire line can be lowered

from the surface, into a landing receptacle located within a test assembly, establishing

electrical signal communication between the surface and the test assembly. Regardless

of the type of test equipment currently used, and regardless of the type of

communication system used, the amount of time and money required for retrieving the 3 drill string and running a second test rig into the hole is significant. Further, if the hole

is highly deviated, a wire line can not be used to perform the testing, because the test

tool may not enter the hole deep enough to reach the desired formation.

There is also another type of problem, related to down hole pressure

conditions, which can occur during drilling. The density of the drilling fluid is

calculated to achieve maximum drilling efficiency while maintaining safety, and the

density is dependent upon the desired relationship between the weight of the drilling

mud column and the downhole pressures which will be encountered. As different

formations are penetrated during drilling, the downhole pressures can change

significantly. With currently available equipment, there is no way to accurately sense

the formation pressure as the drill bit penetrates the formation. The formation pressure

could be lower than expected, allowing the lowering of mud density, or the formation

pressure could be higher than expected, possibly even resulting in a pressure kick.

Consequently, since this information is not easily available to the operator, the drilling

mud may be maintained at too high or too low a density for maximum efficiency and

maximum safety.

Therefore, there is a need for a method and apparatus that will allow for the

pressure testing and fluid sampling of potential hydrocarbon reservoirs as soon as the

bore hole has been drilled into the reservoir, without removal of the drill string.

Further, there is a need for a method and apparatus that will allow for adjusting drilling

fluid density in response to changes in downhole pressures, to achieve maximum

drilling efficiency. Finally, there is a need for a method and apparatus that will allow

for blow out prevention downhole, to promote drilling safety. 4

BRIEF SUMMARY OF THE INVENTION

A formation testing method and a test apparatus are disclosed. The test apparatus is mounted on a work string for use in a well bore filled with fluid. It can be

a work string designed for drilling, re-entry work, or workover applications. As

required for many of these applications, the work string may be one capable of going

into highly deviated holes, horizontally, or even uphill. Therefore, in order to be fully useful to accomplish the purposes of the present invention, the work string must be

one that is capable of being forced into the hole, rather than being dropped like a

wireline. The work string can contain a Measurement While Drilling system and a drill

bit, or other operative elements. The formation test apparatus may include at least one

expandable packer or other extendible structure that can expand or extend to contact the wall of the well bore; means for moving fluid, such as a pump, for taking in

formation fluid; a non-rotating sleeve; an extendible stabilizer blade; a coring device,

and at least one sensor for measuring a characteristic of the fluid. The test apparatus will also contain control means, for controlling the various valves or pumps which are

used to control fluid flow. The sensors and other instrumentation and control

equipment must be carried by the tool. The tool must have a communication system

capable of communicating with the surface, and data can be telemetered to the surface

or stored in a downhole memory for later retrieval.

The method involves drilling or re-entering a bore hole and selecting an

appropriate underground reservoir. The pressure, or some other characteristic of the

fluid in the well bore at the reservoir, the rock, or both, can then be measured. The

extendible element, such as a packer or test probe, is set against the wall of the bore

hole to isolate a portion of the bore hole or at least a portion of the bore hole wall. In 5 the non-rotatable sleeve embodiment, the drill string can continue rotating and advancing while the sleeve is held stationary during performance of the test

If two packers are used, this will create an upper annulus, a lower annulus, and

an intermediate annulus within the well bore The intermediate annulus corresponds to

the isolated portion of the bore hole, and it is positioned at the reservoir to be tested Next, the pressure, or other property, within the intermediate annulus is measured

The well bore fluid, primarily drilling mud, may then be withdrawn from the

intermediate annulus with the pump The level at which pressure within the

intermediate annulus stabilizes may then be measured, it will correspond to the formation pressure Pressure can also be applied to fracture the formation, or to

perform a pressure test of the formation Additional extendible elements may also be

provided, to isolate two or more permeable zones This allows the pumping of fluid

from one or more zones to one or more other zones

Alternatively, a piston or other test probe can be extended from the test apparatus to contact the bore hole wall in a sealing relationship, or some other

expandable element can be extended to create a zone from which essentially pristine

formation fluid can be withdrawn This could also be accomplished by extending a

locating arm or stabilizer rib from one side of the test tool, to force the opposite side of

the test tool to contact the bore hole wall, thereby exposing a sample port to the formation fluid Regardless of the apparatus used, the goal is to establish a zone of

pristine formation fluid from which a fluid or core sample can be taken, or in which

characteristics of the fluid can be measured This can be accomplished by various

means The example first mentioned above is to use inflatable packers to isolate a portion of the entire bore hole, subsequently withdrawing drilling fluid from the

isolated portion until it fills with formation fluid The other examples given accomplish 6 the goal by expanding an element against a spot on the bore hole wall, thereby directly contacting the formation and excluding drilling fluid.

Regardless of the apparatus used, it must be constructed so as to be protected

during performance of the primary operations for which the work string is intended, such as drilling, re-entry, or workover. If an extendible probe is used, it can retract

within the tool, or it can be protected by adjacent stabilizers, or both. A packer or

other extendible elastomeric element can retract within a recession in the tool, or it can

be protected by a sleeve or some other type of cover.

In addition to the pressure sensor mentioned above, the formation test

apparatus can contain a resistivity sensor for measuring the resistivity of the well bore

fluid and the formation fluid, or other types of sensors. The resistivity of the drilling

fluid will be noticeably different from the resistivity of the formation fluid. If two packers are used, the resistivity of fluid being pumped from the intermediate annulus

can be monitored to determine when all of the drilling fluid has been withdrawn from

the intermediate annulus. As flow is induced from the isolated formation into the

intermediate annulus, the resistivity of the fluid being pumped from the intermediate

annulus is monitored. Once the resistivity of the exiting fluid differs sufficiently from

the resistivity of the well bore fluid, it is assumed that formation fluid has filled the

intermediate annulus, and the flow is terminated. This can also be used to verify a

proper seal of the packers, since leaking of drilling fluid past the packers would tend to

maintain the resistivity at the level of the drilling fluid. Other types of sensors which

can be incorporated are flow rate measuring devices, viscosity sensors, density

measuring devices, dielectric property measuring devices, and optical spectroscopes.

After shutting in the formation, the pressure in the intermediate annulus can be

monitored. Pumping can also be resumed, to withdraw formation fluid from the 7 intermediate annulus at a measured rate. Pumping of formation fluid and measurement

of pressure can be sequenced as desired to provide data which can be used to calculate various properties of the formation, such as permeability and size. If direct contact with the bore hole wall is used, rather than isolating a section of the bore hole, similar

tests can be performed by incorporating test chambers within the test apparatus. The

test chambers can be maintained at atmospheric pressure while the work string is being

drilled or lowered into the bore hole. Then, when the extendible element has been

placed in contact with the formation, exposing a test port to the formation fluid, a test chamber can be selectively placed in fluid communication with the test port. Since the

formation fluid will be at much higher pressure than atmospheric, the formation fluid

will flow into the test chamber. In this way, several test chambers can be used to

perform different pressure tests or take fluid samples.

In some embodiments which use expandable packers, the formation test

apparatus has contained therein a drilling fluid return flow passageway for allowing

return flow of the drilling fluid from the lower annulus to the upper annulus. .Also

included is at least one pump, which can be a Venturi pump or any other suitable type of pump, for preventing overpressurization in an intermediate annulus.

Overpressurization can be undesirable because of the possible loss of the packer seal,

or because it can hamper operation of extendible elements which may be operated by

differential pressure between the inner bore of the work string and the annulus, or by a

fluid pump. To prevent overpressurization, the drilling fluid is pumped down the

longitudinal inner bore of the work string, past the lower end of the work string (which

is generally the bit), and up the annulus. Then the fluid is channeled through return

flow passageway and the Venturi pump, creating a low pressure zone at the Venturi, 8 so that the fluid within the intermediate annulus is held at a lower pressure than the fluid in the return flow passageway.

The device may also include a circulation valve, for opening and closing the

inner bore of the work string. A shunt valve can be located in the work string and

operatively associated with the circulation valve, for allowing flow from the inner bore

of the work string to the annulus around the work string, when the circulation valve is closed. These valves can be used in operating the test apparatus as a down hole blow¬

out preventor.

In the case where an influx of reservoir fluids invade the bore hole, which is

sometimes referred to as a "kick", the method includes the steps of setting the expandable packers, and then positioning the circulating valve in the closed position.

The packers are set at a position that is above the influx zone so that the influx zone is

isolated. Next, the shunt valve is placed in the open position. Additives can then be

added to the drilling fluid, thereby increasing the density of the mud. The heavier mud

is circulated down the work string, through the shunt valve, to fill the annulus. Once the circulation of the denser drilling fluid is completed, the packers can be unseated

and the circulation valve can be opened. Drilling may then resume.

An advantage of the present invention includes use of the pressure and

resistivity sensors with the MWD system, to allow for real time data transmission of

those measurements. Mother advantage is that the present invention allows obtaining

static pressures, pressure build-ups, and pressure draw-downs with the work string,

such as a drill string, in place. Computation of permeability and other reservoir

parameters based on the pressure measurements can be accomplished without pulling

the drill string. 9

The packers can be set multiple times, so that testing of several zones is

possible. By making measurement of the down hole conditions possible in real time,

optimum drilling fluid conditions can be determined which will aid in hole cleaning,

drilling safety, and drilling speed. When an influx of reservoir fluid and gas enter the

well bore, the high pressure is contained within the lower part of the well bore, significantly reducing risk of being exposed to these pressures at surface. Also, by

shutting-in the well bore immediately above the critical zone, the volume of the influx

into the well bore is significantly reduced.

The novel features of this invention, as well as the invention itself, will be best

understood from the attached drawings, taken along with the following description, in

which similar reference characters refer to similar parts, and in which:

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS Figure 1 is a partial section view of the apparatus of the present invention as it

would be used with a floating drilling rig;

Figure 2 is a perspective view of one embodiment of the present invention,

incorporating expandable packers;

Figure 3 is a section view of the embodiment of the present invention shown in

Figure 2;

Figure 4 is a section view of the embodiment shown in Figure 3, with the

addition of a sample chamber;

Figure 5 is a section view of the embodiment shown in Figure 3, illustrating the flow path of drilling fluid; 10

Figure 6 is a section view of a circulation valve and a shunt valve which can be

incorporated into the embodiment shown in Figure 3;

Figure 7 is a section view of another embodiment of the present invention, showing the use of a centrifugal pump to drain the intermediate annulus;

Figure 8 is a schematic of the control system and the communication system

which can be used in the present invention;

Figure 9 is a partial section view of the apparatus of the present invention,

showing more than two extendible elements;

Figure 10 is a section view of the apparatus of the present invention, showing

one embodiment of a coring device;

Figure 11 is a perspective view of the apparatus of the present invention

utilizing a non-rotating sleeve; and

Figure 12 is a section view of the embodiment shown in Figure 11.

DETAILED DESCRIPTION OF THE INVENTION

Referring to Fig. 1, a typical drilling rig 2 with a well bore 4 extending

therefrom is illustrated, as is well understood by those of ordinary skill in the art. The drilling rig 2 has a work string 6, which in the embodiment shown is a drill string. The

work string 6 has attached thereto a drill bit 8 for drilling the well bore 4. The present

invention is also useful in other types of work strings, and it is useful with jointed

tubing as well as coiled tubing or other small diameter work string such as snubbing

pipe. Figure 1 depicts the drilling rig 2 positioned on a drill ship S with a riser extending from the drilling ship S to the sea floor F.

If applicable, the work string 6 can have a downhole drill motor 10.

Incorporated in the drill string 6 above the drill bit 8 is a mud pulse telemetry system 11

12, which can incorporate at least one sensor 14, such as a nuclear logging instrument.

The sensors 14 sense down hole characteristics of the well bore, the bit, and the reservoir, with such sensors being well known in the art. The bottom hole assembly

also contains the formation test apparatus 16 of the present invention, which will be

described in greater detail hereinafter. As can be seen, one or more subterranean

reservoirs 18 are intersected by the well bore 4.

Figure 2 shows one embodiment of the formation test apparatus 16 in a

perspective view, with the expandable packers 24, 26 withdrawn into recesses in the

body of the tool. Stabilizer ribs 20 are also shown between the packers 24, 26,

arranged around the circumference of the tool, and extending radially outwardly. Also

shown are the inlet ports to several drilling fluid return flow passageways 36 and a draw down passageway 41 to be described in more detail below.

Referring now to Fig. 3, one embodiment of the formation test apparatus 16 is

shown positioned adjacent the reservoir 18. The test apparatus 16 contains an upper

expandable packer 24 and a lower expandable packer 26 for sealingly engaging the

wall of the well bore 4. The packers 24, 26 can be expandable by any means known in

the art. Inflatable packer means are well known in the art, with inflation being

accomplished by means of injecting a pressurized fluid into the packer. Optional

covers for the expandable packer elements may also be included to shield the packer

elements from the damaging effects of rotation in the well bore, collision with the wall

of the well bore, and other forces encountered during drilling, or other work

performed by the work string.

A high pressure drilling fluid passageway 27 is formed between the longitudinal

internal bore 7 and an expansion element control valve 30. An inflation fluid

passageway 28 conducts fluid from a first port of the control valve 30 to the packers 12

24, 26. The inflation fluid passageway 28 branches off into a first branch 28 A that is connected to the inflatable packer 26 and a second branch 28B that is connected to the

inflatable packer 24. A second port of the control valve 30 is connected to a drive

fluid passageway 29, which leads to a cylinder 35 formed within the body of the test

tool 16. A third port of the control valve 30 is connected to a low pressure passageway 31, which leads to one of the return flow passageways 36. Alternatively,

the low pressure passageway 31 could lead to a Venturi pump 38 or to a centrifugal

pump 53 which will be discussed further below. The control valve 30 and the other

control elements to be discussed are operable by a downhole electronic control system 100 seen in Fig. 8, which will be discussed in greater detail hereinafter.

It can be seen that the control valve 30 can be selectively positioned to pressurize the cylinder 35 or the packers 24, 26 with high pressure drilling fluid

flowing in the longitudinal bore 7. This can cause the piston 45 or the packers 24, 26

to extend into contact with the wall of the bore hole 4. Once this extension has been

achieved, repositioning the control valve 30 can lock the extended element in place. It

can also be seen that the control valve 30 can be selectively positioned to place the

cylinder 35 or the packers 24, 26 in fluid communication with a passageway of lower

pressure, such as the return flow passageway 36. If spring return means are utilized in

the cylinder 35 or the packers 24, 26, as is well known in the art, the piston 45 will

retract into the cylinder 35, and the packers 24, 26 will retract within their respective

recesses. Alternatively, as will be explained below in the discussion of Fig. 7, the low

pressure passageway 31 can be connected to a suction means, such as a pump, to draw

the piston 45 within the cylinder 35, or to draw the packers 24, 26 into their recesses.

Once the inflatable packers 24, 26 have been inflated, an upper annulus 32, an

intermediate annulus 33, and a lower annulus 34 are formed. This can be more clearly 13 seen in Fig. 5. The inflated packers 24, 26 isolate a portion of the well bore 4 adjacent

the reservoir 18 which is to be tested. Once the packers 24, 26 are set against the wall

of the well bore 4, an accurate volume within the intermediate annulus 33 may be calculated, which is useful in pressure testing techniques.

The test apparatus 16 also contains at least one fluid sensor system 46 for

sensing properties of the various fluids to be encountered. The sensor system 46 can

include a resistivity sensor for determining the resistivity of the fluid. Also, a dielectric

sensor for sensing the dielectric properties of the fluid, and a pressure sensor for sensing the fluid pressure may be included. Other types of sensors which can be

incorporated are flow rate measuring devices, viscosity sensors, density measuring

devices, and optical spectroscopes. A series of passageways 40 A, 40B, 40C, and 40D

are also provided for accomplishing various objectives, such as drawing a pristine formation fluid sample through the piston 45, conducting the fluid to a sensor 46, and

returning the fluid to the return flow passageway 36. A sample fluid passageway 40A

passes through the piston 45 from its outer face 47 to a side port 49. A sealing

element can be provided on the outer face 47 of the piston 45 to ensure that the sample

obtained is pristine formation fluid. This in effect isolates a portion of the well bore

from the drilling fluid or any other contaminants or pressure sources.

When the piston 45 is extended from the tool, the piston side port 49 can align

with a side port 51 in the cylinder 35. A pump inlet passageway 40B connects the

cylinder side port 51 to the inlet of a pump 53. The pump 53 can be a centrifugal

pump driven by a turbine wheel 55 or by another suitable drive device. The turbine

wheel 55 can be driven by flow through a bypass passageway 84 between the longitudinal bore 7 and the return flow passageway 36. .Alternatively, the pump 53 can

be any other type of suitable pump. A pump outlet passageway 40C is connected 14 between the outlet of the pump 53 and the sensor system 46. A sample fluid return

passageway 40D is connected between the sensor 46 and the return flow passageway 36. The passageway 40D has therein a valve 48 for opening and closing the

passageway 40D. As seen in Figure 4, there can be a sample collection passageway 40E which

connects the passageways 40A, 40B, 40C, and 40D with the lower sample module,

seen generally at 52. The passageway 40E leads to the adjustable choke means 74 and to the sample chamber 56, for collecting a sample. The sample collection passageway

40E has therein a chamber inlet valve 58 for opening and closing the entry into the

sample chamber 56. The sample chamber 56 can have a movable baffle 72 for

separating the sample fluid from a compressible fluid such as air, to facilitate drawing

the sample as will be discussed below. An outlet passage from the sample chamber 56 is also provided, with a chamber outlet valve 62 therein, which can be a manual valve.

.Also, there is provided a sample expulsion valve 60, which can be a manual valve. The

passageways from valves 60 and 62 are connected to external ports (not shown) on the

tool. The valves 62 and 60 allow for the removal of the sample fluid once the work

string 6 has been pulled from the well bore, as will be discussed below. .Alternatively,

the sample chamber 56 can be made wireline retrievable, by means well known in the

art. When the packers 24, 26 are inflated, they will seal against the wall of the well

bore 4, and as they continue to expand to a firm set, the packers 24, 26 will expand

slightly into the intermediate annulus 33. If fluid is trapped within the intermediate

annulus 33, this expansion can tend to increase the pressure in the intermediate annulus

33 to a level above the pressure in the lower annulus 34 and the upper annulus 32. For

operation of extendible elements such as the piston 45, it is desired to have the 15 pressure in the longitudinal bore 7 of the drill string 6 higher than the pressure in the

intermediate annulus 33. Therefore, a Venturi pump 38 is used to prevent overpressurization of the intermediate annulus 33.

The drill string 6 contains several drilling fluid return flow passageways 36 for

allowing return flow of the drilling fluid from the lower annulus 34 to the upper

annulus 32, when the packers 24, 26 are expanded. A Venturi pump 38 is provided

within at least one of the return flow passageways 36, and its structure is designed for creating a zone of lower pressure, which can be used to prevent overpressurization in

the intermediate annulus 33, via the draw down passageway 41 and the draw down control valve 42. Similarly, the Venturi pump 38 could be connected to the low

pressure passageway 31, so that the low pressure zone created by the Venturi pump 38

could be used to withdraw the piston 45 or the packers 24, 26. .Alternatively, as

explained below in the discussion of Fig. 7, another type of pump could be used for

this purpose.

Several return flow passageways can be provided, as shown in Fig. 2. One return flow passageway 36 is used to operate the Venturi pump 38. As seen in Fig. 3

and Fig. 4, the return flow passageway 36 has a generally constant internal diameter

until the Venturi restriction 70 is encountered. As shown in Fig. 5, the drilling fluid is

pumped down the longitudinal bore 7 of the work string 6, to exit near the lower end

of the drill string at the drill bit 8, and to return up the annular space as denoted by the

flow arrows. Assuming that the inflatable packers 24, 26 have been set and a seal has

been achieved against the well bore 4, then the annular flow will be diverted through

the return flow passageways 36. As the flow approaches the Venturi restriction 70, a

pressure drop occurs such that the Venturi effect will cause a low pressure zone in the

Venturi. This low pressure zone communicates with the intermediate annulus 33 16 through the draw down passageway 41, preventing any overpressurization of the intermediate annulus 33.

The return flow passageway 36 also contains an inlet valve 39 and an outlet

valve 80, for opening and closing the return flow passageway 36, so that the upper

annulus 32 can be isolated from the lower annulus 34. The bypass passageway 84

connects the longitudinal bore 7 of the work string 6 to the return flow passageway 36.

Referring now to Fig. 6, yet another possible feature of the present invention is

shown, wherein the work string 6 has installed therein a circulation valve 90, for

opening and closing the inner bore 7 of the work string 6. .Also included is a shunt

valve 92, located in the shunt passageway 94, for allowing flow from the inner bore 7 of the work string 6 to the upper annulus 32. The remainder of the formation tester is

the same as previously described.

The circulation valve 90 and the shunt valve 92 are operatively associated with

the control system 100. In order to operate the circulation valve 90, a mud pulse

signal is transmitted down hole, thereby signaling the control system 100 to shift the

position of the valve 90. The same sequence would be necessary in order to operate

the shunt valve 92.

Figure 7 illustrates an alternative means of performing the functions performed

by the Venturi pump 38. The centrifugal pump 53 can have its inlet connected to the

draw down passageway 41 and to the low pressure passageway 31. A draw down

valve 57 and a sample inlet valve 59 are provided in the pump inlet passageway to the

intermediate annulus and the piston, respectively. The pump inlet passageway is also

connected to the low pressure side of the control valve 30. This allows use of the

pump 53, or another similar pump, to withdraw fluid from the intermediate annulus 33 17 through valve 57, to withdraw a sample of formation fluid directly from the formation through valve 59, or to pump down the cylinder 35 or the packers 24, 26.

Figure 7 also shows a means of applying fluid pressure to the formation, either

via the intermediate annulus 33 or via the sample inlet valve 59. The purpose of

applying this fluid pressure may be either to fracture the formation, or to perform a

pressure test of the formation. A pump inlet valve 120 and a pump outlet valve 122

are provided in the inlet and outlet, respectively, of the pump 53. The pump inlet valve

120 can be positioned as shown to align the pump inlet with the low pressure

passageway 31 as required for the operations described above. Alternatively, the

pump inlet valve 120 can be rotated clockwise a quarter turn by the control system 100

to align the pump inlet with the return flow passageway 36. Similarly, the pump outlet valve 122 can be positioned as shown to align the pump outlet with the return flow

passageway 36 as required for the operations described above. Alternatively, the

pump outlet valve 122 can be rotated clockwise a quarter turn by the control system

100 to align the pump outlet with the low pressure passageway 31. With the pump

inlet valve 120 aligned to connect the pump inlet with the return flow passageway 36 and the pump outlet valve 122 aligned to connect the pump outlet with the low

pressure passageway 31, the pump 53 can be operated to draw fluid from the return

flow passageway 36 to pressurize the formation via the low pressure passageway 31.

Pressurization of the formation can be through the extendible piston 45, with the

sample inlet valve 59 open and the draw down valve 57 shut. Alternatively, pressurization of the formation can be through the annulus 33, with the sample inlet

valve 59 shut and the draw down valve 57 open.

As depicted in Fig. 8, the invention includes use of a control system 100 for

controlling the various valves and pumps, and for receiving the output of the sensor 18 system 46. The control system 100 is capable of processing the sensor information

with the downhole microprocessor/controller 102, and delivering the data to the

communications interface 104, so that the processed data can then be telemetered to

the surface using conventional technology. It should be noted that various forms of transmission energy could be used such as mud pulse, acoustical, optical, or electro¬

magnetic. The communications interface 104 can be powered by a downhole electrical

power source 106. The power source 106 also powers the flow line sensor system 46,

the microprocessor/controller 102, and the various valves and pumps.

Communication with the surface of the Earth can be effected via the work string 6 in the form of pressure pulses or other means, as is well known in the art. In

the case of mud pulse generation, the pressure pulse will be received at the surface via

the 2-way communication interface 108. The data thus received will be delivered to

the surface computer 110 for interpretation and display.

Command signals may be sent down the fluid column by the communications

interface 108, to be received by the downhole communications interface 104. The

signals so received are delivered to the downhole microprocessor/controller 102. The

controller 102 will then signal the appropriate valves and pumps for operation as

desired.

The down hole microprocessor/controller 102 can also contain a pre-

programmed sequence of steps based on pre-deter ined criteria. Therefore, as the

down hole data, such as pressure, resistivity, flow rate, viscosity, density, spectral

analysis or other data from an optical sensor, or dielectric constants, are received, the

microprocessor/controller would automatically send command signals via the control

means to manipulate the various valves and pumps. 19

As shown in Figure 9, it can be useful to have two or more sets of extendible packers, with associated test apparatus 16 therebetween. One set of packers can

isolate a first formation, while another set of packers can isolate a second formation.

The apparatus can then be used to pump formation fluid from the first formation into

the second formation. This function can be performed either from one annulus 33 at the first formation to another annulus 33 at the second formation, using the extended

packers for isolation of the formations. Alternatively, this function can be performed

via sample fluid passageways 40 A in the two sets of test apparatus 16, using the

extended pistons 45 for isolation of the formations. For instance, referring again to

Figure 7, in the first set of test apparatus 16, the sample inlet valve 59 can be closed and the draw down valve 57 opened. With the pump inlet and outlet valves 120, 122

aligned as shown in Figure 7, the pump 53 can be operated to pump formation fluid

from the annulus 33 at the first formation into the return flow passageway 36. The

return flow passageway 36 can extend through the work string 6 to the second set of test apparatus 16 at the second formation. There, the second sample inlet valve 59 can

be closed and the second draw down valve 57 can be opened, just as in the first set of

test apparatus 16. However, in the second set of test apparatus 16, the pump inlet and

outlet valves 120, 122 can be rotated clockwise a quarter turn to allow the second

pump 53 to pump the first formation fluid from the return flow passageway 36 into the

second formation via the second draw down valve 57 and via the annulus 33.

Variations of this process can be used to pump formation fluid from one or more

formations into one or more other formations. At the lower end of the work string 6,

it may only be necessary to have a single extendible packer for isolating the lower

annulus. 20

As shown in Figure 10, it can also be useful to incorporate a formation coring device 124 into the test apparatus 16 of the present invention. The coring device 124 can be extended into the formation by equipment identical to the equipment described

above for extending the piston 45. The coring device 124 can be rotated by a turbine

126 which is activated by drilling fluid via the central bore 7 and a turbine inlet port

128. The outlet of the turbine 126 can be via an outlet passageway 130 and a turbine

control valve 132, which is controlled by the control system 100. With the packers 24,

26 extended, the coring device 124 is extended and rotated to obtain a pristine core

sample of the formation. The core sample can then be withdrawn into the work string

6, where some chemical analysis can be performed if desired, and the core sample can

be preserved in its pristine state, including pristine formation fluid, for extraction upon

return of the test apparatus 16 to the surface.

As shown in Figure 11, the apparatus of the present invention can be modified

by the use of a sliding, non-rotating, sleeve 200 to allow testing to take place while

drilling or other rotation of the drill string continues. .An extendible stabilizer blade

216 can be located on the side of the test tool opposite the test port, for the purpose of

pushing the test port against the bore hole wall, if no piston is used, or for centering of

the test tool in the bore hole. Upper stabilizers 220 and lower stabilizers 222 can be

added on the work string 6 to separately stabilize the rotating portion of the work

string.

Figure 12 is a longitudinal section view of the embodiment of the test apparatus

16 having a sliding, non-rotating, sleeve 200. The cylindrical non-rotating sleeve 200

is set into a recess in the outer surface of the work string 6. The space between the

non-rotating sleeve 200 and the work string is sealed by upper rotating seals 202 and

lower rotating seals 204. A plurality of other rotating seals 206, 208, 210, 212, 214 21 can be used to seal fluid passageways which lead from the inner bore 7 of the work

string 6 to the test apparatus 16, depending upon the particular configuration of the test apparatus used. The non-rotating sleeve 200 is shorter than the recess into which

it is set, to allow the work string 6 to move axially relative to the stationary sleeve 200, as the work string 6 advances during drilling. A spring 223 is provided between the

upper end of the sleeve 200 and the upper end of the recess, to bias the sleeve 200

downwardly relative to the work string 6.

One or more extendible stabilizer blades or ribs 216 can be provided on the

non-rotating sleeve 200, on the side opposite the test piston 45 or the test port rib 20.

A remotely operated rib extension valve 218 can be provided in a passageway 219

leading from the work string bore 7 to an expansion chamber 221 in which the

extendible rib 216 is located. Opening of the rib extension valve 218 introduces

pressurized drilling fluid into the expansion chamber 221, thereby hydraulically forcing

the extendible rib 216 to move outwardly to contact the bore hole wall. Abutting

shoulders or other limiting devices known in the art (not shown) can be provided on

the extendible rib 216 and the non-rotating sleeve 200, to limit the travel of the

extendible rib 216. Further, a spring or other biasing element known in the art (not

shown) can be provided to return the extendible rib 216 to its stored position upon

release of the hydraulic pressure.

OPERATION

In operation, the formation tester 16 is positioned adjacent a selected formation

or reservoir. Next, a hydrostatic pressure is measured utilizing the pressure sensor

located within the sensor system 46, as well as determining the drilling fluid resistivity

at the formation. This is achieved by pumping fluid into the sample system 46, and 22 then stopping to measure the pressure and resistivity The data is processed down hole and then stored or transmitted up-hole using the MWD telemetry system

Next, the operator expands and sets the inflatable packers 24, 26 This is done

by maintaining the work string 6 stationary and circulating the drilling fluid down the

inner bore 7, through the drill bit 8 and up the annulus The valves 39 and 80 are

open, and therefore, the return flow passageway 36 is open The control valve 30 is positioned to align the high pressure passageway 27 with the inflation fluid

passageways 28A, 28B, and drilling fluid is allowed to flow into the packers 24, 26

Because of the pressure drop from inside the inner bore 7 to the annulus across the

drill bit 8, there is a significant pressure differential to expand the packers 24, 26 and

provide a good seal The higher the flow rate of the drilling fluid, the higher the pressure drop, and the higher the expansion force applied to the packers 24, 26 In the

non-rotating sleeve embodiment, extension of the packers 24, 26 can be used to stop

and prevent rotation of the test apparatus 16 When the packers 24, 26 are retracted,

the sleeve 200 rests on the lower end of the recess in the work string 6 The packers

24, 26 are activated by a hydraulic system controlled by the downhole electronics As

the work string 6 advances during drilling, the sleeve 200 remains stationary relative to

the bore hole, compressing the spring 223 Thus, the sleeve 200 is essentially

decoupled from the movement of the work string 6, enabling formation test

measurements to be carried out, without being influenced by the movement of the

work string 6 Therefore, there is no requirement to interrupt the drilling process

Once the formation test is complete, the packers 24, 26 are retracted The spring 223,

or other biasing device known in the art, then pushes the sleeve 200 against the lower

end of the recess in the work string 6 As an alternative to extension of packers, or in

addition thereto, another expandable element such as the piston 45 can be extended to 23 contact the wall of the well bore, by appropriate positioning of the control valve 30. If

no packers are extended, the extendible rib 216 alone can be used to hold the non- rotating sleeve 200 stationary.

The upper packer element 24 can be wider than the lower packer 26, thereby

containing more volume. Thus, the lower packer 26 will set first. This can prevent

debris from being trapped between the packers 24, 26.

The Venturi pump 38 can then be used to prevent overpressurization in the

intermediate annulus 33, or the centrifugal pump 53 can be operated to remove the

drilling fluid from the intermediate annulus 33. This is achieved by opening the draw

down valve 41 in the embodiment shown in Fig. 3, or by opening the valves 82, 57, and 48 in the embodiment shown in Fig. 7.

If the fluid is pumped from the intermediate annulus 33, the resistivity and the dielectric constant of the fluid being drained can be constantly monitored by the sensor

system 46. The data so measured can be processed down hole and transmitted up-hole

via the telemetry system. The resistivity and dielectric constant of the fluid passing

through will change from that of drilling fluid to that of drilling fluid filtrate, to that of

the pristine formation fluid.

In order to perform the formation pressure build-up and draw down tests, the

operator closes the pump inlet valve 57 and the by-pass valve 82. This stops drainage

of the intermediate annulus 33 and immediately allows the pressure to build-up to

virgin formation pressure. The operator may choose to continue circulation in order to

telemeter the pressure results up-hole.

In order to take a sample of formation fluid, the operator could open the

chamber inlet valve 58 so that the fluid in the passageway 40E is allowed to enter the

sample chamber 56. The sample chamber may be empty or filled with some 24 compressible fluid. If the sample chamber 56 is empty and at atmospheric conditions,

the baffle 72 will be urged downward until the chamber 56 is filled. An adjustable

choke 74 is included for regulating the flow into the chamber 56. The purpose of the

adjustable choke 74 is to control the change in pressure across the packers when the sample chamber is opened. If the choke 74 were not present, the packer seal might be

lost due to the sudden change in pressure created by opening the sample chamber inlet

valve 58. Another purpose of the choke 74 would be to control the process of flowing

the fluid into the system, to prevent the pressure from being lowered below the fluid bubble point, thereby preventing gas from evaporating from the fluid.

Once the sample chamber 56 is filled, then the valve 58 can again be closed,

allowing for another pressure build-up, which is monitored by the pressure sensor. If

desired, multiple pressure build-up tests can be performed by repeatedly pumping down the intermediate annulus 33, or by repeatedly filling additional sample chambers.

Formation permeability may be calculated by later analyzing the pressure versus time

data, such as by a Horner Plot which is well known in the art. Of course, in

accordance with the teachings of the present invention, the data may be analyzed

before the packers 24 and 26 are deflated. The sample chamber 56 could be used in

order to obtain a fixed, controlled drawn down volume. The volume of fluid drawn

may also be obtained from a down hole turbine meter placed in the appropriate

passageway.

Once the operator is prepared to either drill ahead, or alternatively, to test

another reservoir, the packers 24, 26 can be deflated and withdrawn, thereby returning

the test apparatus 16 to a standby mode. If used, the piston 45 can be withdrawn. The

packers 24, 26 can be deflated by positioning the control valve 30 to align the low

pressure passageway 31 with the inflation passageway 28. The piston 45 can be 25 withdrawn by positioning the control valve 30 to align the low pressure passageway 31 with the cylinder passageway 29. However, in order to totally empty the packers or the cylinder, the Venturi pump 38 or the centrifugal pump 53 can be used.

Once at the surface, the sample chamber 56 can be separated from the work

string 6. In order to drain the sample chamber, a container for holding the sample

(which is still at formation pressure) is attached to the outlet of the chamber outlet

valve 62. A source of compressed air is attached to the expulsion valve 60. Upon

opening the outlet valve 62, the internal pressure is released, but the sample is still in

the sample chamber. The compressed air attached to the expulsion valve 60 pushes the

baffle 72 toward the outlet valve 62, forcing the sample out of the sample chamber 56.

The sample chamber may be cleaned by refilling with water or solvent through the outlet valve 62, and cycling the baffle 72 with compressed air via the expulsion valve

60. The fluid can then be analyzed for hydrocarbon number distribution, bubble point

pressure, or other properties. .Alternatively, a sensor package can be associated with

the sample chamber 56, so that the same measurements can be performed on the fluid

sample while it is still downhole. Then, the sample may be discharged downhole.

Once the operator decides to adjust the drilling fluid density, the method

comprises the steps of measuring the hydrostatic pressure of the well bore at the target

formation. Then, the packers 24, 26 are set so that an upper 32, a lower 34, and an

intermediate annulus 33 are formed within the well bore. Next, the well bore fluid is

withdrawn from the intermediate annulus 33 as has been previously described and the

pressure of the formation is measured within the intermediate annulus 32. The other

embodiments of extendible elements may also be used to determine formation pressure.

The method further includes the steps of adjusting the density of the drilling

fluid according to the pressure readings of the formation so that the mud weight of the 26 drilling fluid closely matches the pressure gradient of the formation. This allows for

maximum drilling efficiency. Next, the inflatable packers 24, 26 are deflated as has been previously explained and drilling is resumed with the optimum density drilling

fluid. The operator would continue drilling to a second subterranean horizon, and at

the appropriate horizon, would then take another hydrostatic pressure measurement,

thereafter inflating the packers 24, 26 and draining the intermediate annulus 33, as

previously set out. According to the pressure measurement, the density of the drilling

fluid may be adjusted again and the inflatable packers 24, 26 are unseated and the

drilling of the bore hole may resume at the correct overbalance weight.

The invention herein described can also be used as a near bit blow-out

preventor. If an underground blow-out were to occur, the operator would set the inflatable packers 24, 26, and have the valve 39 in the closed position, and begin

circulating the drilling fluid down the work string through the open valves 80 and 82.

Note that in a blowout prevention application, the pressure in the lower annulus 34

may be monitored by opening valves 39 and 48 and closing valves 57, 59, 30, 82, and

80. The pressure in the upper annulus may be monitored while circulating directly to

the annulus through the bypass valve by opening valve 48. Also the pressure in the

internal diameter 7 of the drill string may be monitored during normal drilling by

closing both the inlet valve 39 and outlet valve 80 in the passageway 36, and opening

the by-pass valve 82, with all other valves closed. Finally, the by-pass passageway 84 would allow the operator to circulate heavier density fluid in order to control the kick.

Alternatively, if the embodiment shown in Fig. 6 is used, the operator would

set the first and second inflatable packers 24, 26 and then position the circulation valve

90 in the closed position. The inflatable packers 24, 26 are set at a position that is 27 above the influx zone so that the influx zone is isolated. The shunt valve 92 contained

on the work string 6 is placed in the open position. Additives can then be added to the

drilling fluid at the surface, thereby increasing the density. The heavier drilling fluid is

circulated down the work string 6, through the shunt valve 92. Once the denser

drilling fluid has replaced the lighter fluid, the inflatable packers 24, 26 can be unseated

and the circulation valve 90 is placed in the open position. Drilling may then resume.

While the particular invention as herein shown and disclosed in detail is fully

capable of obtaining the objects and providing the advantages hereinbefore stated, it is

to be understood that this disclosure is merely illustrative of the presently preferred

embodiments of the invention and that no limitations are intended other than as described in the appended claims.

Claims

28CLAIMSWe claim:

1. An apparatus for testing an underground formation during drilling

operations, comprising: a rotatable drill string;

at least one extendible element mounted on said drill string, said at least

one extendible element being selectively extendible into sealing engagement

with the wall of the well bore for isolating a portion of the well bore at the

formation while rotation of the drill string is stopped, said at least one

extendible element being selectively retractable; a test port in said drill string, said test port being exposable to said

isolated portion of the well bore; and

a test device mounted within said drill string for testing at least one

characteristic of the formation via said test port.

2. The apparatus recited in claim 1, wherein said test device comprises: a fluid control device mounted within said drill string for allowing

formation fluid through said test port from said isolated portion of the well

bore; and a sensor for sensing at least one characteristic of the fluid.

3. The apparatus recited in claim 2, wherein said sensor is selected from a

group comprising a pressure sensor, a resistivity sensor, a viscosity sensor, a flow rate

measuring device, a dielectric property measuring device, a density measuring device,

or an optical spectroscope. 29

4. The apparatus recited in claim 2, further comprising at least one sample

chamber mounted on said drill string, said at least one sample chamber being in fluid

flow communication with said test port, for collecting a sample of formation fluid.

5. The apparatus recited in claim 4, wherein said at least one sample

chamber is wireline retrievable.

6. The apparatus recited in claim 1, wherein said test device comprises a

coring device mounted within said drill string for obtaining a core sample from said

isolated portion of the formation, through said test port.

7. The apparatus recited in claim 1, wherein said at least one extendible

element comprises first and second expandable annular elements mounted on said drill

string, said second expandable annular element being spaced longitudinally from said

first expandable annular element, said first and second expandable annular elements

being selectively expandable to contact the wall of the well bore in a sealing

relationship, thereby dividing an annular space surrounding said drill string into an

upper annulus, an intermediate annulus and a lower annulus, wherein said intermediate

annulus comprises said isolated portion of the well bore.

8. The apparatus recited in claim 7, further comprising:

at least a third additional expandable annular element mounted on said

drill string, each said expandable annular element being spaced longitudinally

from other said expandable annular elements, said expandable annular elements 30 being selectively expandable to contact the wall of the well bore in a sealing relationship, thereby dividing an annular space surrounding said drill string into

a longitudinally arranged series of annular spaces, wherein said series of annular

spaces comprise a series of isolated portions of the well bore; and

at least a second additional test port in said drill string, each said test

port being exposable to a respective said isolated portion of the well bore.

9. The apparatus recited in claim 1, further comprising a protective

structure on said drill string, said protective structure extending radially beyond said at least one extendible element, when said element is retracted.

10. The apparatus recited in claim 1, wherein said test port is located in said

extendible element.

11. The apparatus recited in claim 1, wherein said test port is located

adjacent to said extendible element.

12. The apparatus of any one of claims 1-11 wherein said extendible

element is located on a non-rotating sleeve which is in turn located on said drill string.

13. A method of testing a formation comprising:

lowering a drill string into a well bore, said drill string including a drill

bit, a telemetry system, at least one element extendible from said drill string, a

test port, and at least one formation test device; 31 drilling the well bore hole;

positioning said at least one extendible element adjacent a selected subterranean formation; extending said at least one extendible element into sealing engagement

with the wall of the well bore to isolate a portion of the well bore adjacent the

selected formation; and

performing a test of said formation via said test port.

14. The method recited in claim 13, wherein said formation test device

includes a fluid control device and a sensing apparatus, and said step of performing a

test of said formation comprises: allowing formation fluid through said test port from said isolated

portion of the well bore; and

sensing at least one characteristic of the formation fluid.

15. The method recited in claim 14, wherein said drill string further includes

at least one sample chamber, said method further comprising transferring formation

fluid into said at least one sample chamber.

16. The method recited in claim 14, further comprising telemetering

information about said at least one characteristic.

17. The method recited in claim 13, wherein said formation test device

includes a coring device, and said step of performing a test of said formation comprises 32 obtaining a core sample from said isolated portion of the formation, through said test

port.

18. A method of testing a reservoir formation comprising:

lowering a drill string into a well bore, said drill string having at least one non-rotating sleeve, with at least one extendible element, a

port, at least one fluid transfer device, and a pressure sensing apparatus

mounted on said non-rotating sleeve;

positioning said at least one extendible element adjacent a selected subterranean formation;

extending said at least one extendible element to establish a

sealing engagement with the wall of the well bore to isolate a portion of

the well bore adjacent the selected formation; applying fluid via said port with said at least one fluid transfer

device to raise the pressure in said isolated portion of the well bore to a

selected test level; and

monitoring the pressure in said isolated portion of the well bore

with said pressure sensing apparatus to sense a pressure drop.

19. A method of testing a reservoir formation comprising:

lowering a drill string into a well bore, said drill string including

at least two elements expandable from said drill string, at least two

ports, and at least one fluid transfer device;

positioning said at least two expandable elements adjacent to at least two selected subterranean formations; 33 expanding said at least two expandable elements to establish a

sealing engagement with the wall of the well bore to isolate at least two selected subterranean formations from each other; and

transferring formation fluid from at least a first said selected

subterranean formation to at least a second said selected subterranean

formation through said at least two ports.

20. A method of testing a formation comprising:

lowering a drill string into a well bore, said drill string including a drill

bit, at least one element extendible from said drill string, a port, and at least one

fluid transfer device; drilling the well bore hole;

positioning said at least one extendible element adjacent a selected

subterranean formation;

extending said at least one extendible element into sealing engagement

with the wall of the well bore to isolate a portion of the well bore adjacent the

selected formation; and

applying high pressure fluid via said port with said fluid transfer device,

to fracture said isolated portion of the well bore.

21. A method of testing a formation comprising :

lowering a drill string into a well bore, said drill string including a drill

bit, at least one element extendible from said drill string, a port, at least one

fluid transfer device, and a pressure sensing apparatus; 34 drilling the well bore hole;

positioning said at least one extendible element adjacent a selected subterranean formation;

extending said at least one extendible element into sealing engagement

with the wall of the well bore to isolate a portion of the well bore adjacent the

selected formation;

applying fluid via said port with said fluid transfer device, to raise the

pressure in said isolated portion of the well bore to a selected test level; and

monitoring the pressure in said isolated portion of the well bore with

said pressure sensing apparatus, to sense a pressure drop.

22. A method of testing a formation comprising:

lowering a drill string into a well bore, said drill string including a drill

bit, at least two elements expandable from said drill string, at least two ports,

and at least one fluid transfer device;

drilling the well bore hole;

positioning said at least two expandable elements adjacent to at least two selected subterranean formations;

expanding said at least two expandable elements into sealing

engagement with the wall of the well bore to isolate said at least two selected

subterranean formations from each other; and

transferring formation fluid from at least a first said selected

subterranean formation to at least a second said selected subterranean

formation through said at least two ports. 35

23. A method in accordance with any of claims 13-21 further comprising

locating said extendible element on a non-rotating sleeve.