Apparatus and method for formation testing while drilling with minimum system volume

Information

  • Patent Grant
  • 6640908
  • Patent Number
    6,640,908
  • Date Filed
    Wednesday, August 7, 2002
    21 years ago
  • Date Issued
    Tuesday, November 4, 2003
    20 years ago
Abstract
A minimum volume apparatus and method is provided including a tool for obtaining at least one parameter of interest of a subterranean formation in-situ, the tool comprising a carrier member, a selectively extendable member mounted on the carrier for isolating a portion of annulus, a port exposable to formation fluid in the isolated annulus space, a piston integrally disposed within the extendable member for urging the fluid into the port, and a sensor operatively associated with the port for detecting at least one parameter of interest of the fluid.
Description




BACKGROUND OF THE INVENTION




1. Field of the Invention




This invention generally relates to the testing of underground formations or reservoirs. More particularly, this invention relates to a reduced volume method and apparatus for sampling and testing a formation fluid.




2. Description of the Related Art




To obtain hydrocarbons such as oil and gas, well boreholes are drilled by rotating a drill bit attached at a drill string end. The drill string may be a jointed rotatable pipe or a coiled tube. A large portion of the current drilling activity involves directional drilling, i.e., drilling boreholes deviated from vertical and/or horizontal boreholes, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from earth formations. Modem directional drilling systems generally employ a drill string having a bottomhole assembly (BHA) and a drill bit at an end thereof that is rotated by a drill motor (mud motor) and/or the drill string. A number of downhole devices placed in close proximity to the drill bit measure certain downhole operating parameters associated with the drill string. Such devices typically include sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a resistivity-measuring device to determine the presence of hydrocarbons and water. Additional downhole instruments, known as measurement-while-drilling (MWD) or logging-while-drilling (LWD) tools, are frequently attached to the drill string to determine formation geology and formation fluid conditions during the drilling operations.




Pressurized drilling fluid (commonly known as the “mud” or “drilling mud”) is pumped into the drill pipe to rotate the drill motor, to provide lubrication to various members of the drill string including the drill bit and to remove cuttings produced by the drill bit. The drill pipe is rotated by a prime mover, such as a motor, to facilitate directional drilling and to drill vertical boreholes. The drill bit is typically coupled to a bearing assembly having a drive shaft which in turn rotates the drill bit attached thereto. Radial and axial bearings in the bearing assembly provide support to the drill bit against these radial and axial forces.




Boreholes are usually drilled along predetermined paths and proceed through various formations. A drilling operator typically controls the surface-controlled drilling parameters to optimize the drilling operations. These parameters include weight on bit, drilling fluid flow through the drill pipe, drill string rotational speed (r.p.m. of the surface motor coupled to the drill pipe) and the density and viscosity of the drilling fluid. The downhole operating conditions continually change and the operator must react to such changes and adjust the surface-controlled parameters to continually optimize the drilling operations. For drilling a borehole in a virgin region, the operator typically relies on seismic survey plots, which provide a macro picture of the subsurface formations and a pre-planned borehole path. For drilling multiple boreholes in the same formation, the operator may also have information about the previously drilled boreholes in the same formation.




Typically, the information provided to the operator during drilling includes borehole pressure, temperature, and drilling parameters such as weight-on-bit (WOB), rotational speed of the drill bit and/or the drill string, and the drilling fluid flow rate. In some cases, the drilling operator is also provided selected information about the bottomhole assembly condition (parameters), such as torque, mud motor differential pressure, torque, bit bounce and whirl, etc.




Downhole sensor data are typically processed downhole to some extent and telemetered uphole by sending a signal through the drill string or by transmitting pressure pulses through the circulating drilling fluid, i.e. mud-pulse telemetry. Although mud-pulse telemetry is more commonly used, such a system is capable of transmitting only a few (1-4) bits of information per second. Due to such a low transmission rate, the trend in the industry has been to attempt to process greater amounts of data downhole and transmit selected computed results or “answers” uphole for use by the driller for controlling the drilling operations.




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 additional data. Therefore, after the well has been drilled, the hydrocarbon zones are often tested with other test equipment.




One type of post-drilling test involves producing fluid from the reservoir, collecting samples, shutting-in the well, reducing a test volume pressure, 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 borehole or at several points in a single reservoir. This type of test is known as a “Pressure Build-up Test.” One important aspect of data collected during such a Pressure Build-up Test is the pressure buildup information gathered after drawing down the pressure in the test volume. From this data, information can be derived as to permeability and size of the reservoir. Moreover, actual samples of the reservoir fluid can be obtained and tested to gather Pressure-Volume-Temperature data relevant to the reservoir's hydrocarbon distribution.




Some systems require retrieval of the drill string from the borehole to perform pressure testing. The drill is removed, and a pressure measuring tool is run into the borehole using a wireline and packers for isolating the reservoir. Although wireline conveyed tools are capable of testing a reservoir, it is difficult to convey a wireline tool in a deviated borehole.




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 mud-pulse telemetry to or from a downhole 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, thereby 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 drill string and running a second test rig into the hole is significant. Further, when a hole is highly deviated wireline conveyed test figures cannot be used because frictional force between the test rig and the wellbore exceed gravitational force causing the test rig to stop before reaching the desired formation.




A more recent system is disclosed in U.S. Pat. No. 5,803,186 to Berger et al. The '186 patent provides a MWD system that includes use of pressure and resistivity sensors with the MWD system, to allow for real time data transmission of those measurements. The '186 device enables obtaining static pressures, pressure build-ups, and pressure draw-downs with the work string, such as a drill string, in place. Also, computation of permeability and other reservoir parameters based on the pressure measurements can be accomplished without removing the drill string from the borehole.




A problem with the system described in the '186 patent relates to the time required for completing a test. During drilling, density of the drilling fluid is calculated to achieve maximum drilling efficiency while maintaining safety, and the density calculation is based upon the desired relationship between the weight of the drilling mud column and the predicted downhole pressures to be encountered. After a test is taken a new prediction is made, the mud density is adjusted as required and the bit advances until another test is taken. Different formations are penetrated during drilling, and the pressure can change significantly from one formation to the next and in short distances due to different formation compositions. If formation pressure is lower than expected, the pressure from the mud column may cause unnecessary damage to the formation. If the formation pressure is higher than expected, a pressure kick could result. Consequently, delay in providing measured pressure information to the operator results in drilling mud being maintained at too high or too low a density for maximum efficiency and maximum safety.




A drawback of the '186 patent, as well as other systems requiring fluid intake, is-that system clogging caused by debris in the fluid can seriously impede drilling operations. When drawing fluid into the system, cuttings from the drill bit or other rocks being carried by the fluid may enter the system. The '186 patent discloses a series of conduit paths and valves through which the fluid must travel. It is possible for debris to clog the system at any valve location, at a conduit bend or at any location where conduit size changes. If the system is clogged, it may have to be retrieved from the borehole for cleaning causing enormous delay in the drilling operation. Therefore, it is desirable to have an apparatus with reduced risk of clogging to increase drilling efficiency.




Another drawback of the '186 patent is that it has a large system volume. Filling a system with fluid takes time, so a system with a large internal volume requires more time to sample and test than does a system with a smaller internal volume. Therefore it is desirable to minimize internal system volume in order to maximize sampling and test efficiency.




SUMMARY OF THE INVENTION




The present invention addresses some of the drawbacks discussed above by providing a measurement while drilling apparatus and method which enables sampling and measurements of parameters of fluids contained in a borehole while reducing the time required for taking such samples and measurements and reducing the risk of system clogging.




A minimum system volume apparatus is provided comprising a tool for obtaining at least one parameter of interest for a subterranean formation in-situ. The tool comprises a carrier member for conveying the tool into a borehole; at least one extendable member mounted on the carrier member, the at least one extendable member being selectively extendable into sealing engagement with the wall of the borehole for isolating a portion of an annular space between the carrier member and the formations; a port exposable to a fluid containing formation fluid in the isolated annular space; a piston integrally disposed within the extendable member for urging the fluid contained in the isolated annular space into the port; and a sensor operatively associated with the port for detecting at least one parameter of interest of the fluid indicative of the at least one formation parameter of interest.




In addition to the apparatus provided, a method is provided for obtaining at least one parameter of interest for a subterranean formation in-situ. The method comprises conveying a tool on a carrier member into a borehole; extending at least one pad member mounted on the carrier member; isolating a portion of an annular space between the carrier member and the borehole with the at least one pad member; exposing a port to a fluid containing formation fluid in the isolated annular space; urging the fluid contained in the isolated annular space into the port with a piston integrally disposed within the pad member; and detecting at least one parameter of interest of the fluid with a sensor operatively associated with the port for detecting, the at least one fluid parameter of interest indicative of the at least one formation parameter of interest.




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.











BRIEF DESCRIPTION OF THE DRAWINGS





FIG. 1

is an elevation view of an offshore drilling system according to one embodiment of the present invention.





FIG. 2

shows a preferred embodiment of the present invention wherein downhole components are housed in a portion of drill string and a surface controller is shown schematically.





FIG. 3

is a detailed cross sectional view of an integrated pump and pad in an inactive state according to the present invention.





FIG. 4

is a cross sectional view of an integrated pump and pad showing an extended pad member according to the present invention.





FIG. 5

is a cross sectional view of an integrated pump and pad after a pressure test according to the present invention.





FIG. 6

is a cross sectional view of an integrated pump and pad after flushing the system according to the present invention.





FIG. 7

shows an alternate embodiment of the present invention wherein packers are not required.





FIG. 8

shows and alternate mode of operation of a preferred embodiment wherein samples are taken with the pad member in a retracted position.











DESCRIPTION OF PREFERRED EMBODIMENTS





FIG. 1

is a typical drilling rig


102


with a borehole


104


being drilled into the subterranean formations


118


, as is well understood by those of ordinary skill in the art. The drilling rig


102


has a work string


106


, which in the typical embodiment shown in

FIG. 1

is a drill string. The work string


106


has attached thereto a drill bit


108


for drilling the borehole


104


. 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. The drilling rig


102


is shown positioned on a drilling ship


122


with a riser


124


extending from the drilling ship


122


to the sea floor


120


.




If applicable, the drill string


106


(or any suitable work string) can have a downhole drill motor


110


for rotating the drill bit


108


. Incorporated in the drill string


106


above the drill bit


108


is at least one typical sensor


114


to sense downhole characteristics of the borehole, the bit, and the reservoir. Typical sensors sense characteristics such as temperature, pressure, bit speed, depth, gravitational pull, orientation, azimuth, fluid density, dielectric, etc. The drill string


106


also contains the formation test apparatus


116


of the present invention, which will be described in greater detail hereinafter. A telemetry system


112


is located in a suitable location on the drill string


106


such as uphole from the test apparatus


116


. The telemetry system


112


is used to receive commands from, and send data to, the surface.





FIG. 2

is a cross section elevation view of a preferred system according to the present invention. The system includes surface components and downhole components to carry out “Formation Testing While Drilling” (FTWD) operations. A borehole


104


is shown drilled into a formation


118


containing a formation fluid


216


. Disposed in the borehole


104


is a drill string


106


. The downhole components are conveyed on the drill string


106


, and the surface components are located in suitable locations on the surface. A surface controller


202


typically includes a communication system


204


electronically connected to a processor


206


and an input/output device


208


, all of which are well known in the art. The input/out device


208


may be a typical terminal for user inputs. A display such as a monitor or graphical user interface may be included for real time user interface. When hard-copy reports are desired, a printer may be used. Storage media such as CD, tape or disk are used to store data retrieved from downhole for future analyses. The processor


206


is used for processing (encoding) commands to be transmitted downhole and for processing (decoding) data received from downhole via the communication system


204


. The surface communication system


204


includes a receiver for receiving data transmitted from downhole and transferring the data to the surface processor for evaluation recording and display. A transmitter is also included with the communication system


204


to send commands to the downhole components. Telemetry is typically relatively slow mud-pulse telemetry, so downhole processors are often deployed for preprocessing data prior to transmitting results of the processed data to the surface.




A known communication and power unit


212


is disposed in the drill string


106


and includes a transmitter and receiver for two-way communication with the surface controller


202


. The power unit, typically a mud turbine generator, provides electrical power to run the downhole components.




Connected to the communication and power unit


212


is a controller


214


. As stated earlier a downhole processor (not separately shown) is preferred when using mud-pulse telemetry; the processor being integral to the controller


214


. The controller


214


uses preprogrammed commands, surface-initiated commands or a combination of the two to control the downhole components. The controller controls the extension of anchoring, stabilizing and sealing elements disposed on the drill string, such as grippers


210


and packers


232


and


234


. The control of various valves (not shown) can control the inflation and deflation of packers


232


and


234


by directing drilling mud flowing through the drill string


106


to the packers


232


and


234


. This is an efficient and well-known method to seal a portion of the annulus or to provide drill string stabilization while sampling and tests are conducted. When deployed, the packers


232


and


234


separate the annulus into an upper annulus


226


, an intermediate annulus


228


and a lower annulus


230


. The creation of the intermediate annulus


228


sealed from the upper annulus


226


and lower annulus


230


provides a smaller annular volume for enhanced control of the fluid contained in the volume.




The grippers


210


, preferably have a roughened end surface for engaging the well wall


244


to anchor the drill string


106


. Anchoring the drill string


106


protects soft components such as the packers


232


and


234


and pad member


220


from damage due to tool movement. The grippers


210


would be especially desirable in offshore systems such as the one shown in

FIG. 1

, because movement caused by heave can cause premature wear out of sealing components.




The controller


214


is also used to control a plurality of valves


240


combined in a multi-position valve assembly or series of independent valves. The valves


240


direct fluid flow driven by a pump


238


disposed in the drill string


106


to extend a pad piston


222


, operate a drawdown piston or otherwise called a draw piston


236


, and control pressure in the intermediate annulus


228


by pumping fluid from the annulus


228


through a vent


218


. The annular fluid may be stored in an optional storage tank


242


or vented to the upper


226


or lower annulus


230


through standard piping and the vent


218


.




Mounted on the drill string


106


via a pad piston


222


is a pad member


220


for engaging the borehole wall


244


. The pad member


220


is a soft elastomer cushion such as rubber. The pad piston


222


is used to extend the pad


220


to the borehole wall


244


. A pad


220


seals a portion of the annulus


228


from the rest of the annulus. A port


246


located on the pad


220


is exposed to formation fluid


216


, which tends to enter the sealed annulus when the pressure at the port


246


drops below the pressure of the surrounding formation


118


. The port pressure is reduced and the formation fluid


216


is drawn into the port


246


by a draw piston


236


. The draw piston


236


is operated hydraulically and is integral to the pad piston


222


for the smallest possible fluid volume within the tool. The small volume allows for faster measurements and reduces the probability of system contamination from the debris being drawn into the system with the fluid.




It is possible to cause damage downhole seals and the borehole mudcake when extending the pad member


220


, expanding the packers


232


and


234


, or when venting fluid. Care should be exercised to ensure the pressure is vented or exhausted to an area outside the intermediate annulus


228


.

FIG. 2

shows a preferred location for the vent


218


above the upper packer


232


. It is also possible to prevent damage by leaving the upper packer


232


in a retracted position until the lower packer


234


is set and the pad member


220


is sealed against the borehole wall.





FIGS. 3 through 6

show details of the pad


220


and pistons


222


and


236


in more detail and in several operational positions.

FIG. 3

is a cross sectional view of the fluid sampling unit of

FIG. 2

in its initial, inactive or transport position. In the position shown in

FIG. 3

, the pad member


220


is fully retracted toward a tool housing


304


. A sensor


320


is disposed at the end of the pad member


226


. Disposed within the tool housing


304


is a piston cylinder


308


that contains hydraulic oil or drilling mud


326


in a draw reservoir


322


for operating the draw piston


236


. The draw piston


236


is coaxially disposed within the drawdown cylinder


308


and is shown in its outermost or initial position. In this initial position, there is substantially zero volume at the port


246


. The pad extension piston


222


is shown disposed circumferentially around and coaxially with the draw piston


236


. A barrier


306


disposed between the base of the draw piston


236


and the base of the pad extension piston


222


separates the piston cylinder reservoir into an inner (or draw) reservoir


322


and an outer (or extension) reservoir


324


. The separate extension reservoir


324


allows for independent operation of the extension piston


222


relative to the draw piston


236


. The hydraulic reservoirs are preferably balanced to hydrostatic pressure of the annulus for consistent operation.




Referring to

FIGS. 2 and 3

, each piston assembly provides dedicated control lines


312


-


318


. The draw piston


236


is controlled in the “draw” direction by fluid


326


entering the draw line


314


while fluid


326


exits through the “flush” line


312


. When fluid flow is reversed in these lines, the draw piston


236


travels in the opposite or outward direction. Independent of the draw piston


236


, the pad extension piston


222


is forced outward by fluid


328


entering the pad deploy line


316


while fluid


328


exits the pad retract line


318


. Like the draw piston


236


, the travel of the pad extension piston


222


is reversed when the fluid


328


in the lines


316


and


318


reverses direction. As shown in

FIG. 2

, the line selection, and thus the direction of travel, is controlled through the valves


240


by the downhole controller


214


. The pump


238


provides the fluid pressure in the line selected.




Referring now to

FIGS. 2 and 4

, a pad piston


222


is shown at its outermost position. In this position, the pad


220


is in sealing engagement with the borehole wall


244


. To get to this position, the piston


222


is forced radially outward and perpendicular to a longitudinal axis of the drill string


106


by fluid


328


entering the outer reservoir


324


through the pad deploy fluid line


316


. The port


246


located at the end of the pad


220


is open, and formation fluid


216


will enter the port


246


when the draw piston


236


is activated.




Test volume can be reduced to substantially zero in an alternate embodiment according to the present invention. Still referring to

FIG. 4

, if the sensor


320


is slightly reconfigured to translate with the draw piston


236


, and the draw piston extends to the borehole wall


244


with the pad piston


222


there would be zero volume at the port


246


. One way to extend the draw piston


236


to the borehole wall


244


is to extend the housing assembly


304


until the pad


220


contacts the wall


244


. If the housing


304


is extended, then there is no need to extend the pad piston


222


. At the beginning of a test with the housing


304


extended, the pad


220


, port


246


, sensor


320


, and draw piston


236


are all urged against the wall


244


. Pressure should be vented to the upper annulus


226


via the vent valve


240


and vent


218


when extending elements into the annulus to prevent over pressurizing its intermediate annulus


228


.




Another embodiment enabling the draw piston to extend is to remove the barrier


306


and use the flush line


312


to extend both pistons. The pad extension line


316


would then not be necessary, and the draw line


314


would be moved closer to the pad retract line


318


. The actual placement of the draw line


314


would be such that the space between the base of the draw piston


236


and the base of the pad extension piston


222


aligns with the draw line


314


, when both pistons are fully extended.




Referring now to

FIGS. 2 and 5

, cross-sectional views are shown of an integrated pump and pad according the present invention after sampling. Formation fluid


216


is drawn into a sampling reservoir


502


when the draw piston


236


moves inward toward the base of the housing


304


. As described earlier, movement of the draw piston


236


toward the base of the housing


304


is accomplished by hydraulic fluid or mud


326


entering the draw reservoir


322


through the draw line


314


and exiting through the flush line


312


. Clean fluid, meaning formation fluid


216


substantially free of contamination by drilling mud, can be obtained with several draw-flush-draw cycles. Flushing will be described in detail later.




Fluid drawn into the system may be tested downhole with one or more sensors


320


, or the fluid may be pumped to optional storage tanks


242


for retrieval and surface analysis or both. The sensor


320


may be located at the port


246


, with its output being transmitted or connected to the controller


214


via a sensor tube


310


as a feedback circuit. The controller may be programmed to control the draw of fluid from the formation based on the sensor output. The sensor


320


may also be located at any other desired suitable location in the system. If not located at the port


246


, the sensor


320


is preferably in fluid communication with the port


246


via the sensor tube


310


.




Referring to

FIGS. 2 and 6

, a detailed cross sectional view of an integrated pump and pad according the present invention is shown after flushing the system. The system draw piston


236


flushes the system when it is returned to its pre-draw position or when both pistons


222


and


236


are returned to the initial positions. The translation of the fluid piston


236


to flush the system occurs when fluid


326


is pumped into the draw reservoir through the flush line


312


. Formation fluid


216


contained in the sample reservoir


502


is forced out of the reservoir as shown in

FIG. 5. A

check valve


602


may be used to allow fluid to exit into the annulus


228


, or the fluid may be forced out through the port


246


as shown in FIG.


6


. The check valve


602


should not be used when the upper packer is extended. Retracting its packer


232


will ensure the intermediate annulus


228


is not over pressurized when fluid is flushed via the check valve


602


. The check valve


602


may also be relocated such that expelled fluid is vented to the upper annulus


226


.





FIG. 7

shows an alternative embodiment of the present invention wherein packers are not required and the optional storage reservoirs are not used. A drill string


106


carries downhole components comprising a communication/power unit


212


, controller


214


, pump


708


, a valve assembly


710


, stabilizers


704


, and a pump assembly


714


. A surface controller sends commands to and receives data from the downhole components. The surface controller comprises a two-way communications unit


204


, a processor


206


, and an input-out device


208


.




In this embodiment, stabilizers or grippers


704


selectively extend to engage the borehole wall


244


to stabilize or anchor the drill string


106


when the piston assembly


714


is adjacent a formation


118


to be tested. A pad extension piston


222


extends in a direction generally opposite the grippers


704


. The pad


220


is disposed on the end of the pad extension piston


222


and seals a portion of the annulus


702


at the port


246


. Formation fluid


216


is then drawn into the piston assembly


714


as described above in the discussion of

FIGS. 4 and 5

. Flushing the system is accomplished as described above in the discussion of FIG.


6


.




The configuration of

FIG. 7

shows a sensor


706


disposed in the fluid sample reservoir of the piston assembly


714


. The sensor senses a desired parameter of interest of the formation fluid such as pressure, and the sensor transmits data indicative of the parameter of interest back to the controller


214


via conductors, fiber optics or other suitable transmission conductor. The controller


214


further comprises a controller processor (not separately shown) that processes the data and transmits the results to the surface via the communications and power unit


212


. The surface controller receives, processes and outputs the results described above in the discussion of

FIGS. 1 and 2

.




Modifications to the embodiments described above are considered within scope of this invention. Referring to

FIG. 2

for example, the draw piston


236


and pad piston


222


may operated electrically, rather than hydraulically as shown. An electrical motor can be used to reciprocate each piston independently, or preferably, one motor controls both pistons. The electrical motor could replace the pump


238


shown in FIG.


2


. If a controllable pump power source such as a spindle or stepper motor is selected, then the piston position can be selectable throughout the line of travel. This feature is preferable in applications where precise control of system volume is desired.




A spindle motor is a known electrical motor wherein electrical power is translated into rotary mechanical power. Controlling electrical current flowing through motor windings controls the torque and/or speed of a rotating output shaft. A stepper motor is a known electrical motor that translates electrical pulses into precise discrete mechanical movement. The output shaft movement of a stepper motor can be either rotational or linear.




Using either a stepper motor or a spindle motor, the selected motor output shaft is connected to a device for reciprocating the pad and draw pistons


222


and


236


. A preferred device is a known ball screw assembly (BSA). A BSA uses circulating ball bearings (typically stainless steel or carbon) to roll along complementary helical groves of a nut and screw subassembly. The motor output shaft may turn either the nut or screw while the other translates linearly along the longitudinal axis of the screw subassembly. The translating component is connected to a piston, thus the piston is translated along the longitudinal axis of the screw subassembly axis.




Now that system embodiments of the invention have been described, a preferred method of testing a formation using the preferred system embodiment will be described. Referring first to

FIGS. 1-6

, a tool according to the present invention is conveyed into a borehole


104


on a drill string


106


. The drill string is anchored to the well wall using a plurality of grippers


210


that are extended using methods well known in the art. The annulus between the drill string


106


and borehole wall


244


is separated into an upper section


226


, an intermediate section


228


and a lower section


230


using expandable packers


232


and


234


known in the art. Using a pad extension piston


222


, a pad member


220


is brought into sealing contact with the borehole wall


244


preferably in the intermediate annulus section


228


. Using a pump


238


, drilling fluid pressure in the intermediate annulus


228


is reduced by pumping fluid from the section through a vent


218


. A draw piston


236


is used to draw formation fluid


216


into a fluid sample volume


502


through a port


246


located on the pad


220


. At least one parameter of interest such as formation pressure, temperature, fluid dielectric constant or resistivity is sensed with a sensor


320


, and the sensor output is processed by a downhole processor. The results are then transmitted to the surface using a two-way communications unit


212


disposed downhole on the drill string


106


. Using a surface communications unit


204


, the results received and forwarded to a surface processor


206


. The method further comprises processing the data at the surface for output to a display unit, printer, or storage device


208


.




A test using substantially zero volume can be accomplished using an alternative method according to the present invention. To ensure initial volume is substantially zero, the draw piston


236


and sensor are extended along with the pad


220


and pad piston


222


to seal off a portion of the borehole wall


244


. The remainder of this alternative method is essentially the same as the embodiment described above. The major difference is that the draw piston


236


need only be translated a small distance back into the tool to draw formation fluid into the port


246


thereby contacting the sensor


320


. The very small volume reduces the time required for the volume parameters being sensed to equalize with the formation parameters.





FIG. 8

illustrates another method of operation wherein samples of formation fluid


216


are taken with the pad member


220


in a retracted position. The annulus is separated into the several sealed sections


226


,


228


and


230


as described above using expandable packers


232


and


234


. Using a pump


238


, drilling fluid pressure in the intermediate annulus


228


is reduced by pumping fluid from the section through a vent


218


. With the pressure in the intermediate annulus


228


lower than the formation pressure, formation fluid


216


fills the intermediate annulus


228


. If the pumping process continues, the fluid in the intermediate annulus becomes substantially free of contamination by drilling mud. Then without extending the pad member


220


, the draw piston


236


is used to draw formation fluid


216


into a fluid sample volume


502


through a port


246


exposed to the fluid


216


. At least one parameter of interest such as those described above is sensed with a sensor


320


, and the sensor output is processed by a downhole processor. The processed data is then transmitted to the surface controller


202


for further processing and output as described above.




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
  • 1. A tool for obtaining in situ a parameter of interest of a subterranean formation, the tool comprising:(a)a carrier member for conveying the tool into a borehole, the tool having a port associated with a sealing member for providing communication with fluid in the formation, the tool further including an internal test volume at the port for receiving formation fluid; (b) a device integrally disposed with the internal test volume, the device operating to draw formation fluid into the volume; and (c) a sensor operatively associated with the internal test volume for detecting a parameter of interest of the fluid, the fluid parameter of interest being indicative of the formation parameter of interest.
  • 2. The tool of claim 1, wherein the sealing member comprises a pad seal on an extendable piston for sealing a portion of the borehole around the port.
  • 3. The tool of claim 1, wherein the sealing member comprises a pair of packers for sealing an annular portion of the borehole around the port.
  • 4. The tool of claim 1, wherein the device for drawing fluid into the internal test volume includes a pump.
  • 5. The tool of claim 1, wherein the device for drawing fluid into the internal test volume includes a piston for controlling volume in the internal test volume.
  • 6. The tool of claim 5, wherein the draw piston is movably disposed within an extendable piston.
  • 7. The tool of claim 1, wherein the carrier member is selected from a group consisting of (i) a jointed pipe drill string; (ii) a coiled tube; and (iii) wireline.
  • 8. The tool of claim 1, wherein the device for drawing fluid into the internal test volume is hydraulically operated using a fluid selected from a group consisting of (i) an oil and (ii) drilling mud.
  • 9. The tool of claim 1, wherein the device for drawing fluid into the internal test volume is operated by an electric motor.
  • 10. The tool of claim 9, wherein the electric motor is selected from a group consisting of (i) a spindle motor and (ii) a stepper motor.
  • 11. The tool of claim 1 further comprising a conduit for providing fluid communication between the internal test volume and the sensor.
  • 12. The tool of claim 1 further comprising a pump for transferring the fluid from the port to at least one fluid storage reservoir.13.The apparatus of claim 1 further comprising an extendable housing and wherein the device for drawing fluid into the internal test volume is disposed in the extendable housing.
  • 14. A method for obtaining a parameter of interest of a subterranean formation in-situ, the method comprising:(a) sealing a portion of a borehole wall; (b) exposing a port in a tool to the sealed portion; (c) drawing fluid into a tool internal test volume at the port using a device integrally disposed with the internal test volume; and (d) detecting a parameter of interest of the fluid in the internal test volume with a sensor, the fluid parameter of interest being indicative of the a formation parameter of interest.
  • 15. The method of claim 14, wherein the tool is conveyed into the borehole on a carrier member selected from a group consisting of (i) a drill pipe; (ii) a coiled tubing; and (iii) a wireline.
  • 16. The method of claim 14, wherein sealing a portion of the borehole wall includes extending a selectively extendable pad member into sealing contact with the borehole wall.
  • 17. The method of claim 14 further comprising operating the fluid drawing device hydraulically using hydraulic fluid selected from a group consisting of (i) an oil and (ii) drilling mud.
  • 18. The method of claim 14, wherein the fluid drawing device includes a reciprocating piston, the method further comprising moving the reciprocating piston between a first position and a second position, the reciprocating piston drawing the fluid into the port when moving from the first position to the second position.
  • 19. The method of claim 14 further comprising providing fluid communication between the port and the sensor through a conduit.
  • 20. The method of claim 14 further comprising transferring the fluid from the port to a fluid storage reservoir using a pump.
  • 21. The method of claim 14 further comprising operating the fluid drawing device with an electric motor.
  • 22. The method of claim 21, wherein the electric motor is selected from a group consisting of (i) a spindle motor and (ii) a stepper motor.
  • 23. The method of claim 14 further comprising extending a housing from the tool, the fluid drawing device being disposed in the housing.
CROSS REFERENCES TO RELATED APPLICATIONS

This application is a continuation of Nonprovisional U.S. patent application Ser. No. 09/621,398 filed on Jul. 21, 2000 now U.S. Pat. No. 6,478,096.

US Referenced Citations (8)
Number Name Date Kind
3864970 Bell Feb 1975 A
4833914 Rasmus May 1989 A
5428293 Sinclair et al. Jun 1995 A
5799733 Ringgenberg et al. Sep 1998 A
5803186 Berger et al. Sep 1998 A
6157893 Berger et al. Dec 2000 A
6178815 Felling et al. Jan 2001 B1
6206108 MacDonald et al. Mar 2001 B1
Foreign Referenced Citations (1)
Number Date Country
2334982 Sep 1999 GB
Continuations (1)
Number Date Country
Parent 09/621398 Jul 2000 US
Child 10/213865 US