Downhole probe assembly

A downhole, extendable apparatus and methods of use are described and claimed herein. In one embodiment, the extendable apparatus includes a piston that extends toward a borehole wall, the piston having an inner sampling member that is also extendable. The sampling member may be further extended to engage the borehole wall and penetrate the formation. The sampling member may also include a screen and an inner scraper or wiper that frictionally engages the screen and reciprocates to remove debris from the screen. The piston may comprise a seal pad having an internal cavity for receiving a volume of fluid. In another embodiment, the extendable apparatus comprises multiple, concentric pistons for extending the sampling member further toward the borehole wall than is possible with a single piston. The extendable apparatus may also include a retraction contact switch and position indicator.

Not applicable.

BACKGROUND

During the drilling and completion of oil and gas wells, it may be necessary to engage in ancillary operations, such as monitoring the operability of equipment used during the drilling process or evaluating the production capabilities of formations intersected by the wellbore. For example, after a well or well interval has been drilled, zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, bubblepoint and formation pressure gradient. These tests are performed in order to determine whether commercial exploitation of the intersected formations is viable and how to optimize production.

Wireline formation testers (WFT) and drill stem testing (DST) have been commonly used to perform these tests. The basic DST test tool consists of a packer or packers, valves or ports that may be opened and closed from the surface, and two or more pressure-recording devices. The tool is lowered on a work string to the zone to be tested. The packer or packers are set, and drilling fluid is evacuated to isolate the zone from the drilling fluid column. The valves or ports are then opened to allow flow from the formation to the tool for testing while the recorders chart static pressures. A sampling chamber traps clean formation fluids at the end of the test. WFTs generally employ the same testing techniques but use a wireline to lower the test tool into the well bore after the drill string has been retrieved from the well bore, although WFT technology is sometimes deployed on a pipe string. The wireline tool typically uses packers also, although the packers are placed closer together, compared to drill pipe conveyed testers, for more efficient formation testing. In some cases, packers are not used. In those instances, the testing tool is brought into contact with the intersected formation and testing is done without zonal isolation across the axial span of the circumference of the borehole wall.

WFTs may also include a probe assembly for engaging the borehole wall and acquiring formation fluid samples. The probe assembly may include an isolation pad to engage the borehole wall. The isolation pad seals against the formation and around a hollow probe, which places an internal cavity in fluid communication with the formation. This creates a fluid pathway that allows formation fluid to flow between the formation and the formation tester while isolated from the borehole fluid.

In order to acquire a useful sample, the probe must stay isolated from the relative high pressure of the borehole fluid. Therefore, the integrity of the seal that is formed by the isolation pad is critical to the performance of the tool. If the borehole fluid is allowed to leak into the collected formation fluids, a non-representative sample will be obtained and the test will have to be repeated.

With the use of WFTs and DSTs, the drill string with the drill bit must be retracted from the borehole. Then, a separate work string containing the testing equipment, or, with WFTs, the wireline tool string, must be lowered into the well to conduct secondary operations. Interrupting the drilling process to perform formation testing can add significant amounts of time to a drilling program.

DSTs and WFTs may also cause tool sticking or formation damage. There may also be difficulties of running WFTs in highly deviated and extended reach wells. WFTs also do not have flowbores for the flow of drilling mud, nor are they designed to withstand drilling loads such as torque and weight on bit.

Further, the formation pressure measurement accuracy of drill stem tests and, especially, of wireline formation tests may be affected by filtrate invasion and mudcake buildup because significant amounts of time may have passed before a DST or WFT engages the formation. Mud filtrate invasion occurs when the drilling mud fluids displace formation fluids. Because the mud filtrate ingress into the formation begins at the borehole surface, it is most prevalent there and generally decreases further into the formation. When filtrate invasion occurs, it may become impossible to obtain a representative sample of formation fluids or, at a minimum, the duration of the sampling period must be increased to first remove the drilling fluid and then obtain a representative sample of formation fluids. The mudcake is made up of the solid particles that are deposited on the side of the well as the filtrate invades the near well bore during drilling. The prevalence of the mudcake at the borehole surface creates a “skin.” Thus there may be a “skin effect” because formation testers can only withdraw fluids from relatively short distances into the formation, thereby distorting the representative sample of formation fluids due to the filtrate. The mudcake also acts as a region of reduced permeability adjacent to the borehole. Thus, once the mudcake forms, the accuracy of reservoir pressure measurements decreases, affecting the calculations for permeability and producibility of the formation.

Another testing apparatus is the measurement while drilling (MWD) or logging while drilling (LWD) tester. Typical LWD/MWD formation testing equipment is suitable for integration with a drill string during drilling operations. Various devices or systems are provided for isolating a formation from the remainder of the wellbore, drawing fluid from the formation, and measuring physical properties of the fluid and the formation. With LWD/MWD testers, the testing equipment is subject to harsh conditions in the wellbore during the drilling process that can damage and degrade the formation testing equipment before and during the testing process. These harsh conditions include vibration and torque from the drill bit, exposure to drilling mud, drilled cuttings, and formation fluids, hydraulic forces of the circulating drilling mud, and scraping of the formation testing equipment against the sides of the wellbore. Sensitive electronics and sensors must be robust enough to withstand the pressures and temperatures, and especially the extreme vibration and shock conditions of the drilling environment, yet maintain accuracy, repeatability, and reliability.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

Certain terms are used throughout the following description and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function.

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Also, the terms “couple,” “couples”, and “coupled” used to describe any electrical connections are each intended to mean and refer to either an indirect or a direct electrical connection. Thus, for example, if a first device “couples” or is “coupled” to a second device, that interconnection may be through an electrical conductor directly interconnecting the two devices, or through an indirect electrical connection via other devices, conductors and connections. Further, reference to “up” or “down” are made for purposes of ease of description with “up” meaning towards the surface of the borehole and “down” meaning towards the bottom or distal end of the borehole. In addition, in the discussion and claims that follow, it may be sometimes stated that certain components or elements are in fluid communication. By this it is meant that the components are constructed and interrelated such that a fluid could be communicated between them, as via a passageway, tube, or conduit. Also, the designation “MWD” or “LWD” are used to mean all generic measurement while drilling or logging while drilling apparatus and systems.

To understand the mechanics of formation testing, it is important to first understand how hydrocarbons are stored in subterranean formations. Hydrocarbons are not typically located in large underground pools, but are instead found within very small holes, or pore spaces, within certain types of rock. Therefore, it is critical to know certain properties of both the formation and the fluid contained therein. At various times during the following discussion, certain formation and formation fluid properties will be referred to in a general sense. Such formation properties include, but are not limited to: pressure, permeability, viscosity, mobility, spherical mobility, porosity, saturation, coupled compressibility porosity, skin damage, and anisotropy. Such formation fluid properties include, but are not limited to: viscosity, compressibility, flowline fluid compressibility, density, resistivity, composition and bubble point.

Permeability is the ability of a rock formation to allow hydrocarbons to move between its pores, and consequently into a wellbore. Fluid viscosity is a measure of the ability of the hydrocarbons to flow, and the permeability divided by the viscosity is termed “mobility.” Porosity is the ratio of void space to the bulk volume of rock formation containing that void space. Saturation is the fraction or percentage of the pore volume occupied by a specific fluid (e.g., oil, gas, water, etc.). Skin damage is an indication of how the mud filtrate or mud cake has changed the permeability near the wellbore. Anisotropy is the ratio of the vertical and horizontal permeabilities of the formation.

Resistivity of a fluid is the property of the fluid which resists the flow of electrical current. Bubble point occurs when a fluid's pressure is brought down at such a rapid rate, and to a low enough pressure, that the fluid, or portions thereof, changes phase to a gas. The dissolved gases in the fluid are brought out of the fluid so gas is present in the fluid in an undissolved state. Typically, this kind of phase change in the formation hydrocarbons being tested and measured is undesirable, unless the bubblepoint test is being administered to determine what the bubblepoint pressure is.

In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.

Referring toFIG. 1, a formation tester tool10is shown as a part of bottom hole assembly6which includes an MWD sub13and a drill bit7at its lower most end. Bottom hole assembly6is lowered from a drilling platform2, such as a ship or other conventional platform, via drill string5. Drill string5is disposed through riser3and well head4. Conventional drilling equipment (not shown) is supported within derrick1and rotates drill string5and drill bit7, causing bit7to form a borehole8through the formation material9. The borehole8penetrates subterranean zones or reservoirs, such as reservoir11, that are believed to contain hydrocarbons in a commercially viable quantity. It should be understood that formation tester10may be employed in other bottom hole assemblies and with other drilling apparatus in land-based drilling, as well as offshore drilling as shown inFIG. 1. In all instances, in addition to formation tester10, the bottom hole assembly6contains various conventional apparatus and systems, such as a down hole drill motor, rotary steerable tool, mud pulse telemetry system, measurement-while-drilling sensors and systems, and others well known in the art.

It should also be understood that, even though formation tester10is shown as part of drill string5, the embodiments of the invention described below may be conveyed down borehole8via wireline technology, as is partially described above, or via a rotary steerable drill string that is well known to one skilled in the art. Further context and examples for methods of use of the embodiments described herein may be obtained from U.S. patent application Ser. No. 11/133,712 entitled “Formation Tester Tool Assembly and Methods of Use,” having U.S. Express Mail Label Number EV 303483552 US; U.S. patent application Ser. No. 11/132,475 entitled “Methods for Using a Formation Tester,” having U.S. Express Mail Label Number EV 303483362 US; and U.S. patent application entitled “Methods for Measuring a Formation Supercharge Pressure,” having U.S. patent application Ser. No. 11/069,649; each hereby incorporated herein by reference for all purposes.

Referring now toFIGS. 2A-C, portions of the formation tester tool10are shown.FIG. 2Aillustrates the electronics module20, which may include battery packs, various circuit boards, capacitors banks and other electrical components.FIG. 2Bshows fillport assembly22having fillports24,26for adding or removing hydraulic or other fluids to the tool10. Below fillport assembly22is hydraulic insert assembly30. Below assembly30is the hydraulic connectors ring assembly32, which acts as a hydraulic line manifold.FIG. 2Cillustrates the portion of tool10including equalizer valve60, formation probe assembly50(or probe assembly200), draw down shutoff valve assembly74, draw down piston assemblies70,72and stabilizer36. Also included is pressure instrument assembly38, including the pressure transducers used by formation probe assemblies50,200.

Referring toFIGS. 3A-Bnow, the enlarged portions of tool10shown inFIGS. 2B-Care shown. Hydraulic insert assembly30, probe retract accumulator424, equalizer valve60, formation probe assembly50, draw down shutoff valve74and draw down piston assemblies70,72can be seen in greater detail. Equalizer valve60may be any of a variety of equalizer valves known to one skilled in the art.

Referring now toFIG. 4, formation probe assembly50is disposed within probe drill collar12, and covered by probe cover plate51. Also disposed within probe collar12is an equalizer valve60having a valve cover plate61. Adjacent formation probe assembly50and equalizer valve60is a flat136in the surface17of probe collar12. Probe drill collar12includes a draw down cover76for protecting other devices associated with the formation probe assembly50mounted in the collar12, such as draw down pistons (not shown).

As best shown inFIG. 5, it can be seen how formation probe assembly50and equalizer valve60are positioned in probe collar12. Formation probe assembly50and equalizer valve60are mounted in probe collar12just above the flowbore14. Flowbore14may be deviated from the center longitudinal axis12aof probe collar12, or from other portions14b,14cof flowbore14, to accommodate at least formation probe assembly50. For example, inFIG. 5, flowbore portion14ais offset radially from the longitudinal axis12a, and also from the flowbore portion14bvia transition flowbore portion14c. Also shown are draw down piston assemblies70,72and draw down shutoff valve74.

The details of a first embodiment of formation probe assembly50are best shown inFIG. 6A-6B. InFIG. 6A, formation probe assembly50is retained in probe collar12by threaded engagement with collar12and also by cover plate51. Formation probe assembly50generally includes stem92, a generally cylindrical threaded adapter sleeve94, piston96adapted to reciprocate within adapter sleeve94, and a snorkel assembly98adapted for reciprocal movement within piston96. Probe collar12includes an aperture90for receiving formation probe assembly50. Cover plate51fits over the top of formation probe assembly50and retains and protects formation probe assembly50when the formation probe assembly50is within probe collar12. Formation probe assembly50may extend and retract through aperture52in cover plate51.

Stem92includes a circular base portion105with an outer flange106having stem holding screw97(shown inFIG. 6B) for retaining stem92in aperture90. Extending from base105is a tubular extension107having central passageway108. The end of extension107includes internal threads at109. Central passageway108is in fluid connection with fluid passageway91(not shown, but seen schematically inFIG. 9) that connects to fluid passageway93(not shown, but seen schematically inFIG. 9) leading to other portions of tool10, including equalizer valve60.

Adapter sleeve94includes inner end111that engages flange106of stem92. Adapter sleeve94is secured within aperture90by threaded engagement with collar12at segment110. The outer end112of adapter sleeve94may extend to be substantially flushed with recess55formed in collar12for receiving cover plate51. Outer end112also includes flange158for engaging recess162of cover plate51. Adapter sleeve94includes cylindrical inner surface113having reduced diameter portions114,115. A seal116is disposed in surface114.

Piston96is slidingly retained within adapter sleeve94and generally includes cylindrical outer surface141having an increased diameter base portion118. A seal143is disposed in increased diameter portion118. Just below base portion118, piston96may rest on flange106of stem base portion105while formation probe assembly50is in the fully retracted position as shown inFIG. 6A. Piston96may also include cylindrical inner surface145having reduced diameter portion147. Piston96may further include central bore121having a bore surface120and extending through upper extending portion119.

Referring toFIG. 6B, at the top of extending portion119of piston96is a seal pad180. Seal pad180may be donut-shaped with a curved outer sealing surface183and central aperture186. However, seal pad180may include numerous other geometries as is known in the art, or, for example, as is seen in U.S. patent application Ser. No. 10/440,835 entitled “MWD Formation Tester.” Base surface185of seal pad180may be coupled to a skirt182. Seal pad180may be bonded to skirt182, or otherwise coupled to skirt182, such as by molding seal pad180onto skirt182such that the seal pad material fills grooves or holes in skirt182, as can be seen in U.S. patent application Ser. No. 10/440,835. Skirt182is detachably coupled to extending portion119by way of threaded engagement with surface120of central bore121(seeFIG. 6A), or other means of engagement, such as a pressure fit with central bore surface120. Because the seal pad/skirt combination may be detachable from extending portion119, it is easily replaced in the field. Alternatively, seal pad180may be coupled directly to extending portion119without using a skirt.

Seal pad180is preferably made of an elastomeric material. Seal pad180seals and prevents drilling fluid or other contaminants from entering the formation probe assembly50during formation testing. More specifically, seal pad180may seal against the filter cake that may form on a borehole wall. Typically, the pressure of the formation fluid is less than the pressure of the drilling fluids that are injected into the borehole. A layer of residue from the drilling fluid forms a filter cake on the borehole wall and separates the two pressure areas. Seal pad180, when extended, may conform its shape to the borehole wall and/or mud cake and forms a seal through which formation fluids can be collected and/or formation properties measured.

In an alternative embodiment of the seal pad180, the seal pad180may have an internal cavity such that it can retain a volume of fluid. A fluid may be pumped into the seal pad cavity at variable rates such that the pressure in the seal pad cavity may be increased and decreased. Fluids used to fill the seal pad may include hydraulic fluid, saline solution or silicone gel. By way of example, the seal pad may be emptied or unpressured as the probe extends to engage the borehole wall. Depending on the contour of the borehole wall, the seal pad may be pressured by filling the seal pad with fluid, thereby conforming the seal pad surface to the contour of the borehole wall and providing a better seal.

In yet another embodiment of the seal pad, the seal pad may be filled, either before or after engagement with the borehole wall, with an electro-rheological fluid. An electro-rheological fluid may be an insulating oil containing a dispersion of fine solid particles, for example, 5 μm to 50 μm in diameter. Such an electro-rheological fluid is well known in the art. When subjected to an electric field, theses fluids develop an increased shear stress and an increased static yield stress that make them more resistant to flow. This change of fluid properties is evident, for example, as an increase in viscosity, most notably the plastic viscosity, when the electric field is applied. The fluid in the seal pad may effectively become semi-solid. The semi-solid effect is reversed when the fluid is no longer subjected to the electric field. In the absence of the electric field, the electro-rheological fluid that may fill the seal pad becomes less viscous, causing the seal pad to conform to the contour of a borehole wall. Once the seal pad has conformed to the borehole wall, an electric field may be applied to the electro-rheological fluid inside the seal pad, causing an increase in fluid viscosity, a stiffening of the seal pad, and a better seal.

Still referring toFIG. 6B, snorkel assembly98includes a base portion125, a snorkel extension126, and a central passageway127extending through base125and extension126. Base portion125may include a cylindrical outer surface122and inner surface124. Extension126may include a cylindrical outer surface128and inner surface138. Disposed inside the top of extension126is a screen100. Screen100is a generally tubular member having a central bore132extending between a fluid inlet end131and fluid outlet end135. Screen100further includes a flange130adjacent to fluid inlet end131and an internally slotted segment133having slots134. Between slotted segment133and outlet end135, screen100includes threaded segment137for threadedly engaging snorkel extension126.

Threaded to the bottom of base portion125of snorkel98is scraper tube keeper152having a circular base portion154with flange153, a tubular extension156having a central passageway155and a central aperture157for receiving stem extension107. Just below scraper tube keeper152is retainer ring159, which provides seated engagement with snorkel98such that the movement of snorkel98is limited in the retract direction. Scraper tube keeper152supports scraper tube150when scraper tube150is in the retracted position shown inFIG. 6B. Scraper tube150having central passageway151extends up from scraper tube keeper152and through passageway127of snorkel98. Coupled at the top of scraper tube150is scraper or wiper160. Scraper160is threadedly engaged with scraper tube150at threaded segment161. Scraper160is a generally cylindrical member including scraper plug portion163, central bore164and apertures166that are in fluid communication with central bore164. Scraper160is disposed within central bore132of screen100and may be actuated back and forth (or reciprocal) between screen inlet end131and outlet end135. When scraper tube150and scraper160are in their retracted positions, as shown inFIG. 6B, apertures166are in fluid communication with fluid outlet end135of screen100, thereby allowing fluid to pass from screen100, through scraper bore164, and into central passageway155of scraper tube150. Scraper or wiper160is thus configured to be a moveable or floating scraper.

In an alternative embodiment of the scraper160within the screen100, the actuation of scraper160may be a rotational movement around the longitudinal axis of scraper160. This rotational movement may be in place of the reciprocal movement, or in addition to the reciprocal movement.

As shown inFIG. 6B, a connector176is disposed in aperture178of probe collar12, just beneath inner end111of sleeve94. Contact lead175electrically connects connector176, via a wire, to a contact assembly (not shown) preferably disposed in flange106of stem base portion105so that the contact assembly can be in direct contact with base portion118of piston96.FIGS. 8A-8Bshow the details of connector176and contact assembly310, with the surrounding structures shown in a more general fashion such that the different parts of formation probe assembly50agenerally correspond with similar parts of formation probe assembly50ofFIGS. 6A-6B.

Referring now toFIG. 8B, wire300leads into contact assembly310. Contact assembly310generally includes housing316having aperture317, a conductive contact body312having a flange314and a central bore319, a stripped end318of wire300extending into and soldered to bore319, a non-conductive spring support322, and wave springs324. The flange314of body312is disposed between the upper portion of housing316and the lower portion of spring support322. Disposed between spring support322and flange314are wave springs324, which are supported by lower plate326and upper plate328. Springs324provide an upward force on flange314such that top surface313of body312extends out of aperture317such that top surface313protrudes out of cavity307. As formation probe assembly50ais retracting, piston96acomes into contact with and presses downward on surface313of body312, causing springs324to compress and bottom surface315to move downward into space324. When piston96acontacts surface313of body312, an electric circuit is completed to ground (not shown) through piston96a, providing a signal to the tool electronics (not shown) that formation probe assembly50ahas been fully retracted. After piston96amakes contact with surface313of body312, piston96acontinues to travel until making contact with base portion105aof stem92a. Heat shrink320is shrunk in place over wire300for mechanical protection.

Referring now toFIGS. 6A and 6B, formation probe assembly50is assembled such that piston base118is permitted to reciprocate along surface113of adapter sleeve94, and piston outer surface141is permitted to reciprocate along surface114. Similarly, snorkel base125is disposed within piston96and is adapted for reciprocal movement along surface147while flange153of scraper tube keeper152reciprocates along surface145. Snorkel extension126is adapted for reciprocal movement along piston surface120. Central passageway127of snorkel98is axially aligned with tubular extension107of stem92, scraper tube keeper152, scraper tube150, scraper160and with screen100. Formation probe assembly50is reciprocal between a fully retracted position, as shown inFIG. 6A, and a fully extended position, as shown inFIG. 6B. Also, scraper tube150is reciprocal between a fully retracted position, as shown inFIGS. 6A-6B, and a fully extended position, as is illustrated by a similar scraper tube278inFIGS. 7A-7E. When scraper tube150is fully retracted, fluid may be communicated between central passageway108of extension107, passageway155of scraper tube keeper152, passageway151of scraper tube150, scraper bore164, scraper apertures166, screen100, and the surrounding environment15.

With reference toFIGS. 6A and 6B, the operation of formation probe assembly50will now be described. Formation probe assembly50is normally in the retracted position. Formation probe assembly50remains retracted when not in use, such as when the drill string is rotating while drilling if formation probe assembly50is used for an MWD application, or when the wireline testing tool is being lowered into borehole8if formation probe assembly50is used for a wireline testing application.FIG. 6Ashows formation probe assembly50in the fully retracted position, except that scraper tube150is shown in the retracted position, and scraper tube150is typically extended when formation probe assembly50is in this position, as shown inFIGS. 7A-7E.FIGS. 7A-7Fwill be referred to in describing the operation of formation probe assembly50because the structures of formation probe assembly50previously described are similar to corresponding parts of probe assembly200seen inFIGS. 7A-7F.

Formation probe assembly50typically begins in the retracted position, as shown inFIG. 6A. Upon an appropriate command to formation probe assembly50, a force is applied to base portion118of piston96, preferably by using hydraulic fluid. Piston96extends relative to the other portions of formation probe assembly50until retainer ring159engages flange153of scraper tube keeper152. This position of piston96relative to snorkel assembly98can be seen inFIG. 7B. As hydraulic fluid continues to be pumped into hydraulic fluid reservoir54, piston96and snorkel assembly98continue to move upward together. Base portion118slides along adapter sleeve surface113until base portion118comes into contact with shoulder170. After such contact, formation probe assembly50will continue to pressurize reservoir54until reservoir54reaches a certain pressure P1. Alternatively, if seal pad180comes into contact with a borehole wall before base portion118comes into contact with shoulder170, formation probe assembly50will continue to apply pressure to seal pad180by pressurizing reservoir54up to the pressure P1. The pressure P1applied to formation probe assembly50, for example, may be 1,200 p.s.i.

The continued force from the hydraulic fluid in reservoir54causes snorkel assembly98to extend such that the outer end of snorkel extension126, inlet end131of screen100and the top of scraper160extend beyond seal pad surface183through seal pad aperture186. This snorkel extending force must overcome the retract force being applied on the retract side of snorkel base portion125facing piston shoulder172. Previously, the retract force, provided by retract accumulator424and the retract valves, was greater than the extend force, thereby maintaining snorkel98in the retract position. However, the extend force continues to increase until it overcomes the retract force at, for example, 900 p.s.i. Snorkel assembly98stops extending outward when snorkel base portion125comes into contact with shoulder172of piston96. Scraper tube150and scraper160are still in the extended position, as is best shown with the snorkel assembly and piston configuration ofFIG. 7E.

Alternatively, if snorkel assembly98comes into contact with a borehole wall before snorkel base portion125comes into contact with shoulder172of piston96, continued force from the hydraulic fluid pressure in reservoir54is applied up to the previously mentioned maximum pressure. The maximum pressure applied to snorkel assembly98, for example, may be 1,200 p.s.i. Preferably, the snorkel and seal pad will contact the borehole wall before either piston96or snorkel98shoulders at full extension. Then, the force applied on the seal pad is reacted by stabilizer36, or other similar device disposed on or near probe collar12.

If, for example, seal pad180had made contact with the borehole wall16before being fully extended and pressurized, then seal pad180should seal against the mudcake on borehole wall16through a combination of pressure and seal pad extrusion. The seal separates snorkel assembly98from the mudcake, drilling fluids and other contaminants outside of seal pad180. As the snorkel assembly extends, snorkel extension126, screen inlet end131and the top of scraper160pierce the mudcake that has been sealed off, and preferably go through the entire mudcake layer and into formation9.

With screen100and scraper160extended, the piston96and snorkel98assembly configuration looks similar to the piston and snorkel configuration shown inFIG. 7E. While extending snorkel extension126into the mudcake and formation, contaminants and debris tend to gather on screen100which can affect the sampling of formation fluids. To clear the debris, which may be mudcake or other contaminants from previous sampling procedures, scraper160may be retracted after snorkel assembly98has been extended. A downward retract force is applied to scraper tube150, preferably by applying a hydraulic fluid force downward on flange177of scraper tube150. The cavity formed by scraper tube150and snorkel surface124fills with hydraulic fluid as scraper tube150moves downward, until scraper tube150bottoms out on scraper tube keeper152. As scraper160is drawn within snorkel extension126during this process, scraper160passes through screen100while also frictionally engaging screen100, thereby agitating and removing debris that has gathered on screen100. Alternatively, as previously described, debris agitation may be achieved with rotational movement of scraper160about its longitudinal axis within screen100. When scraper tube150is fully retracted, apertures166radially align with outlet end135of screen100such that fluid communication is possible between bore132of screen100and passageway151of scraper tube150. This scraper160action that removes debris is preferably performed as part of the formation probe assembly50retract sequence, as described below.

To retract formation probe assembly50, forces, or pressure differentials, may be applied to snorkel98and piston96in opposite directions relative to the extending forces. Simultaneously, the extending forces may be reduced or ceased to aid in probe retraction. A hydraulic force is applied to snorkel base portion125at shoulder172to push snorkel assembly98down until flange153of scraper tube keeper152sits on retainer ring159, thereby fully retracting snorkel assembly98. Concurrently, a hydraulic force is applied downward on piston base portion118at shoulder170until base portion118bottoms out on stem base portion105, thereby fully retracting formation probe assembly50. When piston96contacts stem base portion105, probe retract switch176is triggered as described above, signaling a successful retraction of formation probe assembly50. Scraper160may be extended to its original position at any time during retraction. When the extend pressure on the probe assembly, which provides the retract pressure for the scraper assembly because the probe assembly extend portions are hydraulically coupled to the scraper assembly retract portions, falls below the extend pressure on the scraper assembly, scraper160is extended.

Another embodiment of the present invention is shown inFIGS. 7A-7F. Probe collar202having flowbore14ahouses telescoping formation probe assembly200. Probe assembly200, as compared to formation probe assembly50, extends to reach a borehole wall that is further displaced from collar202. Such borehole walls that may be displaced further from collar12may be found in washed out portions of a well, irregular holes in the well, wells drilled with hole openers or near bit reamers or large wells drilled with bi-center bits. Telescoping probe assembly200is useful in reaching a borehole wall in these types of wells.

Telescoping probe assembly200generally includes stem plate210, stem212, a generally cylindrical threaded adapter sleeve220, an outer piston230adapted to reciprocate within adapter sleeve220, a piston240adapted to reciprocate within outer piston230, and a snorkel assembly260adapted for reciprocal movement within piston240. Probe collar202includes an aperture204for receiving telescoping formation probe assembly200. Cover plate206fits over the top of probe assembly200and retains and protects assembly200within probe collar202. Formation probe assembly200is configured to extend through aperture208in cover plate206.

Referring first toFIG. 7A, adapter sleeve220includes inner end221near the bottom207of aperture204. Adapter sleeve220is secured within aperture204by threaded engagement with collar202at segment209. The outer end223of adapter sleeve220extends to be substantially flushed with opening205of aperture204formed in collar202. Outer end223includes flanges225for engaging cover plate206. Adapter sleeve220includes cylindrical inner surface227having reduced diameter portion226. A seal229is disposed in surface226.

Referring next toFIG. 7B, stem plate210includes a circular base portion213with an outer flange214. Extending from base213is a short extension216. Extending through extension216and base213is a central passageway218for receiving the lower end215of stem212having central passageway203. Lower end215threadedly engages stem plate passageway218. Central passageway218is in fluid connection with fluid passageway91(not shown, but seen schematically inFIG. 9) that connects to fluid passageway93(not shown, but seen schematically inFIG. 9) leading to other portions of tool10, including equalizer valve60. Stem212extends up through the center of probe assembly200. Disposed about stem212is outer stem219. Threadedly engaged at the top of outer stem219is outer stem capture screw222having central bore224.

Referring again toFIG. 7B, outer piston230is slidingly retained within adapter sleeve220and generally includes cylindrical outer surface232having an increased diameter base portion234. A seal235is disposed in increased diameter portion234. Outer piston230also includes cylindrical inner surface236having reduced diameter portions237,238at upper extending portion233. A seal239is disposed in surface237.

Referring now toFIG. 7C, piston240is slidingly retained within outer piston230and generally includes cylindrical outer surface242having an increased diameter base portion244. A seal245is disposed in increased diameter portion244. Just below base portion244, piston240rests on capture sleeve254which is engaged with base portion234of outer piston230. Retainer ring256is engaged at the bottom of capture sleeve254and holds the capture sleeve in position. Piston240also includes cylindrical inner surface246having reduced diameter portion248. Piston240further includes central bore249having bore surface241and extending through upper extending portion250.

At the top of extending portion250of piston240is a seal pad280. As shown inFIGS. 7A-7F, seal pad280may be donut-shaped with a curved outer surface283and central aperture286. However, seal pad280may include numerous other geometries as is known in the art, or, for example, as is seen in U.S. patent application Ser. No. 10/440,835 entitled “MWD Formation Tester.” Base surface285of seal pad280may be coupled to a skirt282. Seal pad280may be bonded to skirt282, or otherwise coupled to skirt282, such as by molding seal pad280onto skirt282such that the seal pad material fills grooves or holes in skirt282, as can be seen in U.S. patent application Ser. No. 10/440,835. Skirt282is detachably coupled to extending portion250by way of threaded engagement with surface241of central bore249, or other means of engagement, such as a pressure fit with central bore surface241. Because the seal pad/skirt combination is detachable from extending portion250, it is easily replaced in the field. Alternatively, seal pad280may be coupled directly to extending portion250without using a skirt. Other characteristics of seal pad280, such as seal pad material and the way seal pad280functions, are similar to the previously described seal pad180.

Referring now toFIG. 7D, snorkel260includes a base portion262, a snorkel extension266, and a central passageway264extending through base262and extension266. Base portion262includes a cylindrical outer surface268and inner surface269. Extension266includes a cylindrical outer surface263and inner surface265. Disposed inside the top of extension266is a screen290, best shown inFIG. 7F. Screen290is a generally tubular member having a central bore292extending between a fluid inlet end294and fluid outlet end296. Screen290further includes a flange298adjacent to fluid inlet end294and an internally slotted segment293having slots295. Between slotted segment293and outlet end296, screen290includes threaded segment297for threadedly engaging snorkel extension266.

Threaded to the bottom of base portion262of snorkel260is scraper tube keeper270having a circular base portion272and retaining edge273, a tubular extension274having a central passageway275and a central aperture271for receiving outer stem219. Outer stem219includes central passageway243. A retainer ring277is radially aligned and engageable with retaining edge273, which limits the movement of snorkel260in the retract direction. After snorkel260has been extended, retainer ring277is disposed below scraper tube keeper270in piston surface246, as can be seen inFIG. 7E. Scraper tube keeper270supports scraper tube278when scraper tube278is in the retracted position shown inFIG. 7F, and isolates the hydraulic fluid reservoir formed by tubular extension274and snorkel surface269. Scraper tube278having central passageway279is slidingly retained above scraper tube keeper270in passageway264of snorkel260. Coupled at the top of scraper tube278is scraper288. Scraper288is threadedly engaged with scraper tube278at threaded segment281. Scraper288is a generally cylindrical member including scraper plug portion284, central bore287and apertures289that are in fluid communication with central bore287. Scraper288is disposed within central bore292of screen290and is reciprocal between screen inlet end294and outlet end296; alternatively, as previously described, scraper288may be rotatable within screen290. When scraper tube278and scraper288are in their retracted positions, as shown inFIG. 7F, apertures289are in fluid communication with fluid outlet end296of screen290, thereby allowing fluid to pass from screen290, through scraper bore287, and into central passageway279of scraper tube278.

Referring back toFIG. 7B, a probe retract switch connector276is disposed in aperture278of probe collar202, just beneath inner end221of sleeve220. The details of switch connector276are similar to the previously described switch176, above, with reference toFIGS. 8A-8B. Although not shown, switch and connector276are electrically coupled to a contact assembly disposed in stem base portion213. The contact assembly contacts piston240when piston240is bottomed out on stem base portion213indicating to the tool electronics that probe assembly200is fully retracted.

Formation probe assembly200is assembled such that outer piston base234is permitted to reciprocate along surface227of adapter sleeve220, and outer piston surface232is permitted to reciprocate along surface226. Similarly, piston base portion244is permitted to reciprocate along outer piston inner surface236, and piston surface242is permitted to reciprocate along outer piston surface237. Snorkel base portion262is disposed within piston240and is adapted for reciprocal movement along surface248while retaining edge273of scraper tube keeper270reciprocates between retainer ring277and decreased diameter portion248. Snorkel extension266is adapted for reciprocal movement along piston surface241. Central passageway264of snorkel260is axially aligned with stem212, outer stem219, scraper tube keeper270, scraper tube278, scraper288and with screen290. Formation probe assembly200is reciprocal between a fully retracted position, as shown inFIG. 7A, and a fully extended position, as shown inFIG. 7F. Also, scraper tube278is reciprocal between a fully extended position, as shown inFIGS. 7A-7E, and a fully retracted position, as is illustrated inFIG. 7F. When scraper tube278is fully retracted, fluid may be communicated between central passageway203of stem212, passageway243of outer stem219, passageway275of scraper tube keeper270, passageway279of scraper tube278, bore287of scraper288, scraper apertures289, screen290, and the surrounding environment15.

With reference toFIGS. 7A-7F, the operation of formation probe assembly200will now be described. Formation probe assembly200typically begins in the retracted position, as shown inFIG. 7A. Assembly200remains retracted when not in use, such as when the drill string is rotating while drilling if assembly200is used for an MWD application, or when the wireline testing tool is being lowered into borehole8if assembly200is used for a wireline testing application.FIG. 7Ashows assembly200in the fully retracted position, with scraper tube278in the extended position.

Upon an appropriate command to probe assembly200, a force is applied to base portion234of outer piston230, preferably by using hydraulic fluid. Outer piston230raises relative to adapter sleeve220, with outer piston base portion sliding along sleeve surface227. Retainer ring256and capture sleeve254force piston240upward along with outer piston230by pressing on piston base portion244. As seen inFIG. 7B, snorkel260remains seated on stem plate210while outer piston230and piston240begin to rise, until retainer ring277contacts retaining edge273of scraper tube keeper270. At this point, the upward hydraulic force continues to be applied to the reciprocal parts of assembly200, and fluid reservoir334enlarges and fills until outer piston base portion234seats on adapter sleeve shoulder332, as shown inFIG. 7C. Then hydraulic fluid is directed into reservoir336, causing piston240and snorkel260to extend out, with piston base portion244sliding along outer piston surface236. Finally, piston base portion244seats on outer piston shoulder342, as shown inFIG. 7D. Once again, typically, snorkel260and seal pad280(FIG. 7C) contact the borehole wall prior to reaching full extension, as previously described. The tool stabilizer, or other such device, will react the probe extension force.

Before reaching the position shown inFIG. 7D, seal pad280is preferably engaged with the borehole wall (not shown). To form a seal with seal pad280, probe assembly200will continue to pressurize the reservoirs334,336until the reservoirs reach a maximum pressure. Alternatively, if seal pad180comes into contact with the borehole wall before probe assembly200is fully extended, probe assembly200will continue to apply pressure to seal pad280up to the previously mentioned maximum pressure. The maximum pressure applied by probe assembly200, for example, may be 1,200 p.s.i.

As hydraulic fluid continues to be pumped through reservoirs334,336, snorkel260slides along surfaces248,241as hydraulic fluid is directed into reservoir338and this snorkel extend force increases. This snorkel extending force must overcome the retract force being applied on the retract side of snorkel base portion262facing piston shoulder352. Previously, the retract force, provided by retract accumulator424and the retract valves, was greater than the extend force, thereby maintaining snorkel260in the retract position. However, the extend force continues to increase until it overcomes the retract force at, for example, 900 p.s.i. Snorkel base portion262finally seats on piston shoulder352, as shown inFIG. 7E. Snorkel260has extended such that the outer end of snorkel extension266, inlet end294of screen290and the top of scraper288extend beyond seal pad surface283through seal pad aperture286. Scraper tube278and scraper288are still in the extended position, as seen inFIG. 7E. If seal pad280is engaged with the borehole wall, snorkel extension266, screen inlet end294and the top of scraper288pierce the mudcake that has been sealed off, and preferably go through the entire mudcake layer and into formation9.

As previously described, extending snorkel extension266into the mudcake and formation causes contaminants and debris to gather on screen290, which can affect the sampling of formation fluids. Floating scraper288is used to clear the debris in a similar fashion to that described with respect to formation probe assembly50. A downward force is applied to scraper tube278, preferably by applying a hydraulic fluid force downward on flange372of scraper tube278. The cavity formed by scraper tube278and inner snorkel surface269fills with hydraulic fluid as scraper tube278moves downward, until tube flange372seats on scraper tube keeper270. As scraper288is drawn within snorkel extension266during this process, scraper288passes through screen290, agitating and removing debris that has gathered on screen290through frictional engagement between scraper288and screen290, as previously described. Also previously described was an alternative embodiment including a rotating screen290, equally applicable here. When scraper tube278is fully retracted, apertures289radially align with screen outlet end296such that fluid communication is possible between screen bore292and passageway279of scraper tube278. This scraper288action that removes debris is preferably performed as part of the formation probe assembly200retract sequence, as described below.

To retract probe assembly200, forces, or pressure differentials, may be applied to probe assembly200in opposite directions relative to the extending forces. Simultaneously, the extending forces may be reduced or ceased to aid in probe retraction. First, and preferably, a pressure differential is applied across flange372of scraper tube278by increasing the hydraulic fluid pressure on the bottom of flange372. This extends scraper tube278until scraper288is fully extended once again, wiping screen290clean as scraper288passes through it. Next, a hydraulic force is applied to snorkel base portion262at shoulder352to push snorkel assembly260down until retaining edge273of scraper tube keeper270sits on retainer ring277, thereby fully retracting snorkel assembly260. Next, a hydraulic force is applied downward on piston base portion244at shoulder342until base portion244seats on capture sleeve254and retainer ring256adjacent outer piston base portion234. From this position, a hydraulic fluid is inserted at adapter sleeve shoulder332onto outer piston base portion234to force outer piston230downward. Outer piston230then seats on bottom207of aperture204, and the piston240/snorkel260assembly seats on stem plate210, thereby fully retracting probe assembly200. When piston240contacts stem plate210, probe retract switch276is triggered as described above, signaling a successful retraction of assembly200.

It is noted that formation probe assembly50may only extend the outer end of piston extending portion119past the outer end of sleeve94a distance that is less than the length of piston96. The length of piston96is defined as the distance between the uppermost end of extending portion119and the lowermost end of base portion118. In comparison, probe assembly200may extend the outer end of piston upper portion250past the outer end of sleeve220a distance that exceeds the length of piston240. Therefore, the telescoping feature of probe assembly200, i.e., the concentric pistons230,240, allows seal pad280to engage a borehole wall that is significantly further from collar202than the length of piston240.

Referring now toFIG. 14, an example of how the probe assemblies may be used to test a formation will be described. The test sequence700may begin (box702) upon a command to the tool10from the surface of the borehole, for example, or from embedded tool software. In a first embodiment, piston96and seal pad180may be extended (box704). In a further embodiment, piston230may be extended (box703) to provide the telescopic effect previously described. The borehole wall is contacted by seal pad180(box706). Next, a volume surrounding snorkel98is sealed (box708). In a further embodiment, seal pad180may be filled with a fluid (box707), as previously described. Continuing with the sequence700, snorkel98may be extended (box710), and the borehole wall contacted by snorkel98(box712). Scraper160may now be retracted (box714), causing agitation and removal of contaminants from snorkel98. A formation property may then be measured (box716). In a further embodiment, contaminants may be filtered (box715), such as by a screen100. After measuring a formation property, snorkel98is retracted (box718), piston96and seal pad180are retracted (box720), and scraper160is extended (box722). The extension of scraper160may also serve to remove contaminants from snorkel98. Sequence700ends (box724) with a formation property having been measured for uses further described herein.

In an alternative embodiment of tool10, formation probe assemblies50,200may be located elsewhere in the tool. Referring now toFIG. 3B, formation probe assembly50may instead be disposed in blade37of stabilizer36. Equalizer valve60, shutoff valve74and draw down pistons70,72may remain in the same position as shown inFIG. 3B, although it is preferred that they be in closer proximity to formation probe assembly50, and therefore may be moved closer to stabilizer36. Locating formation probe assemblies50,200in stabilizer blade37allows the assemblies to be placed closer to the borehole wall while still mounted in a robust portion of the tool. Further, the other blades of stabilizer36may be used to back up formation probe assemblies50,200as they extend out and pressure up against the borehole wall.

Even if formation probe assemblies50,200are not disposed in stabilizer36, the blades of stabilizer36are preferably used to back up the extending formation probe assemblies50,200. To provide a sufficient sealing force for the probe seal pad, a reactive force must be applied to the tool to counter the force of the extending probe. Alternatively, if a stabilizer is not used, centralizing pistons such as those illustrated and described in U.S. patent application Ser. No. 10/440,593, filed May 19, 2003 and entitled “Method and Apparatus for MWD Formation Testing,” hereby incorporated by reference for all purposes, may be used.

With respect to any of the probe assembly embodiments described above, a probe assembly position indicator may be included in the probe assembly to measure the distance that the probe assembly has extended from its fully retracted position. Numerous sensors may be used to detect the position of the probe assembly as it extends. In one embodiment, the probe assembly position indicator may be a measure of the volume of hydraulic fluid used to extend the probe assembly. If the probe assembly is configured to use hydraulic fluid and pressure differentials to extend, as is described in the embodiments above, the volume of fluid pumped into the probe assembly may be measured. With known diameters for the adapter sleeves and pistons, the distance that the pistons have extended may be calculated using the volume of fluid that has been pumped into the probe assembly. To make this measurement more accurate, certain characteristics of the probe assembly may be accounted for, such as seal pad compression as it compresses against the borehole wall.

In another embodiment of the probe assembly position indicator, an optical or acoustic sensor may be disposed in the probe assembly, such as in an aperture formed in the piston surface141of formation probe assembly50, or piston surface242of probe assembly200. The optical or acoustic sensor may measure the distance the piston moves from a known reference point, such as the piston position when the probe assembly is fully retracted. Such devices are well known to one skilled in the art.

In yet another embodiment, a potentiometer, resistance-measuring device or other such device well known to one skilled in the art may be used to detect movement of the reciprocating portions of the probe assemblies through electrical means. The potentiometer or resistance-measuring device may measure voltage or resistance, and such information can be used to calculate distance.

The distance measurement gathered from the probe position indicator may be used for numerous purposes. For example, the borehole caliper may be calculated using this measurement, thereby obtaining an accurate measurement of the borehole diameter. Alternatively, multiple probes may be spaced radially around the drill string or wireline instrument, and measurements may be taken with the multiple probes to obtain borehole diameter and shape. Having an accurate borehole caliper measurement allows the driller to know where borehole breakout or collapse may be occurring. The caliper measurement may also be used to help correct formation evaluation sensors. For example, resistivity measurements are affected by borehole size. Neutron corrections applied to a neutron tool are also affected, as well as density corrections applied to a density tool. Other sensor tools may also be affected. An accurate borehole caliper measurement assists in correcting these tools, as well as any other drilling, production and completion process that requires borehole size characteristics, such as cementing.

In another embodiment, the probe position indicator may be used to correct for probe flow line volume changes. Flow lines, such as flow lines91,93inFIGS. 6A,6B and9, are susceptible to volume changes as the probe seal pad compresses and decompresses. Particularly, when the seal pad is engaged with the borehole wall and a formation test is in progress, the pressure from drawing down the formation fluids causes the seal pad to compress and the flow line volume to increase. The flow line volume is used in several formation calculations, such as mobility; permeability may then be calculated using formation fluid viscosity and density. To correct for this volume change and obtain an accurate flow line volume measurement, probe positioning may be used. Further, although the full flow line volume is known, if the probe does not fully extend before engaging the borehole wall, only a portion of the flow line volume is used and that quantity may not be known. Therefore, the probe position may be used to correct for the portion of the flow line volume that is not being used.

The embodiments of the position indicator described above may also be applied to the draw down piston assemblies, described in more detail below, for knowing where in the cylinder the draw down piston is located, and how the piston is moving. Volume and diameter calculations may be used to obtain distance moved, or sensors may be used as described above. Thus, the exact distance the piston has moved may be obtained, rather than relying on the volume of fluid used to actuate the piston as an indication of distance moved. Further, the steadiness of the draw down may be obtained from the position indicator. The rate may be calculated from the distance measured, and the steadiness of the rate may be used to correct other measurements.

For example, to gain a better understanding of the formation's permeability or the bubble point of the formation fluids, a reference pressure may be chosen to draw down to, and then the distance the draw down piston moved before that reference pressure was reached may be measured by the draw down piston position indicator. If the bubble point is reached, the distance the piston moved may be recorded and sent to the surface, or to the software in the tool, so that the piston may be commanded to move less and thereby avoid the bubble point.

Sensors intended for other purposes may also be disposed in the probe assemblies. For example, a temperature sensor, known to one skilled in the art, may be disposed on the probe assembly for taking annulus or formation temperature. In one embodiment, the temperature sensor may be placed in the snorkel extensions126,266. In the probe assembly retracted position, the sensor would be adjacent the annulus environment, and the annulus temperature could be taken. In the probe assembly extended position, the sensor would be adjacent the formation, allowing for a formation temperature measurement. Such temperature measurements could be used for a variety of reasons, such as production or completion computations, or evaluation calculations such as permeability and resistivity. These sensors may also be placed adjacent the probe assemblies, such as in the stabilizer blades or centralizing pistons.

Referring back toFIGS. 3B and 5, it can be seen that probe collar12also houses draw down piston assemblies70,72and draw down shutoff valve assembly74. Referring now toFIG. 11, draw down piston assembly70generally includes annular seal502, piston506, plunger510and endcap508. Piston506is slidingly received in cylinder504and plunger510, which is integral with and extends from piston506, is slidingly received in cylinder514. InFIG. 11, piston506is in its drawn down position, but is typically biased to its uppermost or shouldered position at shoulder516. A bias spring (not shown) biases piston506to the shouldered position, and is disposed in lower cylinder portion504bbetween piston506and endcap508. Separate hydraulic lines (not shown) interconnect with cylinder504above and below piston506in portions504a,504bto move piston506either up or down within cylinder504as described more fully below. Plunger510is slidingly disposed in cylinder514coaxial with cylinder504. Cylinder512is the upper portion of cylinder514that is in fluid communication with the longitudinal passageway93(seen schematically inFIG. 9) that interconnects with draw down shutoff valve assembly74, draw down piston72, formation probe assembly50,200and equalizer valve60. Cylinder512is flooded with drilling fluid via its interconnection with passageway93. Cylinder514is filled with hydraulic fluid beneath seal513via its interconnection with hydraulic circuit400.

Endcap508houses a contact switch (not shown) having a contact that faces toward piston506. A wire515is coupled to the contact switch. A plunger511is disposed in piston506. When drawdown of piston assembly70is complete, as shown inFIG. 11, piston506actuates the contact switch by causing plunger511to engage the contact of the contact switch, which causes wire515to couple to system ground via the contact switch to plunger511to piston506to endcap508which is in communication with system ground (not shown).

Referring toFIG. 12, a second draw down piston assembly72is shown. Draw down piston72is similar to piston70, with the most notable difference being that the draw down volume is greater and the assembly does not include a bias spring. Draw down piston assembly72generally includes annular seal532, piston536, plunger540and endcap538. Piston536is slidingly received in cylinder534and plunger540, which is integral with and extends from piston536, is slidingly received in cylinder544. Plunger540and cylinder544have greater diameters than the corresponding portions of piston70. InFIG. 12, piston536is in its drawn down position, but is typically maintained at its uppermost or shouldered position at shoulder546by hydraulic force. Separate hydraulic lines (not shown) interconnect with cylinder534above and below piston536in portions534a,534bto move piston536either up or down within cylinder534as described more fully below. Plunger540is slidingly disposed in cylinder544coaxial with cylinder534. Cylinder542is the upper portion of cylinder544that is in fluid communication with the longitudinal passageway93(seen schematically inFIG. 9) that interconnects with draw down shutoff valve assembly74, draw down piston70, formation probe assembly50,200and equalizer valve60. Cylinder542is flooded with drilling fluid via its interconnection with passageway93. Cylinder544is filled with hydraulic fluid beneath seal543via its interconnection with hydraulic circuit400.

Endcap538houses a contact switch548having a contact550that faces toward piston536. A wire545is coupled to contact switch548. A plunger541is disposed in piston536. When drawdown of piston assembly72is complete, as shown inFIG. 12, piston536actuates contact switch548by causing plunger541to engage contact550, which causes wire545to couple to system ground via contact switch548to plunger541to piston536to endcap538which is in communication with system ground (not shown).

It will be understood that the draw down pistons may vary in size such that their volumes vary. The pistons may also be configured to draw down at varying pressures. The embodiment just described includes two draw down piston assemblies, but the formation tester tool may include more or less than two.

The hydraulic circuit400used to operate formation probe assemblies50,200, equalizer valve60and draw down pistons70,72is shown inFIG. 9. A microprocessor-based controller402is electrically coupled to all of the controlled elements in the hydraulic circuit400illustrated inFIG. 9, although the electrical connections to such elements are conventional and are not illustrated other than schematically. Controller402is located in electronics module20, shown inFIG. 2A, although it could be housed elsewhere in tool10or bottom hole assembly6. Controller402detects the control signals transmitted from a master controller401housed in the MWD sub13of the bottom hole assembly6which, in turn, receives instructions transmitted from the surface via mud pulse telemetry, or any of various other conventional means for transmitting signals to downhole tools.

When controller402receives a command to initiate formation testing, the drill string has stopped rotating if tool10is disposed on a drill sting. As shown inFIG. 9, motor404is coupled to pump406which draws hydraulic fluid out of hydraulic reservoir408through a serviceable filter410. As will be understood, the pump406directs hydraulic fluid into hydraulic circuit400that includes formation probe assembly50,200(either can be used interchangeably), equalizer valve60, draw down pistons70,72and solenoid valves412,414,416,418,420,422. It will be understood that although the description below will reference only formation probe assembly50, the hydraulic circuit described may be used to operate formation probe assembly50or probe assembly200.

The operation of formation tester10is best understood with reference toFIG. 9in conjunction withFIGS. 6A-6B,7A-F,11and12. In response to an electrical control signal, controller402energizes retract solenoid valve412and valve414, and starts motor404. Pump406then begins to pressurize hydraulic circuit400and, more particularly, charges probe retract accumulator424. The act of charging accumulator424also ensures that the formation probe assembly50is retracted, the equalizer valve60is open and that draw down pistons70,72are in their initial shouldered position as described with reference toFIGS. 11 and 12. When the pressure in system400reaches a predetermined value, such as 1800 p.s.i. as sensed by pressure transducer426a, controller402(which continuously monitors pressure in the system) energizes extend solenoid valve416which causes formation probe assembly50to begin to extend toward the borehole wall16. Concurrently, check valve428and relief valve429seal the probe retract accumulator424at a pressure charge of between approximately 500 to 1250 p.s.i. Solenoid valve412is still energized.

Formation probe assembly50extends, as previously described, from the position shown inFIG. 6Ato a position before full extension as shown inFIG. 6B(except with snorkel still retracted), where seal pad180engages the mud cake49on borehole wall16. At this point, retract solenoid valve412is de-energized, thereby allowing snorkel98to be extended and scraper160to be retracted. With hydraulic pressure continuing to be supplied to the extend side of piston96and snorkel98for formation probe assembly50, the snorkel may then penetrate the mud cake and the scraper retracted, as shown inFIG. 6B(andFIGS. 7E-7Ffor assembly200). The outward extensions of pistons96and snorkel98continue until seal pad180engages the borehole wall16, as previously described with regard to formation probe assembly50. This combined motion continues until the pressure pushing against the extend side of piston96and snorkel98reaches a pre-determined magnitude, for example 1,200 p.s.i., controlled by relief valve417, causing seal pad180to be squeezed. At this point, a second stage of expansion takes place with snorkel98then moving within the cylinders120in piston96to penetrate the mud cake49on the borehole wall16and to receive formation fluids or take other measurements.

De-energizing solenoid valve412also closes equalizer valve60, thereby isolating fluid passageway93from the annulus. In this manner, valve412ensures that valve60closes only after the seal pad140has entered contact with mud cake49which lines borehole wall16. Passageway93, now closed to the annulus15, is in fluid communication with cylinders512,542at the upper ends of cylinders514,544in draw down piston assemblies70,72, best shown inFIGS. 11 and 12.

With extend solenoid valve416still energized, and the hydraulic circuit400at approximately 1,200 p.s.i., probe extend accumulator430has been charged and controller402energizes solenoid valve414. Energizing valve414closes off the extend section of the hydraulic circuit, thereby maintaining the extend section at approximately 1,200 p.s.i. and allowing drawdown to begin. With valve414energized, pressure can be added to the draw down circuit, which generally includes draw down accumulator432, solenoid valves418,420,422and draw down piston assemblies70,72.

Controller402now energizes solenoid valve420which permits pressurized fluid to enter portion504aof cylinder504causing draw down piston70to retract. When that occurs, plunger510moves within cylinder514such that the volume of fluid passageway93increases by the volume of the area of the plunger510times the length of its stroke along cylinder514. The volume of cylinder512is increased by this movement, thereby increasing the volume of fluid in passageway93. Preferably, these elements are sized such that the volume of fluid passageway93is increased by preferably 30 cc maximum as a result of piston70being retracted.

If draw down piston70is to be stopped due to, for example, the need for only a partial draw down or an unsuccessful partial draw down, controller402may energize solenoid valve418to pressurize the draw down shutoff valve assembly74. Pressurizing valve assembly74causes draw down piston70to cease drawing down formation fluids. Now, valve assembly74and draw down piston70have been pressured up to approximately 1,800 p.s.i. This ensures that shutoff valve assembly74holds draw down piston70in its drawn down, or partially drawn down, position such that the drawn formation fluids are retained and not inadvertently expelled.

When it is desired to continue drawing down with draw down piston70, solenoid valve418can be de-energized, thereby turning shutoff valve74off. Draw down with draw down piston70then commences until the volume of cylinder514filled. The draw down of draw down piston70may continue to be interrupted using valves418and74. Such interruptions may be necessary to change draw down parameters, such as draw down rate and volume.

Controller402may be used to command draw down piston70to draw down fluids at differing rates and volumes. For example, draw down piston70may be commanded to draw down fluids at 1 cc per second for 10 cc and then wait 5 minutes. If the results of this test are unsatisfactory, a downlink signal may be sent using mud pulse telemetry, or another form of downhole communication, programming controller402to command piston70to now draw down fluids at 2 cc per second for 20 cc and then wait 10 minutes, for example. The first test may be interrupted, parameters changed and the test may be restarted with the new parameters that have been sent from the surface to the tool. These parameter changes may be made while formation probe assembly50is extended.

While draw down piston70is stopped, controller402may energize solenoid valve422which permits pressurized fluid to enter portion534aof cylinder534causing draw down piston72to retract. When that occurs, plunger540moves within cylinder534such that the volume of fluid passageway93increases by the volume of the area of the plunger540times the length of its stroke along cylinder544. The volume of cylinder542is increased by this movement, thereby increasing the volume of fluid in passageway93. Preferably, these elements are sized such that the volume of fluid passageway93is increased by 50 cc as a result of piston72being retracted. Preferably, draw down piston72does not have the stop and start feature of piston70, and is able to draw down more fluids at a faster rate. Thus, draw down piston72may be configured to draw down fluids at rates of 3.8 or 7.7 cc per second, for example. However, it should be understood that either piston70,72may be different sizes, and piston72may also be configured to have the stop and start feature via the shutoff valve assembly. Thus, hydraulic circuit400may be configured to operate multiple pistons70and/or multiple pistons72. Also, pistons70,72may be operated in any order.

The ability to control draw down pistons70,72as described above also allows the operator to purge fluids in the draw down piston assemblies and probe flow lines. For example, if a pre-test volume of fluid has been drawn into the probe, it may be purged by actuating the draw down pistons in the opposite directions. This may be useful for cleaning out any accumulated debris in the flow lines and probe assembly.

Maintaining clean flow lines is important to protecting instruments in the testing tool, and to maintaining the integrity of the formation tests by purging old fluids left in the flow lines. Thus, in another embodiment for keeping the flow lines clean, a mechanical filter may be placed in the flow lines, such as anywhere along flow lines91,93inFIGS. 6A,6B and9. Alternatively, the flow lines may be purged by opening equalizer valve60, pumping out fluids present in the flow lines, then closing equalizer valve60in preparation of another draw down sequence.

As draw down piston70is actuated, 30 cc of formation fluid will thus be drawn through central passageway127of snorkel98and through screen100. The movement of draw down piston70within its cylinder504lowers the pressure in closed passageway93to a pressure below the formation pressure, such that formation fluid is drawn through screen100and into apertures166, through snorkel98, then through stem passageway108to passageway91that is in fluid communication with passageway93and part of the same closed fluid system. In total, fluid chambers93(which include the volume of various interconnected fluid passageways, including passageways in formation probe assembly50, passageways91,93, the passageways interconnecting93with draw down pistons70,72and draw down shutoff valve74) preferably has a volume of approximately 63 cc. If draw down piston72is also activated, this volume should increase approximately 30 cc, up to approximately 90 cc total. Drilling mud in annulus15is not drawn into snorkel98because seal pad180seals against the mud cake. Snorkel98serves as a conduit through which the formation fluid may pass and the pressure of the formation fluid may be measured in passageway93while seal pad180serves as a seal to prevent annular fluids from entering the snorkel98and invalidating the formation pressure measurement.

Referring momentarily toFIG. 6B, formation fluid is drawn first into the central bore132of screen100. It then passes through slots134in screen slotted segment133such that particles in the fluid are filtered from the flow and are not drawn into passageway93. The formation fluid then passes between the outer surface of screen100and the inner surface of snorkel extension126where it next passes through outlet end135, apertures166in scraper160, scraper tube150and into the central passageway108of stem92.

Screen100(and screen290of assembly200) may be optimized for particular applications. For example, if prior knowledge of the formation is obtained, then the screen can be tailored to the type of rock or sediment that is present in the formation. One type of adjustable screen is a gravel-packed screen, which may be used instead of or in conjunction with the slotted screen100. Generally, a gravel-packed screen is two longitudinal, cylindrical screens of different diameters. The screens are disposed concentrically and the annulus is filled with gravel pack sieve, or a known sand size.

Despite the type of formation encountered, the gravel pack may be tailored to have a 10-to-1 ratio of formation sand size to gravel pack size, which is the preferable formation particle size to gravel particle size ratio. With this ratio, it is expected that the gravel pack screen will have the ability to screen formation particles up to 1/10ththe size of the nominal formation particle diameter size encountered. With this embodiment, the gravel pack sand size can be tailored to the specific intended application.

In yet another embodiment, the screens100,290as they are illustrated inFIGS. 6B,7F may be optimized by adjusting the size and number of slits required for a particular application. The slits, or slots, are illustrated schematically as internally slotted segment133having slots134inFIG. 6B, and internally slotted segment293having slots295. The size and number of slits can be tailored to the particular formation expected to be intersected, and the nominal sand particle size of the produced sand. For example, more slits with smaller openings may be used for smaller nominal formation particle size.

In a further embodiment, the above mentioned adjustment of slot size may be accomplished real-time. In the previous embodiment, the slot size is set upon deployment of tool10into the borehole. The slot size remains unchanged while tool10is deployed. The slot size may be adjusted at the surface of the borehole by replacing screens100,290, or by manually adjusting the slot sizes, but may not be adjusted real-time, or while tool10is deployed downhole. In the current embodiment, detection of the type of formation actually intersected may be achieved via the various apparatus and methods disclosed herein. If the detected formation value, such as particle size, differs from a predetermined value, the slot size may be adjusted without tripping tool10out of the borehole. A command may be given from the surface of the borehole, or from tool10, and slot size may be adjusted by moving two concentrically disposed slotted cylindrical members relative to each other, for example, or by adjusting shutter mechanisms adjacent the slots.

Referring again toFIG. 9, with seal pad180sealed against the borehole wall, check valve434maintains the desired pressure acting against piston96and snorkel98to maintain the proper seal of seal pad180. Additionally, because probe seal accumulator430is fully charged, should tool10move during drawdown, additional hydraulic fluid volume may be supplied to piston96and snorkel98to ensure that seal pad180remains tightly sealed against the borehole wall. In addition, should the borehole wall16move in the vicinity of seal pad180, the probe seal accumulator430will supply additional hydraulic fluid volume to piston96and snorkel98to ensure that seal pad180remains tightly sealed against the borehole wall16. Without accumulator430in circuit400, movement of the tool10or borehole wall16, and thus of formation probe assembly50, could result in a loss of seal at seal pad180and a failure of the formation test.

With the drawdown pistons70,72in their fully, or partially, retracted positions and anywhere from one to 90 cc of formation fluid drawn into closed system93, the pressure will stabilize enabling pressure transducers426b,cto sense and measure formation fluid pressure. The measured pressure is transmitted to the controller402in the electronic section where the information is stored in memory and, alternatively or additionally, is communicated to the master controller401in the MWD tool13below formation tester10where it can be transmitted to the surface via mud pulse telemetry or by any other conventional telemetry means.

When drawdown is completed, pistons70,72actuate their contact switches previously described. When the contact switch550, for example, is actuated controller402responds by shutting down motor404and pump406for energy conservation. Check valve436traps the hydraulic pressure and maintains pistons70,72in their retracted positions. In the event of any leakage of hydraulic fluid that might allow pistons70,72to begin to move toward their original shouldered positions, drawdown accumulator432will provide the necessary fluid volume to compensate for any such leakage and thereby maintain sufficient force to retain pistons70,72in their retracted positions.

During this interval, controller402continuously monitors the pressure in fluid passageway93via pressure transducers426b, c. When the measured pressure stabilizes, or after a predetermined time interval, controller402de-energizes extend solenoid valve416. When this occurs, pressure is removed from the close side of equalizer valve60and from the extend side of probe piston96. Equalizer valve60will return to its normally open state and probe retract accumulator424will cause piston96and snorkel98to retract, such that seal pad180becomes disengaged with the borehole wall. Thereafter, controller402again powers motor404to drive pump406and again energizes solenoid valve412. This step ensures that piston96and snorkel98have fully retracted and that the equalizer valve60is opened. Given this arrangement, the formation tool has a redundant probe retract mechanism. Active retract force is provided by the pump406. A passive retract force is supplied by probe retract accumulator424that is capable of retracting the probe even in the event that power is lost. It is preferred that accumulator424be charged at the surface before being employed downhole to provide pressure to retain the piston and snorkel in housing12.

It will be understood that the equalizer valve60may be opened in a similar manner at other times during probe engagement with the borehole wall. If the probe seal pad is in danger of becoming stuck on the borehole wall, the suction may be broken by opening equalizer valve60as described above.

After a predetermined pressure, for example 1800 p.s.i., is sensed by pressure transducer426aand communicated to controller402(indicating that the equalizer valve is open and that the piston and snorkel are fully retracted), controller402de-energizes solenoid valves418,420,422to remove pressure from sides504a,534aof drawdown pistons70,72, respectively. With solenoid valve412remaining energized, positive pressure is applied to sides504b,534bof drawdown pistons70,72to ensure that pistons70,72are returned to their original positions. Controller402monitors the pressure via pressure transducer426aand when a predetermined pressure is reached, controller402determines that pistons70,72are fully returned and it shuts off motor404and pump406and de-energizes solenoid valve412. With all solenoid valves returned to their original positions and with motor404off, tool10is back in its original condition.

The hydraulic circuit400, as described and illustrated inFIG. 9, may also act as a regenerative circuit while extending the probe assembly. With both retract valve412and extend valve416energized or actuated, as described above, and the difference in areas between the smaller area on the retract side of the probe piston, such as piston96or piston240, and the larger area on the extend side of the piston, there is a net effect of extending the probe assembly. As the piston continues to extend with retract valve still open, there is a back flow of hydraulic fluid through retract valve412due to the lack of a check valve behind retract valve412. This relatively unimpeded back flow path leads into the pressurized hydraulic fluid flowing into extend valve416, adding to the pressure on the extend side of the circuit and increasing the rate at which the probe may extend.

During extension of the probe assembly, using hydraulic circuit400, it can be seen that the total volume of hydraulic fluid required to be displaced by pump406, and hence the number of revolutions of motor404, is reduced compared to a non-regenerative circuit. The regenerative nature of circuit400also allows the moveable wiper or scraper, such as scraper160, to remain extended during extension of the probe assembly, especially as the snorkel assembly is penetrating the mudcake and formation and there is an extra force pushing back on the moveable scraper. As can be seen inFIGS. 6A,6B and7A-7F, the area of the extend side of the scraper assembly, for example, the bottom of flange372of scraper tube278inFIG. 7F, is greater than the area of the retract side, or the upper side of flange372. Thus, with both valves412and416actuated, the same hydraulic pressure acts on different areas, causing the wiper element to extend and the pressurized fluid to regenerate on the extend side of the scraper tube278, as previously described.

Further, as mentioned before, the regeneration of pressure in circuit400allows faster extension of the probe assembly. In addition, the regenerated pressure assists with control of equalizer valve actuation.

A hydraulic reservoir accumulator assembly600is disposed in probe collar12as shown inFIG. 10I. Reservoir accumulator assembly600maintains a pressure above the annulus or surrounding environment pressure in the complete tool10hydraulic system. This condition in the hydraulic system compensates for pressure and temperature changes in the tool. Also, the pressure provided from assembly600causes pump406(FIG. 9) to begin operating from the annulus pressure, thereby reducing the work load that would be required from starting pump406at atmospheric pressure. Thus, accumulator assembly600may be used to communicate annulus pressure into the tool's hydraulic system. As will be seen below, assembly600is self contained and easily field replaceable.

Assembly600generally includes a body602having a top surface632, bottom surface634(FIG. 10C) and endcap604at end606, several locking wings608and drilling fluid apertures618,620at end622. Top surface632includes additional fluid apertures628,630covered by a screen639as illustrated inFIG. 10F. Screen639is held in place by retaining ring637, and prevents large particles in the drilling fluid from entering the cylinders and interfering with the reciprocation of the pistons. Endcap604includes a pressure plug638for connecting assembly600to probe collar12, which helps to lock assembly600into place as illustrated inFIG. 10H. Endcap604also includes hydraulic fluid check valves640,642for fluid communication with the tool hydraulic circuit, and for checking fluid into assembly600and the tool hydraulic system when assembly600is removed from collar12.

Referring briefly toFIG. 10F, it can be seen that the inside of assembly600is split into two cylinders626,646.FIG. 10Cillustrates cylinder626retaining a piston636which separates cylinder626into hydraulic fluid portion626aand drilling fluid portion626b. Piston636is reciprocal between the position shown inFIG. 10Cand the position of piston656shown inFIG. 10D. Spring624is retained in cylinder portion626bbetween piston636and end622. Spring624extends past piston end636baround piston636and seats on increased piston diameter portion633. Increased diameter portion633is similar to increased diameter portion653of piston656, illustrated inFIG. 10G. At end622, aperture620allows drilling fluids to enter cylinder portion626band exert the surrounding annulus pressure on side636bof piston636. Because spring624also exerts a force on side636b, the pressure of hydraulic fluid in cylinder portion626ais greater than the annulus pressure. The pressure of the hydraulic fluid in cylinder portion626ais the annulus pressure plus the pressure added by spring624. Spring624may exert, for example, a pressure of approximately 60-80 p.s.i.

Cylinder646ofFIG. 10Doperates in a similar fashion to cylinder626. Drilling fluid enters cylinder portion646bthrough aperture622, thereby exerting the annulus pressure on side656bof piston656. Spring644then increases the pressure on piston656, causing the hydraulic fluid in cylinder646a, and therefore the hydraulic fluid in the tool hydraulic system, to be greater than the annulus pressure. Spring644is shown in the fully compressed position inFIG. 10D.

Referring now toFIG. 10G, enlarged piston end656aincludes seal659for sealing the drilling mud from the system hydraulic fluid, and scraper661for cleaning the cylinder bore646as piston656reciprocates. Spring644seats on increased diameter portion653. Piston end636ais similar to piston end656aillustrated inFIG. 10G.

Preferably, pistons636,656reciprocate independently of each other while maintaining the pressure in the hydraulic system of the tool. Also, both pistons communicate with the entire tool hydraulic system.

Referring now toFIG. 10H, accumulator assembly600is illustrated placed into position in collar12, but not locked down. To engage assembly600with cavity601in collar12, assembly600is disposed above cavity601and locking wings608(FIG. 10A) are aligned with recesses664. Recesses664are L-shaped (not shown) with the bottom portions of the L extending toward endcap604and end603of cavity601. Assembly600is lowered into cavity601with locking wings608sliding down through recesses664until assembly600seats at the bottom of cavity601and top surface632is substantially flush with the surface of collar12. Assembly600is then moved toward cavity end603such that locking wings608move into the extending bottom portions of recesses664and pressure plug638(FIG. 10A) pressure fits into an aperture (not shown) disposed at end603of cavity601. This forward movement also causes a gap678to be formed between cavity end605and assembly end622.

To lock assembly600into place, a wedge670is placed into gap678. The angled end622(illustrated inFIG. 10C) matingly receives the angled side676of wedge670. The wedging action of these mating surfaces ensures that assembly600is moved fully forward in cavity601. Bolts674and nuts672lock down wedge670. Further, L-shaped locking pieces668are placed into recesses664and bolts666are used to lock down wings608. The final locked position of assembly600is illustrated inFIG. 10I. Fluid ports628,630communicate with drilling fluid in annulus15. Fluid entering cylinder portions626band646bthrough apertures618,620is screened by slots in wedge670(slots not shown).

Removing accumulator assembly600requires a process done in reverse of the process just described. While removing assembly600, check valves640,642close and maintain oil in the tool hydraulic system. Assembly600may then be cleaned and/or replaced. Check valves640,642open again once assembly600is locked into position. Hydraulic fluid may then be added to make up for any fluid loss, and preferable fluid is added to the extent that pistons636,656are pushed back to the position illustrated inFIG. 10D.

The uplink and downlink commands used by tool10are not limited to mud pulse telemetry. By way of example and not by way of limitation, other telemetry systems may include manual methods, including pump cycles, flow/pressure bands, pipe rotation, or combinations thereof. Other possibilities include electromagnetic (EM), acoustic, and wireline telemetry methods. An advantage to using alternative telemetry methods lies in the fact that mud pulse telemetry (both uplink and downlink) requires pump-on operation but other telemetry systems do not.

The down hole receiver for downlink commands or data from the surface may reside within the formation test tool or within an MWD tool13with which it communicates. Likewise, the down hole transmitter for uplink commands or data from down hole may reside within the formation test tool10or within an MWD tool13with which it communicates. In the preferred embodiment specifically described, the receivers and transmitters are each positioned in MWD tool13and the receiver signals are processed, analyzed and sent to a master controller401in the MWD tool13before being relayed to local controller402in formation testing tool10.

The above discussion is meant to be illustrative of the principles and various embodiments of the present invention. While the preferred embodiment of the invention and its method of use have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the invention. The embodiments described herein are exemplary only, and are not limiting. Many variations and modifications of the invention and apparatus and methods disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims.