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BACKGROUND OF THE INVENTION 
     The present invention relates to conducting production tests of wells penetrating earth formations, such as oil and gas wells. More particularly, the present invention provides an improved method and apparatus for testing wells without the need to withdraw the drill stem from the borehole. 
     International patent application number PCT/US98/22379 teaches and discloses methods and apparatuses for testing wells while leaving the drill stem in the borehole. This application is incorporated herein by reference for all purposes. 
     Significant advances have been made in the present invention to provide a system for shutting in the well so that tests can be made. Such improvements relate to the structural use of the activation mechanism for inflating downhole packers including an improved collet/spline configuration to more positively hold and release the packer mandrel; a simplified hydraulic fluid reservoir and feed system to the packers; the utilization of a plurality of packers having varying pressure capabilities; an improved packer attachment assembly; and an improved hydraulic float valve coordinated with the packer hydraulic system. 
     SUMMARY OF THE INVENTION 
     The testing drill collar of the present invention may be positioned between the drill bit and the drill collar assembly. The inflatable packer assembly may be dressed to accommodate environments that arise in different geological areas. This may be obtained by selecting a packer design of short element combination, short and long combination, or only one long element. Packer material and designs depend on area, depth, and bottom hole temperature. 
     The tool is locked in the drill position until deployed by an activating tool via slickline, electric line, or by pumping the activating tool down. Once activated, the lower portion of the drill collar scopes downward. The length of travel is controlled by the amount of pressure applied against the activating tool and consequentially the pressure is delivered to a piston which compresses clean compressible fluid from the reservoir into the packer elements. The packers have separate fluid reservoirs but inflate simultaneously. It should be understood that the fluid utilized in no way limits the present invention. A better packer seat is achieved due to the downward movement while inflating. Once desired pressure is achieved this pressure is locked in and maintained by a locking ratchet design that cannot release until ¼ round right hand torque is delivered with downward travel of the drill string. This deflates the elements and receives the lower drill collar and latches back in the drill position when very little weight is put on the drill bit. If elected, reverse circulation may be achieved during this procedure. 
     The drill mode consists of the upper collar receiving the lower collar scoped in. Torque is delivered from the upper collar to the lower collar by a rugged spline section. The spline area is sealed and operates in gear oil, therefore, assuring a clean environment to maximize the life span of the splines and the contact area for weigh transfer. Weight is delivered from the upper collar at the top of the lower collar. 
     During testing, a multi-flow and multi-shut-in apparatus and method delivers formation pressures, temperatures, and fluid or gas properties to the surface, therefore allowing the test to be engineered efficiently, according to real time data. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a longitudinal cross-sectional view of a production well. 
     FIGS. 2-7 are schematic views of a well borehole showing the various stages in the operation of the testing tool of the present invention, in accordance with a preferred embodiment in order to conduct a drill stem test. 
     FIG. 2 shows drilling operations with the testing tool in place in the borehole with right hand torque. 
     FIG. 3 shows partial or total purging of drilling fluid from the inside of the drill stem in preparation for a drill stem test and rotation of tool one-quarter turn left. 
     FIG. 4 shows lowering the activating tool in preparation of setting the testing tool. 
     FIG. 5 shows shutting in the formation by inflation of the packer while maintaining left hand torque. 
     FIG. 6 shows the formation producing up into the drill stem after a portion or all surface pressure is bled off. 
     FIG. 7 shows deflating the packer after right hand torque. 
     FIGS. 8-17 and  8 A- 17 A are longitudinal cross-sectional views of the testing tool. 
     FIG. 8 is the upper portion of the deactivated tool. 
     FIG. 8A is the upper portion of the activated tool. 
     FIG. 9 is the upper spring portion of the deactivated tool. 
     FIG. 9A is the collet portion of the activated tool. 
     FIG. 10 is the upper inner collar coupling portion of the deactivated tool. 
     FIG. 10A is the compressed spring portion of the activated tool. 
     FIG. 11 is the upper piston and upper hydraulic reservoir of the deactivated tool. 
     FIG. 11A is the upper collar coupling and upper piston portions of the activated tool. 
     FIG. 12 is the intermediate piston and the intermediate hydraulic reservoir of the deactivated tool. 
     FIG. 12A is the intermediate piston and intermediate hydraulic reservoir portions of the activated tool. 
     FIG. 13 is the lower intermediate piston and lower hydraulic reservoir portions of the deactivated tool. 
     FIG. 13A is the lower intermediate piston and lower hydraulic reservoir portions of the activated tool. 
     FIG. 14 is the upper packer portion of the deactivated tool. 
     FIG. 14A is the upper packer portion of the activated tool. 
     FIG. 15 is the intermediate packer portion of the deactivated tool. 
     FIG. 15A is the intermediate packer portion of the activated tool. 
     FIG. 16 is the lower packer and upper float valve portion of the deactivated tool. 
     FIG. 16A is the lower packer portion of the activated tool. 
     FIG. 17 is the hydraulic float valve portion of the deactivated tool. 
     FIG. 17A is the hydraulic float valve portion of the activated tool. 
     FIG. 18 is a transverse cross-sectional view of the deactivated testing tool taken through line A—A of FIG.  9 . 
     FIG. 18A is a transverse cross-sectional view of the activated testing tool taken through line B—B of FIG.  9 A. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     The present invention utilizes an activating tool during a drill stem test. The activating tool may be lowered inside of the drill stem by way of a wireline or pumped down from the surface to seat in a nipple. The nipple is in the drill stem near the formation of interest. When the activating tool seats in the nipple, the formation becomes shut-in. The activating tool can be released from the nipple to allow the formation to produce fluid up into the drill stem. Once released, the activating tool can be retrieved to the surface or reset for additional testing. 
     Thus, the activating tool acts as a valve inside of the drill stem. The activating tool can be used with a conventional drill stem testing tool, which tool requires the removal of the drill bit from the borehole, or the activating tool can be used with an unconventional testing tool that is lowered into the borehole with the drill bit. 
     The use of the activating tool  21  with an improved testing tool  201  is described below with reference to FIGS. 8-18 and  8 A- 18 A. In addition to the activating tool, other valves can be used with the testing tool of FIGS. 8-18 and  8 A- 18 A, which provide real time test data and utilize electronic testing equipment. 
     The testing tool  201  can be used in drilling operations to prevent blow outs and to control thief zones through the utilization of deadman or drop probes. The activating tool  21  is preferably used to conduct a drill stem test. The activating tool can also be used in conjunction with the testing tool  201  to control blow outs and thief zones. 
     In controlling blow outs and thief zones, the activating tool and the testing tool  201  are used in conjunction with the circulating sub  202 , well known in the art, shown in FIGS. 2-7. 
     A thorough description of the operation of an activating tool  21  is detailed in International Publication WO99/22114, published May 6, 1999, and is incorporated herein by reference for all purposes. 
     From time to time it is desirable to test the production of a producing well. During such a production test the well is shut-in and the formation pressure is allowed to increase. 
     The increase in pressure provides useful information on the production capabilities of the well. 
     In FIG. 1, there is shown a view of a producing well  161 . The well  161  extends in the formation of interest  15 . Production equipment is in place. This equipment includes casing  163 . The casing is perforated  165  at the formation  15 . A packer  167  isolates the formation  15 . The nipple  23 A is located above the packer  167 . Located above the nipple  23 A is a standard seating nipple  169  found in many producing wells. A string of tubing  171  extends from the standard nipple  169  to the surface  13 . A well head  173  and other equipment is also provided. The nipple  23 A is installed downhole when the well is completed or when the tubing string is pulled. 
     During drilling operations, an activating tool  21  may be inserted into the well via a lubricator  175 . A wireline  53  is used to raise and lower the activating tool  21  for a drill stem test or pumped down for blow out control. 
     The activating tool  21  can be used to shut-in the production well and acquire pressure data. The activating tool  21  is lowered down inside the tubing on a wireline  53 . It seats inside of the nipple  23 A, as discussed hereinbelow. Once the activating tool is seated, the well is shut-in from a downhole location. Formation pressure is allowed to build, which build up is recorded by the activating tool instrumentation. 
     The well need only be shut-in for a relatively short time (for example, 24 hours) compared to conventional production well testing. Because the well is shut-in from a downhole location close to the formation, the entire column of tubing  171  need not be pressurized by the formation pressure, as with conventional testing. Therefore, use of the activating tool in a production well test saves time. 
     After the well has been shut-in for a suitable period of time, the activating tool is released from the nipple  23 A, as discussed hereinbefore. The activating tool is then retrieved to the surface, for analysis of the data. 
     With the exception of the seals, which are made of rubber, the nipple and the activating tool are made of metal. 
     FIGS. 2-7 show the sequence of operation for a drill stem test. In FIG. 2, the borehole  11  is being drilled. The drill bit  203  is in place on the bottom of the borehole and the drill stem  17 A is being rotated. Drilling proceeds in accordance with conventional techniques. For example, weight is applied to the drill stem at the surface  13 , and drilling fluid  205  is circulated down through the drill stem  17 A, out through jets or orifices in the drill bit  203  and up by way of the annulus  207 , where the drilling fluid returns to the surface  13 . 
     Beginning at the bottom and working towards the surface, the drill stem or drill string  17 A is made up of th drill bit  203 , its associated float sub  209 , the testing tool  201 , a circulating sub  202 , drill collars  35 , and drill pipe  17 A. The testing tool  201  is preferably located immediately above the drill bit  203  and its sub  209 , although the testing tool can be located higher up the drill stem. 
     The testing tool  201  is thus part of the drill stem  17 A. As the drill stem is rotated, so too is the testing tool. The testing tool  201  transmits the rotational force needed to rotate the drill bit for drilling. In addition, weight applied to the bit during drilling is also transmitted through the testing tool  201 . 
     When the borehole penetrates a formation  15  of interest, the decision is made to conduct a drill stem test. In FIGS. 3-5, the borehole  11  is readied for the test. In FIG. 3, the drill stem  17 A is left hand torqued one-quarter turn (counterclockwise) to align the latching collet  219  and is then picked up a determined distance in order to position the packer above the zone at a suitable place for a good packer seat. Next, because the drill stem is full of drilling fluid, the drill stem may be purged by pumping in compressed gas  210  (or lighter fluid) from the surface. For example, compressed nitrogen gas can be used. As the compressed gas traverses down inside of the drill stem  17 A, the drilling fluid is pushed out of the bottom of the drill stem. The drilling fluid flows up to the surface via the annulus  207 . In this manner, the inside of the drill pipe stem may be partially or totally purged of drilling fluid. 
     With the testing tool  201  still suspended above the formation  15 , as shown in FIG. 4, the testing tool is set. The testing tool is set by lowering the activating tool  21  on a wireline  53  down inside of the drill stem  17 A. The inside of the testing tool  201  contains an accommodating nipple  23 A for receiving the activating tool. The activating tool  21  engages the nipple  23 A. The inside of the drill stem  17 A is now closed by the activating tool  21 . The pressure exerted by compression inside of the drill stem causes the nipple  23 A to slide downwardly and then causes a packer  211  (or more than one packer) to inflate (FIG. 5) against the walls of the borehole  11 . In the present preferred embodiment more than one packer is utilized. The ability to use one or more packers of differing characteristics is a unique feature of the present invention as will be discussed below. The packer inflates as it extends and wipes the borehole wall. This helps provide a clean area to seal off the formation. 
     Once inflated, the packer  211  packs off the annulus  207  above the formation  15 . The formation is now shut-in by the inflated packer  211  and also by the activating tool-nipple arrangement  21 ,  23 A, which forms a seal inside of the drill stem. In FIG. 5, the formation fluid or gas  62  is shown as an arrow. The flow of fluid or gas inside of the drill stem is stopped by the activating tool and nipple. 
     The test then enters an initial flow period. To enter the flow period, the valve inside of the testing tool is opened, namely by manipulating the activating tool  21 . Fluid or gas  62  from the formation flows through the testing tool up into the drill stem  17 A. After desired flow and initial shut-in periods, the activating tool  21  is released from the nipple and retrieved to the surface  13 . The activating tool can be used to retrieve a fluid sample as well as contain instrumentation to record pressure, temperature, and other parameters, such as gradients, to determine what kind of fluid is in the drill pipe. When the activating tool reaches the surface, the sample and recorded information can be inspected. Currently, fluid properties and pressure information may be analyzed in real time by the use of electronic test equipment. 
     The well can undergo repeated shut-in and flow periods (FIGS. 5 and 6, respectively) by seating and releasing the activating tool  21 . Some surface manipulation of pressure above the activating tool may be necessary to assist in seating the activating tool. Once inflated, the packer remains inflated, independently of the activating tool activity. 
     After the drill stem test has been completed, the testing tool  201  is reconfigured for drilling. The drill stem  1   7 A is rotated slowly to the right (very little travel is needed to free the collett teeth  242 ) and then eased to the bottom of the borehole (FIG.  7 ). The rotation and lowering of the drill stem allows the lower portion of the drill stem  17 A to retract and the hydraulic fluid to reenter the reservoirs thereby allowing the packer  211  to deflate. As the packer is deflated, the borehole undergoes reverse circulation by surface control. When the packer is released from the borehole, the annulus drilling fluid will flow into the drill stem, thus displacing the formation fluids or gas to the surface where they may be contained. After weight is applied to the bit, the testing tool  201 , and the remainder of the drill stem  17 A, are again ready for drilling (see FIG.  2 ). 
     The testing tool  201  of FIGS. 8-18 and  8 A- 18 A will now be described in detail. The testing tool  201  includes an upper testing collar  213  and an inner assembly  215 . The upper testing collar  213  is generally tubular, having an upper end  217  and a lower end  219  (FIG.  13 ). The upper testing collar  213  forms a housing for the inner assembly  215 . The upper end  217  (FIG. 8) is coupled to a drill collar (not shown). The lower end  219  (FIG. 13) is located adjacent to the packer section. 
     The upper testing collar has an interior cavity  221  that extends from the upper end  217  to the lower end  219 . The interior cavity  221  has a number of characteristics, which will be described beginning near the upper end  217  and proceeding toward the lower end  219 . Near the upper end of the interior cavity  221  is an abutment shoulder  223  (see FIG. 8A) which extends radially inward. The top side  223 A of the shoulder slopes inwardly, but the bottom side  223 B is perpendicular to the longitudinal axis L of the tool  201 . Below the shoulder  223  is a restriction c-ring groove  224 . Further, below the c-ring groove  224  is an upper shoulder  226 . Sliding sleeve sealing O-rings  100  are just above the stop shoulder  226  and fit into o-ring notches  101  (FIG.  8 ). A short distance away (FIG.  9 ), the interior cavity  221  narrows slightly in its inside diameter forming a small circumferential beveled shoulder  227  to cooperate with teeth  242  of collet  219 . The interior cavity  221  extends lower and gradually tapers to a wider diameter to accept a number of splines  231  having teeth  231  A. The top of which is where drilling weight is transferred. (See FIGS. 9,  9 A,  18  and  18 A.) The splines  231  extend longitudinally along the inside of the upper testing collar  213  and project inwardly toward the longitudinal axis L of the tool. In the preferred embodiment, there are four splines  231 , spaced 90° apart around the circumference of the inner cavity (see FIGS.  18  and  18 A). However, there can be more or fewer splines. The splines  231  are separated from each other by channels  232 . Channels  232  are release grooves for the collett teeth  231 A to free-travel in. The lower end of the splines  231  form a shoulder  233 . 
     FIG. 18 is a cross-sectional view of the deactivated testing tool taken through line A—A of FIG.  9 . This shows the tool in the drilling position. The upper testing collar  213  has splines  231  at 90° with channels  232  between each spline section. Cooperating mandrel spline sections  259  are shown in contact with upper testing collar splines  231  along intersections I 1 , I 2 , I 3 , and I 4 . Drilling torque is transferred along these intersection. 
     By rotating the upper testing collar  213 , one-quarter turn left (counterclockwise), the tool is ready to be activated for testing. FIG. 18A shows this slight rotation. The rotation allows the collet teeth  242  (FIG. 8) to rotate into alignment with the spline teeth  231 A. 
     Below the splines, the interior cavity  221  continues toward the lower end  219 , wherein a piston  239 A is encountered (see FIG.  11 ). The piston head  240 A, which is ring shaped, is perpendicular to the longitudinal axis of the tool and projects inwardly. Below the piston  239 A, the interior cavity  221  continues to the lower end  219  of the upper collar. The lower end  219  is closed. 
     The inner assembly  215  includes an upper sliding sleeve  234 A, a nipple  23 A, one or more pistons  239 A- 239 C, a spline mandrel  236 , a lower sliding sleeve  234 B, a packer mandrel  237 , and one or more packers  211 A- 211 C. The upper sliding sleeve  234 A slides in interior cavity  221  as will be discussed below. 
     At the topmost end  218  of sleeve  234 A is a circumferential groove  103  which retains restriction c-ring  104  (FIG.  8 ). The lower end  220  of upper sleeve  234 A is attached to nipple  23 A at an upper sleeve collar portion  216 A (FIG.  9 ). 
     Upper sliding sleeve  234 A guides and aligns the movement of the nipple  23 A. Further, the restriction c-ring  104  cooperates with groove  224  to hold the nipple  23 A in a proper location during deactivation of the tool  201 . 
     The outside diameter of the collar  216 A is greater than the outside diameter of the upper sleeve section. The lower sliding sleeve  234 B is provided with sealing O-rings  267  at its lower end and has a circumferential lower sleeve collar  216 B which fits over and attaches to the lower end of nipple  23 A. Again, the outside diameter of lower sleeve collar  216 B is greater than the outside diameter of the lower sliding sleeve  234 B. 
     The spline mandrel  236  fits circumferentially around nipple  23 A. An upper shoulder  105  on the spline mandrel supports and retains collet  219  having teeth  242 . Shoulder  105  also limits the downward travel of the sleeve  220 . A lower shoulder  106  extends inwardly around mandrel  236  and serves as an abutment for coil spring  255 . The mandrel lower end  233  attaches to the packer mandrel  237  (FIG.  10 ). 
     Turning to FIGS. 8 and 9, it may be seen that when upper sliding sleeve  234 A is in drilling position, collet  219  fits around upper sleeve collar  216 A with teeth  242  urged into engagement with beveled shoulder  227 . The collet teeth cannot move inwardly because upper sleeve collar  216 A restrains such movement. Further, splines  231  are in drilling engagement with the splines  259  of the spline mandrel  236 . 
     A chamber  251  is formed in the interior cavity  221  in the upper testing collar  213 . The chamber, which extends from the shoulder  223 A near the top of tool  201  (FIGS. 8 and 8A) to upwardly facing lower abutment shoulder  106  on the splines mandrel  236  containing the nipple  23 A. The nipple  23 A can slide up and down within the chamber  251 . A helical coil spring  255  is located between the lower abutment shoulder  106  and the lower sliding sleeve collar  216 B, wherein the nipple  23 A is biased upwardly. 
     The cooperation between the collet  219  and the toothed splines  231  are important to the positive locking feature of the present invention. When the tool  201  is in the drilling position (shown in FIGS.  8 - 18 ), the collet  219 , the collet teeth  242 , and the spline teeth  231  A are not engaged and the drilling forces and torque are transmitted through the splines  231  and  259 , as will be described below. However, once the drilling has ceased, the tool rotated one-quarter turn counterclockwise, and the activating tool  21  seated in the nipple  23 A, the collet teeth  242  have been aligned with the spline teeth  231  A. As the collet  219  moves downwardly, the teeth  242  engage the spline teeth  231 A. The flat surface of the collet teeth engage the flat surface of the spline teeth (see FIG.  9 A). Thus, the spline mandrel  236  and the nipple  23 A cannot move upwardly until the upper testing drill collar  213  is rotated clockwise a quarter of a turn to move the collet teeth  242  out of alignment with spline teeth  231  A and into channel  232 . 
     FIG. 10 illustrates the coupling of the packer mandrel  237  with the inner spline mandrel  236 , thus as the inner spline mandrel moves up and down within the borehole during the activation of the testing tool, the packer mandrel also moves up and down. The packer mandrel extends the length of the tool  201  from the spline mandrel  236  (FIG. 10) to the hydraulic float valve  300  assembly (FIG.  16 ). 
     There are a number of compartments  265 A- 265 C formed in the annular region between the packer mandrel  237  and the upper testing collar  213 . These compartments form separate annular reservoirs for holding compressible fluid used to inflate the packer elements and operate a hydraulic float valve situated downstream on the tool string. FIG. 11 shows how the upper reservoir  265 A is bounded at its upper end by piston  239 A and at its lower end by connector sub  235 A which is fixed to the upper testing collar  213 . The piston  239 A is connected to the packer mandrel  237  and slides relative to the upper testing collar  236 . The piston  239 A is ring-shaped around the packer mandrel. The piston has seals  271 A around its outer diameter and also around its inner diameter. 
     The connector sub  235 A (FIG. 11) has seals  273 A, such as O-rings, around its inside diameter to provide a seal against the packer mandrel  237 . The packer mandrel  237  can slide through the sub  235 A. 
     Similarly, an intermediate reservoir  265 B (FIG. 12) and a lower reservoir  265 C (FIG. 13) are provided downstream on the tool  201 . It should be understood that each reservoir has associated pistons  239 B and  239 C, ring systems  271 B and  271 C, subs  235 B and  235 C with seals  273 B and  273 C, and independent oil feed conduits to each packer. 
     Still further downstream on the packer mandrel are a series of packer elements associated with each reservoir. FIG. 14 illustrates the first such packer  211  A mounted to mandrel  237  by packer heads  275 A and  277 A. The upper head  275 A is fixed to the packer mandrel  237  while the lower head  277 A is slidably coupled to the mandrel  237 . The heads have seals around their inside diameters to seal between the heads and the mandrel. The packer element is connected between the upper and lower heads. The packer may be made of rubber such as a 70-90 durometer buna rubber or any other suitable material that is oil resistant. 
     There is an interior annular chamber  280 A formed around the mandrel  237  which fills with hydraulic fluid from reservoir  265 A during activation of the testing tool  201 . FIG. 14A shows the packer  211 A inflated with fluid in chamber  280 A. The injection of fluid is achieved by fluid passing through fluid conduit  281 A from the reservoir  265 A to chamber  280 A during the compression of the fluid by the downward movement of the piston  239 A as will be described below. 
     Similarly, an intermediate packer  211 B (FIG. 15) and a lower packer  211 C (FIG. 15) are provided downstream on the mandrel  237 . It should be understood that each packer has associated upper  275 B and  275 C and lower  277 B and  277 C heads, interior chambers  280 B and  280 C, fluid conduits  281 B and  281 C. 
     One of the unique features of the packer system of the present invention is the ability to provide packers with different pressure capabilities on one tool. Thus, as the well is drilled to deeper depths, it is possible to inflate the lowest packer to a higher pressure by varying the construction of the bladder and the volume of the fluid injected by the same displacement of the piston. 
     A unique packer head locking  509  assembly is provided in the present invention as shown in FIGS. 15 and 15A. A packer header  510  is attached to the packer element  211 C and is provided with seals  512  which urge against the packer mandrel  237 . Internal threads  514  are provided on the header  510  to threadingly attach the header  510  to a keyed, non-rotating locking head  520 . Locking head  520  is attached to the mandrel  237  by key  522  in keyway  523  in the mandrel. This prevents the locking heads from rotating around the mandrel. To further retain the locking head, a four-section, quadrant locking ring  524  is inserted through opening  526  in locking head  520 . Once the four sections of the ring  524  are in place a door closure  528  is inserted into the opening  526 . A lock bolt  530  is set through the door and into the locking head to retain the segmented locking ring in place. The locking ring  524  prevents the locking head  520  from moving up or down the mandrel. The packer header  510  may then be threadingly attached to the locking head  520 . 
     The fixation of the packer head locking assembly to the mandrel ensures that the top end of the packer  532  does not move up, down, or rotate on the mandrel when inflated or during drilling operation when the packer is deflated. Further, the lower end  534  of an upstream packer is restricted in downward movement when it abuts against a locking assembly  509  immediately below it. 
     Downstream of the last packer  211 C is a hydraulic float valve assembly  300  shown in FIGS. 16 and 17. The float valve assembly body  302  is threadingly attached to the packer mandrel end threads  304  on the distal end of the mandrel. The body  302  is further retained to the mandrel by retaining collar  306  (FIG.  16 ). 
     A hydraulic fluid conduit  308  extends through the body  302  and is in fluid communication with fluid conduit  281 C. Thus when fluid pressure is increased by the movement of piston  239 C as described above, fluid is forced through hydraulic fluid conduit  308  into fluid chamber  310 , opening the poppet valve assembly  312  (as seen in FIG.  17 A). 
     The pressure necessary to control the opening of the poppet valve assembly  312  is determined by the unique restriction c-ring  314 . C-ring  314  is designed to collapse in a specified pressure range based upon its material composition, the slope of the restriction shoulder, and thickness of the ring. As may be seen in FIG. 17, c-ring  314  has a leading tapered restriction shoulder  315  which urges against a collapsing collar  317 . As pressure increases in fluid chamber  310 , abutment flange  316  presses against upstream side  318  of the c-ring  314 . When the specific pressure range is reached the ring  314  collapses inwardly into groove  320  (as seen in FIG. 17A) and poppet valve assembly  312  slides downwardly. A second restriction c-ring  322  releases from groove  324  and urges against shoulder  326  extending inwardly from the housing  302  keeping the valve open, even when hydraulic pressure is released from chamber  310 . 
     From this description of the valve  312  operation, it may be seen that fluids from the downhole stem may be passed up the stem by the opening and closing of the hydraulic valve assembly  312 . The assembly includes the valve head  330 , the valve stem  332 , closure spring  334 , valve seat  336 , valve body collar  338 , and valve lower inlet opening  340 . 
     Once a testing or sampling is taken, the drilling operators may close the hydraulic valve by releasing the hydraulic pressure in the chamber  310  by rotating the upper testing collar  213  one-quarter turn clockwise, and lowering the drill stem on the borehole bottom. The weight of the drill stem will exceed the collapse pressure of second restriction c-ring  322 . The ring  322  will collapse back into position in groove  322 A and the entire valve body collar  338  will move upwardly to close the valve head  330  against valve seat  336 . 
     Turning to FIGS. 8A-18A, the operation of the testing tool  201  may be seen. To clarify the drawing the test activating tool  21  is not shown as seated in the nipple  23 A, but one of ordinary skill in the art would understand the operation of the tool  201 . 
     In FIG. 8A, it must be understood that the upper drilling collar  213  has been rotated one-quarter turn counterclockwise to align the collet teeth  242  with the spline teeth  231 A, the test activating tool  21  (not shown) has been seated in nipple  23 A, and nipple  23 A has been urged downwardly compressing spring  255 . The upper sleeve collar portion  216 A has moved downwardly away from the collet teeth  242 . Because of the resiliency of the collet  219 , when the collar portion  216 A is moved away from the upper end of the collet  219  and the collet is urged downwardly applying tension to spring  255  against shoulder  106 , the collet head  700  collapses inwardly and teeth  242  slide off tapered shoulder  227 . The collet  219  continues downwardly engaging the spline teeth  231 A. Spline mandrel  236  is urged downwardly (FIGS.  9 A and  10 A). Packer mandrel  237  moves downwardly causing pistons  239 A,  239 B, and  239 C to compress fluid in the associated reservoirs  265 A,  265 B, and  265 C (see FIGS. 11A,  12 A, and  13 A). As the fluid is compressed, the separate packer elements  211 A,  211 B, and  211 C are inflated (FIGS. 14A,  15 A, and  16 A) simultaneously, move downwardly along the borehole wall and wipe the wall surface for positive engagement and sealing of the borehole. 
     Compressed fluid from one of the reservoirs (in the present embodiment reservoir  265 C via conduit  281 C) opens the hydraulic float valve  312  to allow well fluids to enter the drilling test tool  201  for sampling. 
     To deactivate the drilling test tool the upper testing collar  213  is rotated one-quarter turn counterclockwise allowing the collet teeth  242  to disengage from the spline teeth  231  A. The spline mandrel  236  and the packer mandrel  237  are now urged upwardly by the downward movement of the upper collar when the tool is placed in contact with the bottom of the borehole. The spring  255  has a strength slightly greater than the collapse force necessary to release restriction c-ring  104  from groove  224 . The hydraulic float valve  312  may be closed by forcing the stem against the well bore bottom. 
     Once the tool is deactivated, drilling can be commenced. The splines  231  and  259  are able to transmit torque forces to the drill bit at the distal end of the drilling stem. 
     Although the invention has been described with reference to a specific embodiment, this description is not meant to be construed in a limiting sense. On the contrary, various modifications of the disclosed embodiments will become apparent to those skilled in the art upon reference to the description of the invention. It is therefore contemplated that the appended claims will cover such modifications, alternatives, and equivalents that fall within the true spirit and scope of the invention.

Summary:
An apparatus for in situ borehole testing having a drill string with drill pipe and drill bit. An upper sleeve and lower sleeve are telescopically coupled together. A valve seat is located in an interior passage and closes the interior passage when a valve member is seated in the valve seat. A plurality of separate inflatable packers are coupled to the lower sleeve and activated when the valve member is seated in the valve seat. A latching collet having teeth positively interlocks with spline teeth affixed to the inner wall of the upper sleeve. A hydraulic valve assembly is attached to the lower sleeve and is activated by fluid in one of a plurality of separate fluid chambers which communicate with and inflate the separate packers.