WO2005113938A2 - Methods for using a formation tester - Google Patents
Methods for using a formation tester Download PDFInfo
- Publication number
- WO2005113938A2 WO2005113938A2 PCT/US2005/018056 US2005018056W WO2005113938A2 WO 2005113938 A2 WO2005113938 A2 WO 2005113938A2 US 2005018056 W US2005018056 W US 2005018056W WO 2005113938 A2 WO2005113938 A2 WO 2005113938A2
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- WO
- WIPO (PCT)
- Prior art keywords
- formation
- pressure
- cylinder
- drawdown
- test procedure
- Prior art date
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
- E21B49/10—Obtaining fluid samples or testing fluids, in boreholes or wells using side-wall fluid samplers or testers
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/12—Packers; Plugs
- E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means
- E21B33/1216—Anti-extrusion means, e.g. means to prevent cold flow of rubber packing
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/008—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells by injection test; by analysing pressure variations in an injection or production test, e.g. for estimating the skin factor
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B49/00—Testing the nature of borehole walls; Formation testing; Methods or apparatus for obtaining samples of soil or well fluids, specially adapted to earth drilling or wells
- E21B49/08—Obtaining fluid samples or testing fluids, in boreholes or wells
Definitions
- zones of interest are often tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, bubble point, formation pressure gradient, mobility, filtrate viscosity, spherical mobility, coupled compressibility porosity, skin damage (which is an indication of how the mud filtrate has changed the permeability near the wellbore), and anisotropy (which is the ratio of the vertical and horizontal permeabilities).
- WFT Wireline formation testers
- DST drill stem testers
- the basic DST 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 formation fluid at the end of the test.
- WFTs generally employ the same testing techniques but use a wireline to lower the formation tester into the borehole after the drill string has been retrieved from the borehole.
- WFTs typically use packers also, although the packers are typically placed closer together, compared to DSTs, for more efficient formation testing. In some cases, packers are not even used. In those instances, the testing tool is brought into contact with the intersected formation and testing is done without zonal isolation.
- 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.
- isolation pad is critical to the performance of the tool. If the borehole fluid is allowed to leak into the collected formation fluid, a non-representative sample will be obtained and the test will have to be repeated. Examples of isolation pads and probes used in WFTs can be found in Halliburton' s
- Isolation pads that are used with WFTs are typically rubber pads affixed to the end of the extending sample probe.
- the rubber is normally affixed to a metallic plate that provides support to the rubber as well as a connection to the probe.
- the formation pressure measurement accuracy of drill stem tests and, especially, of wireline formation tests may be affected by mud filtrate invasion and mudcake buildup because significant amounts of time may have passed before a DST or WFT engages the formation after the borehole has been drilled.
- Mud filtrate invasion occurs when the drilling mud fluids displace formation fluid. 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 fluid 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 fluid.
- Mudcake buildup occurs when any solid particles in the drilling fluid are plastered to the side of the wellbore by the circulating drilling mud during drilling.
- the prevalence of the mudcake at the borehole surface creates a "skin".
- skin effect because formation testers can only extend relatively short distances into the formation, thereby distorting the representative sample of formation fluid due to the filtrate.
- the mudcake also acts as a region of reduced permeability adjacent to the borehole.
- FTWD formation tester while drilling
- Typical FTWD formation testing equipment is suitable for integration with a drill string during drilling operations.
- Fluid properties may include fluid compressibility, flowline fluid compressibility, density, resistivity, composition, and bubble point.
- the FTWD may use a probe similar to a WFT that extends to the formation and a small sample chamber to draw in formation fluid through the probe to test the formation pressure. To perform a test, the drill string is stopped from rotating and moving axially and the test procedure, similar to a WFT described above, is performed.
- FIGURE 1 is a schematic elevation view, partly in cross-section, of an embodiment of the formation tester disposed in a subterranean well
- FIGURES 2A-2E are elevation views, partly in cross-section, of portions of the bottomhole assembly and shown in FIGURE 1
- FIGURE 3 is an enlarged elevation view, partly in cross-section, of the formation tester shown in FIGURE 2D
- FIGURE 3 A is an enlarged cross-section view of the drawdown piston and chamber shown in FIGURE 3
- FIGURE 3B is an enlarged cross-section view along line 3B-3B of FIGURE 3
- FIGURE 4 is an elevation view of the formation tester shown in FIGURE 3
- FTGURE 5 is a cross-sectional view of the formation probe assembly taken along line 5-5 shown in FIGURE 4
- FIGURES 6A-6C are cross-sectional views of a portion of the formation probe assembly taken along the same line as seen in FIG
- 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.
- 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 of the borehole.
- 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.
- an MWD formation tester 10 is illustrated as a part of bottom hole assembly 6 (BHA) that comprises an MWD sub 13 and a drill bit 7 at its lower most end.
- BHA 6 bottom hole assembly 6
- the BHA 6 is lowered from a drilling platform 2, such as a ship or other conventional platform, via a drill string 5.
- the drill string 5 is disposed through a riser 3 and a well head 4.
- the formation tester 10 may be employed in other bottom hole assemblies and with other drilling apparatus in land-based drilling, as well as offshore drilling as shown in FIGURE 1. Tn all instances, in addition to formation tester 10, the bottom hole assembly 6 may contain various conventional apparatus and systems, such as a down hole drill motor, mud pulse telemetry system, measurement-while-drilling sensors and systems, and others well known in the art.
- the formation tester 10 is best understood with reference to FIGURES 2A-2E.
- the formation tester 10 generally comprises a heavy walled housing 12 made of multiple sections of drill collar 12a,12b,12c,12d that engage one another so as to form the complete housing 12.
- Bottom hole assembly 6 includes flow bore 14 formed through its entire length to allow passage of drilling fluids from the surface through the drill string 5 and through the bit 7.
- upper section 12a of housing 12 includes upper end 16 and lower end 17.
- Upper end 16 may include a threaded box for connecting formation tester 10 to drill string 5.
- Lower end 17 may include a threaded box for receiving a correspondingly threaded pin end of housing section 12b.
- Disposed between ends 16 and 17 in housing section 12a are three aligned and connected sleeves or tubular inserts 24a,b,c that create an annulus 25 between sleeves 24a,b,c and the inner surface of housing section 12a.
- Annulus 25 is sealed from flowbore 14 and provided for housing a plurality of electrical components, including battery packs 20,22.
- Battery packs 20,22 are mechanically interconnected at connector 26.
- Electrical connectors 28 are provided to interconnect battery packs 20,22 to a common power bus (not shown).
- Beneath battery packs 20,22 and also disposed about sleeve insert 24c in annulus 25 is electronics module 30.
- Electronics module 30 may also include various circuit boards, capacitors banks, and other electrical components, including the capacitors shown at 32.
- a connector 33 is provided adjacent upper end 16 in housing section 12a to electrically couple the electrical components in formation tester 10 with other components of bottom hole assembly 6 that are above housing 12.
- Beneath electronics module 30 in housing section 12a is an adapter insert 34.
- Adapter 34 connects to sleeve insert 24c at connection 35 and retains a plurality of spacer rings 36 in a central bore 37 that forms a portion of flowbore 14.
- Lower end 17 of housing section 12a connects to housing section 12b at threaded connection 40.
- Spacers 38 are disposed between the lower end of adapter 34 and the pin end of housing section 12b. Because threaded connections such as connection 40, at various times, need to be cut and repaired, the length of sections 12a, 12b may vary in length. Employing spacers 36, 38 allow for adjustments to be made in the length of threaded connection 40.
- Housing section 12b includes an inner sleeve 44 disposed therethrough. Sleeve 44 extends into housing section 12a above, and into housing section 12c below.
- housing section 12c includes upper box end 47 and lower box end 48, which may threadingly engage housing section 12b and housing section 12c, respectively.
- adjusting spacers 46 are provided in housing section 12c adjacent to end 47.
- inner mandrel 52 stabs into the upper end of formation tester mandrel 54, which is comprised of three axially aligned and connected sections 54a, b, and c. Extending through mandrel 54 is a deviated flowbore portion 14a. Deviating flowbore 14 into flowbore path 14a provides sufficient space within housing section 12c for the formation tool components described in more detail below. As best shown in FIGURE 2E, deviated flowbore 14a eventually centralizes near the lower end 48 of housing section 12c, shown generally at location 56.
- the cross-sectional profile of deviated flowbore 14a may be a non-circular in segment 14b, so as to provide as much room as possible for the formation probe assembly 50.
- electric motor 64 disposed about formation tester mandrel 54 and within housing section 12c are electric motor 64, hydraulic pump 66, hydraulic manifold 62, equalizer valve 60, formation probe assembly 50, pressure transducers 160, and drawdown piston 170.
- Hydraulic accumulators provided as part of the hydraulic system 200 for the operating formation probe assembly 50 are also disposed about mandrel 54 in various locations, one such accumulator 68 being shown in FIGURE 2D.
- Electric motor 64 may be a permanent magnet motor powered by battery packs 20,22 and capacitor banks 32. Motor 64 is interconnected to and drives hydraulic pump 66. Pump 66 provides fluid pressure for actuating formation probe assembly 50.
- Hydraulic manifold 62 includes various solenoid valves, check valves, filters, pressure relief valves, thermal relief valves, pressure transducer 160b and hydraulic circuitry employed in actuating and controlling formation probe assembly 50 as explained in more detail below.
- mandrel 52 includes a central segment 71. Disposed about segment 71 of mandrel 52 are pressure balance piston 70 and spring 76. Mandrel 52 includes a spring stop extension 77 at the upper end of segment 71.
- Stop ring 88 is threaded to mandrel 52 and includes a piston stop shoulder 80 for engaging corresponding annular shoulder 73 formed on pressure balance piston 70.
- Pressure balance piston 70 further includes a sliding annular seal or barrier 69.
- Barrier 69 consists of a plurality of inner and outer o-ring and lip seals axially disposed along the length of piston 70.
- Beneath piston 70 and extending below inner mandrel 52 is a lower oil chamber or reservoir 78, described more fully below.
- An upper chamber 72 is formed in the annulus between central portion 71 of mandrel 52 and the wall of housing section 12c, and between spring stop portion 77 and pressure balance piston 70.
- Spring 76 is retained within chamber 72, which is open through port 74 to annulus 150.
- drilling fluids may fill chamber 72 in operation.
- An annular seal 67 is disposed about spring stop portion 77 to prevent drilling fluid from migrating above chamber 72.
- Barrier 69 maintains a seal between the drilling fluid in chamber 72 and the hydraulic oil that fills and is contained in oil reservoir 78 beneath piston 70.
- Lower chamber 78 extends from barrier 69 to seal 65 located at a point generally noted as 83 and just above transducers 160 in FIGURE 2E.
- the oil in reservoir 78 completely fills all space between housing section 12c and formation tester mandrel 54.
- the hydraulic oil in chamber 78 may be maintained at slightly greater pressure than the pressure of the drilling fluid in annulus 150.
- the annulus pressure is applied to piston 70 via drilling fluid entering chamber 72 through port 74.
- Equalizer valve 60 is disposed in formation tester mandrel 54b between hydraulic manifold 62 and formation probe assembly 50. Equalizer valve 60 is in fluid communication with hydraulic passageway 85 and with longitudinal fluid passageway 93 formed in mandrel 54b. Prior to actuating formation probe assembly 50 so as to test the formation, drilling fluid fills passageways 85 and 93 as valve 60 is normally open and communicates with annulus 150 through port 84 in the wall of housing section 12c.
- valve 60 closes the passageway 85 to prevent drilling fluids from annulus 150 entering passageway 85 or passageway 93.
- a valve particularly well suited for use in this application is the valve described in U.S. Patent Application No. 10/440/637, filed May 19, 2003 and entitled “Equalizer Valve", hereby incorporated herein by reference for all purposes.
- housing section 12c includes a recessed portion 135 adjacent to formation probe assembly 50 and equalizer valve 60.
- the recessed portion 135 includes a planar surface or "flat" 136.
- the ports through which fluids may pass into equalizing valve 60 and probe assembly 50 extend through flat 136.
- Flat 136 may be recessed at least ' ⁇ inch and may be at least l A inch from the outer diameter of housing section 12c. Similar flats 137,138 are also formed about housing section 12c at generally the same axial position as flat 136 to increase flow area for drilling fluid in the annulus 150 of borehole 8. Disposed about housing section 12c adjacent to formation probe assembly 50 is stabilizer 154. Stabilizer 154 may have an outer diameter close to that of nominal borehole size. As explained below, formation probe assembly 50 includes a seal pad 140 that is extendable to a position outside of housing 12c to engage the borehole wall 151.
- probe assembly 50 and seal pad 140 of formation probe assembly 50 are recessed from the outer diameter of housing section 12c, but they are otherwise exposed to the environment of annulus 150 where they could be impacted by the borehole wall 151 during drilling or during insertion or retrieval of bottom hole assembly 6. Accordingly, being positioned adjacent to formation probe assembly 50, stabilizer 154 provides additional protection to the seal pad 140 during insertion, retrieval, and operation of bottom hole assembly 6. It also provides protection to pad 140 during operation of formation tester 10. In operation, a piston extends seal pad 140 to a position where it engages the borehole wall 151. The force of the pad 140 against the borehole wall 151 would tend to move the formation tester 10 in the borehole, and such movement could cause pad 140 to become damaged.
- mandrel 54c contains chamber 63 for housing pressure transducers 160a,c,d as well as electronics for driving and reading these pressure transducers.
- the electronics in chamber 63 contain memory, a microprocessor, and power conversion circuitry for properly utilizing power from power bus 700.
- housing section 12d includes pins ends 86,87.
- housing section 12d is an adapter used to transition from the lower end of formation tester 10 to the remainder of the bottom hole assembly 6.
- the lower end 87 of housing section 12d threadingly engages other sub assemblies included in bottom hole assembly 6 beneath formation tester 10.
- flowbore 14 extends through housing section 12d to such lower subassemblies and ultimately to drill bit 7.
- drawdown piston 170 is retained in drawdown manifold 89 that is mounted on formation tester mandrel 54b within housing 12c.
- Drawdown piston 170 includes annular seal 171 and is slidingly received in cylinder 172.
- Spring 173 biases drawdown piston 170 to its uppermost or shouldered position as shown in FIGURE 3 A.
- Separate hydraulic lines (not shown) interconnect with cylinder 172 above and below drawdown piston 170 in portions 172a, 172b to move drawdown piston 170 either up or down within cylinder 172 as described more fully below.
- a plunger 174 is integral with and extends from drawdown piston 170.
- Plunger 174 is slidingly disposed in cylinder 177 coaxial with 172.
- Cylinder 175 is the upper portion of cylinder 177 that is in fluid communication with the longitudinal passageway 93 as shown in FIGURE 3A.
- a flowline valve 179 controls flow of fluid through the passageway 93 between the drawdown piston 170 and the probe assembly 50.
- Cylinder 175 is flooded with drilling fluid via its interconnection with passageway 93.
- Cylinder 177 is filled with hydraulic fluid beneath seal 166 via its interconnection with hydraulic circuit 200.
- Plunger 174 also contains scraper 167 that protects seal 166 from debris in the drilling fluid.
- Scraper 167 may be an o-ring energized lip seal.
- formation probe assembly 50 generally includes stem 92, a generally cylindrical adapter sleeve 94, piston 96 adapted to reciprocate within adapter sleeve 94, and a snorkel assembly 98 adapted for reciprocal movement within piston 96.
- Housing section 12c and formation tester mandrel 54b include aligned apertures 90a, 90b, respectively, that together form aperture 90 for receiving formation probe assembly 50.
- Stem 92 includes a circular base portion 105 with an outer flange 106. Extending from base 105 is a tubular extension 107 having central passageway 108. The end of extension 107 includes internal threads at 109.
- Central passageway 108 is in fluid connection with fluid passageway 91 that, in turn, is in fluid communication with longitudinal fluid chamber or passageway 93, best shown in FIGURE 3.
- Adapter sleeve 94 includes inner end 111 that engages flange 106 of stem number 92. Adapter sleeve 94 is secured within aperture 90 by threaded engagement with mandrel 54b at segment 110. The outer end 112 of adapter sleeve 94 extends to be substantially flushed with flat 136 formed in housing member 12c. Circumferentially spaced about the outermost surface of adapter sleeve 94 is a plurality of tool engaging recesses 158.
- Adapter sleeve 94 includes cylindrical inner surface 113 having reduced diameter portions 114,115.
- a seal 1 16 is disposed in surface 1 14.
- Piston 96 is slidingly retained within adapter sleeve 94 and generally includes base section 118 and an extending portion 119 that includes inner cylindrical surface 120. Piston 96 further includes central bore 121.
- the snorkel 98 includes a base portion 125, a snorkel extension 126, and a central passageway 127 extending through base 125 and extension 126.
- the probe assembly 50 is assembled such that piston base 1 18 is permitted to reciprocate along surface 113 of adapter sleeve 94.
- screen 100 is a generally tubular member having a central bore 132 extending between a fluid inlet end 131 and outlet end 122. Outlet end 122 includes a central aperture 123 that is disposed about stem extension 107. Screen 100 further includes a flange 130 adjacent to fluid inlet end 131 and an internally slotted segment 133 having slots 134. Apertures 129 are formed in screen 100 adjacent end 122.
- screen 100 includes threaded segment 124 for threadingly engaging snorkel extension 126.
- the scraper 102 includes a central bore 103, threaded extension 104, and apertures 101 that are in fluid communication with central bore 103.
- Section 104 threadingly engages internally threaded section 109 of stem extension 107, and is disposed within central bore 132 of screen 100.
- seal pad 140 may be generally donut-shaped having base surface 141, an opposite sealing surface 142 for sealing against the borehole wall, a circumferential edge surface 143 and a central aperture 144.
- base surface 141 is generally flat and is bonded to a metal skirt 145.
- Seal pad 140 seals and prevents drilling fluid from entering the probe assembly 50 during formation testing so as to enable pressure transducers 160 to measure the pressure of the formation fluid. Changes in formation fluid pressure over time provide an indication of the permeability of the formation 9. More specifically, seal pad 140 seals against the mudcake 149 that forms on the 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 mudcake 149 on the borehole wall and separates the two pressure areas. Pad 140, when extended, conforms its shape to the borehole wall and, together with the mudcake 149, forms a seal through which formation fluid can be collected.
- pad 140 is sized so that it can be retracted completely within aperture 90. In this position, pad 140 is protected both by flat 136 that surrounds aperture 90 and by recess 135 that positions face 136 in a setback position with respect to the outside surface of housing 12.
- Pad 140 may be made of an elastomeric material having a high elongation characteristic. At the same time, the material may possess relatively hard and wear resistant characteristics. More particularly, the material may have an elongation % equal to at least 200% and even more than 300%.
- One such material useful in this application is Hydrogenated Nitrile Butadiene Rubber (HNBR).
- a material found particularly useful for pad 140 is HNBR compound number 372 supplied by Eutsler Technical Products of Houston, Texas, U.S.A. having a durometer hardness of 85 Shore A and a percent elongation of 370% at room temperature.
- Sealing surface 142 of pad 140 generally includes a spherical surface 162 and radius surface 164. Spherical surface 162 begins at edge 143 and extends to point 163 where spherical surface 162 merges into and thus becomes a part of radius surface 164. Radius surface 164 curves into central aperture 144 which passes through the center of the pad 140.
- pad 140 includes an overall diameter of 2.25 inches with the diameter of central aperture 144 being equal to 0.75 inches.
- Radius surface 164 has a radius of 0.25 inches, and spherical surface 162 has a spherical radius equal to 4.25 inches.
- the height of the profile of pad 140 is 0.53 inches at its thickest point. Referring again to FIGURES 7-9, when pad 140 is compressed, it may extrude into the recesses 152 in skirt 145. The corners 2008 of the recesses 152 can damage the pad, resulting in premature failure.
- An undercut feature 1000 shown in FIGURES 7 and 9 is cut into the pad to give space between the elastomeric pad 140 and the recesses 152.
- skirt 145 includes an extension 146 for threadingly engaging extending portion 119 of piston 96 (FIGURE 5) at threaded segment 147 (FIGURE 7 and 9).
- Skirt 145 may also include dovetail groove 149a as shown in FIGURE 9. When molded, the elastomer fills the dovetail groove. The groove acts to retain the elastomer in the event of de-bonding between the metal skirt 145 and the pad 140.
- a plurality of counterbores 149b (FIGURES 9a and 9b) in skirt 145 act to retain the elastomer. When molded, the elastomer fills the counterbores.
- snorkel extension 126 supports the central aperture 144 of pad 140 (FIGURE 7) to reduce the extrusion of the elastomer when it is pressed against the borehole wall during a formation test. Reducing extrusion of the elastomer helps to ensure a good pad seal, especially against the high differential pressure seen across the pad during a formation test.
- tool 10 may include, among other things, centralizers . for centralizing the formation probe assembly 50 and thereby normalizing pad 140 relative to the borehole wall.
- the formation tester 10 may include centralizing pistons coupled to a hydraulic fluid circuit configured to extend the pistons in such a way as to protect the probe assembly and pad, and also to provide a good pad seal.
- a formation tester including such devices is described in U.S. Patent Application Serial No. 10/440,593, filed May 19, 2003 and entitled “Method and Apparatus for MWD Formation Testing", hereby incorporated herein by reference for all purposes.
- the hydraulic circuit 200 used to operate probe assembly 50, equalizer valve 60, and drawdown piston 170 is illustrated in FIGURE 10.
- a microprocessor-based controller 190 is electrically coupled to all of the controlled elements in the hydraulic circuit 200 illustrated in FTGURE 10, although the electrical connections to such elements are conventional and are not illustrated other than schematically. Controller 190 is located in electronics module 30 in housing section 12a, although it could be housed elsewhere in bottom hole assembly 6.
- Controller 190 detects the control signals transmitted from a master controller (not shown) housed in the MWD sub 13 of the bottom hole assembly 6 which, 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. Controller 190 receives a command to initiate formation testing. This command may be received when the drill string is rotating or sliding or otherwise moving; however the drill string must be stationary during a formation test. As shown in FIGURE 10, motor 64 is coupled to pump 66 that draws hydraulic fluid out of hydraulic reservoir 78 through a serviceable filter 79. As will be understood, the pump 66 directs hydraulic fluid into hydraulic circuit 200 that includes formation probe assembly 50, equalizer valve 60, drawdown piston 170 and solenoid valves 176,178,180.
- the controller 190 energizes solenoid valve 180 and starts motor 64. Pump 66 then begins to pressurize hydraulic circuit 200 and, more particularly, charges probe retract accumulator 182. The act of charging accumulator 182 also ensures that the probe assembly 50 is retracted and that drawdown piston 170 is in its initial shouldered position as shown in FIGURE 3 A.
- the controller 190 When the pressure in system 200 reaches a predetermined value, such as 1800 psi as sensed by pressure transducer 160b, the controller 190, which continuously monitors pressure in the hydraulic circuit 200, energizes solenoid valve 176 and de-energizes solenoid valve 180, which causes the probe piston 96 and the snorkel 98 to begin to extend toward the borehole wall 151. Concurrently, check valve 194 and relief valve 193 seal the probe retract accumulator 182 at a pressure charge of between approximately 500 to 1250 psi. The piston 96 and the snorkel 98 extend from the position shown in FIGURE 6A to that shown in FIGURE 6B where the pad 140 engages the mudcake 49 on the borehole wall 151 .
- FIGURE 6C There are two expanded positions of snorkel 98, generally shown in FIGURES 6B and 6C.
- the piston 96 and snorkel 98 move outwardly together until the pad 140 engages the borehole wall 151. This combined motion continues until the force of the borehole wall against pad 140 reaches a pre-determined magnitude, for example 5,500 lb, causing pad 140 to be squeezed.
- a second stage of expansion takes place with snorkel 98 then moving within the cylinder 120 in piston 96 to penetrate the mudcake 49 on the borehole wall 151 and to receive formation fluid.
- the valve 192 opens so as to close the equalizer valve 60, thereby isolating the fluid passageway 93 from the annulus. In this manner, the valve 192 ensures that the valve 60 closes only after the seal pad 140 has entered contact with the mudcake 49 that lines the borehole wall 151.
- the pressure in circuit 200 rises and closes the equalizer valve 60, thereby isolating the fluid passageway 93 from the annulus.
- valve 60 may close before the seal pad 140 has entered contact with the mudcake 149 that lines the borehole wall 151.
- the passageway 93, now closed to the annulus 150, is in fluid communication with the cylinder 175 at the upper end of the cylinder 177 in drawdown manifold 89, best shown in FIGURE 3A.
- the solenoid valve 176 With the solenoid valve 176 still energized, the probe seal accumulator 184 is charged until the system reaches a predetermined pressure, for example 1800 psi, as sensed by the pressure transducer 160b. When that pressure is reached, a delay may occur before the controller 190 energizes the solenoid valve 178 to begin drawdown.
- This delay which is controllable, can be used to measure properties of the mudcake 149 that lines the borehole wall 151.
- Energizing the solenoid valve 178 permits pressurized fluid to enter the portion 172a of the cylinder 172 causing the drawdown piston 170 to retract.
- the plunger 174 moves within the cylinder 177 such that the volume of the fluid passageway 93 increases by the volume of the area of the plunger 174 times the length of its stroke along the cylinder 177.
- This movement increases the volume of cylinder 175, thereby increasing the volume of the fluid passageway 93.
- the volume of the fluid passageway 93 may be increased by 10 cc as a result of the drawdown piston 170 being retracted.
- the fluid chambers 93 which include the volume of various interconnected fluid passageways, including passageways in the probe assembly 50, the passageways 85,93 [FIGURE 3], the passageways interconnecting 93 with drawdown piston 170 and the pressure transducers 160a,c may have a volume of approximately 40cc.
- Drilling mud in the annulus 150 is not drawn into snorkel 98 because pad 140 seals against the mudcake.
- Snorkel 98 serves as a conduit through which the formation fluid may pass and the pressure of the formation fluid may be measured in passageway 93 while pad 140 serves as a seal to prevent annular fluids from entering the snorkel 98 and invalidating the formation pressure measurement.
- formation fluid is drawn first into the central bore 132 of screen 100. It then passes through slots 134 in screen slotted segment 133 such that particles in the fluid are filtered from the flow and are not drawn into passageway 93.
- the formation fluid then passes between the outer surface of screen 100 and the inner surface of snorkel extension 126 where it next passes through apertures 123 in screen 100 and into the central passageway 108 of stem 92 by passing through apertures 101 and central passage bore 103 of scraper 102.
- check valve 195 maintains the desired pressure acting against piston 96 and snorkel 98 to maintain the proper seal of pad 140.
- the probe seal accumulator 184 is fully charged, should the tool 10 move during drawdown, additional hydraulic fluid volume may be supplied to the piston 96 and the snorkel 98 to ensure that pad 140 remains tightly sealed against the borehole wall. Tn addition, should the borehole wall 151 move in the vicinity of pad 140, the probe seal accumulator 184 will supply additional hydraulic fluid volume to piston 96 and snorkel 98 to ensure that pad 140 remains tightly sealed against the borehole wall 151. Without accumulator 184 in circuit 200, movement of the tool 10 or borehole wall 151, and thus of formation probe assembly 50, could result in a loss of seal at pad 140 and a failure of the formation test.
- drawdown piston 170 With the drawdown piston 170 in its fully retracted position and formation fluid drawn into closed system 93, the pressure will stabilize and enable pressure transducers 160a,c to sense and measure formation fluid pressure. The measured pressure is transmitted to the controller 190 in the electronic section where the information is stored in memory and, alternatively or additionally, is communicated to the master controller in the MWD tool 13 below the formation tester 10 where it can be transmitted to the surface via mud pulse telemetry or by any other conventional telemetry means. When drawdown is completed, drawdown piston 170 actuates a contact switch 320 mounted in endcap 400 and drawdown piston 170, as shown in FIGURE 3 A.
- the drawdown switch assembly consists of contact 300, wire 308 coupled to contact 300, plunger 302, spring 304, ground spring 306, and retainer ring 310.
- the drawdown piston 170 actuates switch 320 by causing plunger 302 to engage contact 300 that causes wire 308 to couple to system ground via contact 300 to plunger 302 to ground spring 306 to drawdown piston 170 to endcap 400 that is in communication with system ground (not shown).
- controller 190 responds by shutting down motor 64 and pump 66 for energy conservation.
- Check valve 196 traps the hydraulic pressure and maintains drawdown piston 170 in its retracted position.
- drawdown accumulator 186 will provide the necessary fluid volume to compensate for any such leakage and thereby maintain sufficient force to retain drawdown piston 170 in its retracted position.
- controller 190 continuously monitors the pressure in fluid passageway 93 via pressure transducers 160a,c until the pressure stabilizes, or after a predetermined time interval. When the measured pressure stabilizes, or after a predetermined time interval, controller 190 de-energizes solenoid valve 176. De-energizing solenoid valve 176 removes pressure from the close side of equalizer valve 60 and from the extend side of probe piston 96.
- controller 190 After a predetermined pressure, for example 1800 psi, is sensed by pressure transducer 160b and communicated to controller 190 (indicating that the equalizer valve is open and that the piston and snorkel are fully retracted), controller 190 de-energizes solenoid valve 178 to remove pressure from side 172a of drawdown piston 170. With solenoid valve 180 remaining energized, positive pressure is applied to side 172b of drawdown piston 170 to ensure that drawdown piston 170 is returned to its original position (as shown in FIGURE 3). Controller 190 monitors the pressure via pressure transducer 160b and when a predetermined pressure is reached, controller 190 determines that drawdown piston 170 is fully returned and it shuts off motor 64 and pump 66 and de-energizes solenoid valve 180.
- a predetermined pressure for example 1800 psi
- FIGURE 11 illustrates a pressure versus time graph illustrating in a general way the pressure sensed by pressure transducer 160a,c during the operation of the formation tester 10. As the formation fluid is drawn within the formation tester 10, pressure readings are taken continuously by the transducers 160a,c.
- the pressure sensed by the transducers 160a,c will initially be equal to the annulus, or borehole, pressure shown at point 201.
- pad 140 is extended and equalizer valve 60 is closed, there will be a slight increase in pressure as shown at 202. This occurs when the pad 140 seals against the borehole wall 151 and squeezes the drilling fluid trapped in the now-isolated passageway 93.
- the drawdown piston 170 is actuated, the volume of the closed passageway 93 increases, causing the pressure to decrease as shown in region 203.
- a differential pressure with the formation fluid exists causing the fluid in the formation to move towards the low pressure area and, therefore, causing the pressure to build over time as shown in region 204.
- the formation tester 10 may include four pressure transducers 160: two quartz crystal gauges 160a,d, a strain gauge 160c, and a differential strain gage 160b.
- One of the quartz crystal gauges 160a is in communication with the annulus, or borehole, fluid and also senses formation pressures during the formation test.
- the other quartz crystal gauge 160d is in communication with the flowbore 14 at all times.
- both quartz crystal gauges 160a and 160d may have temperature sensors associated with the crystals.
- the temperature sensors may be used to compensate the pressure measurement for thermal effects.
- the temperature sensors may also be used to measure the temperature of the fluids near the pressure transducers.
- the temperature sensor associated with quartz crystal gauge 160a is used to measure the temperature of the fluid near the gage in the passageway 93.
- the third transducer is a strain gauge 160c and is in communication with the annulus fluid and also senses formation pressures during the formation test.
- the quartz transducers 160a,d provide accurate, steady-state pressure information, whereas the strain gauge 160c provides faster transient response.
- the passageway 93 is closed off and both the annulus quartz gauge 160a and the strain gauge 160c measure pressure within the closed passageway 93.
- the strain gauge transducer 160c essentially is used to supplement the quartz gauge 160a measurements.
- the quartz transducers 160a,d may operatively measure pressure while drilling to serve as a pressure while drilling tool.
- FIGURE 12 illustrates representative formation test pressure curves.
- the solid curve 220 represents pressure readings P sg detected and transmitted by the strain gauge 160c.
- the pressure P q indicated by the quartz gauge 160a, is shown as a dashed line 222.
- strain gauge transducers generally do not offer the accuracy exhibited by quartz transducers and quartz transducers do not provide the transient response offered by strain gauge transducers.
- the instantaneous formation test pressures indicated by the strain gauge 160c and quartz 160a transducers are likely to be different. For example, at the beginning of a formation test, the pressure readings P nyd ⁇ indicated by the quartz transducer Pq and the strain gauge P sg transducer are different and the difference between these values is indicated as E 0tfS ⁇ in FIGURE 12.
- the actual formation test pressures may be calculated by adding or subtracting the appropriate offset error E 0 f fS ⁇ to the pressures indicated by the strain gauge P sg for the duration of the formation test.
- the accuracy of the quartz transducer and the transient response of the strain gauge may both be used to generate a corrected formation test pressure that, where desired, is used for real-time calculation of formation characteristics.
- the strain gauge readings may become more accurate or for the quartz gauge reading to approach actual pressures in the pressure chamber even though that pressure is changing.
- the formation tester 10 may operate in two general modes: pump-on operation and pump-off operation.
- pump on operation mud pumps on the surface pump drilling fluid through the drill string 6 and back up the annulus 150.
- the tool 10 can transmit data to the surface using mud pulse telemetry during the formation test.
- the tool 10 may also receive mud pulse telemetry downlink commands from the surface.
- the drill string 6 and the formation tester 10 are not rotated. However, it may be the case that an immediate movement or rotation of the drill string 6 will be necessary.
- an abort command can be transmitted from surface to the formation tester 10.
- the formation tester 10 will immediately discontinue the formation test and retract the probe piston to its normal, retracted position for drilling.
- the drill string 6 can then be moved or rotated without causing damage to the formation tester 10.
- a similar failsafe feature may also be active.
- the formation tester 10 and/or MWD tool 13 may be adapted to sense when the mud flow pumps are turned on. Consequently, the act of turning on the pumps and reestablishing flow through the tool may be sensed by pressure transducer 160d or by other pressure sensors in bottom hole assembly 6. This signal will be interpreted by a controller in the MWD tool 13 or other control and communicated to controller 190 that is programmed to automatically trigger an abort command in the formation tester 10.
- the uplink and downlink commands are not limited to mud pulse telemetry.
- 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.
- EM electromagnetic
- 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 failsafe abort command may therefore be sent from the surface to the formation tester 10 using an alternative telemetry system regardless of whether the mud flow pumps are on or off.
- the down hole receiver for downlink commands or data from the surface may reside within the formation tester 10 or within an MWD tool 13 with which it communicates.
- the down hole transmitter for uplink commands or data from down hole may reside within the formation tester 10 or within an MWD tool 13 with which it communicates.
- the receivers and transmitters may each be positioned in MWD tool 13 and the receiver signals may be processed, analyzed, and sent to a master controller in the MWD tool 13 before being relayed to local controller 190 in formation testing tool 10.
- Commands or data sent from surface to the formation tester 10 can be used for more than transmitting a failsafe abort command.
- the formation tester 10 can also have many other operating modes that may be selected using a command from the surface. For example, one of a plurality of operating modes may be selected by transmitting a header sequence indicating a change in operating mode followed by a number of pulses that correspond to that operating mode.
- an operating mode may be selected from the surface to the formation tester 10.
- This information may include critical operational data such as depth or surface drilling mud density.
- the formation tester 10 may use this information to help refine measurements or calculations made downhole or to select an operating mode. Commands from the surface might also be used to program the formation tester 10 to perform in a mode that is not preprogrammed.
- An example of an operating mode of the formation tester 10 is the ability of the formation tester 10 to adapt the pressure test procedure to the bubble point of the formation fluid at different test depths.
- formation fluid can contain some natural gas in solution.
- the bubble point is the pressure at which the gas comes out of solution in the formation fluid at a given temperature.
- FTGURE 13 illustrates a drawdown test procedure where the bubble point of the fluid in the formation tester 10 is exceeded.
- the pressure declines rapidly during the drawdown and in low permeability zones the slope is typically directly proportional to the flow rate. This slope is due primarily to the compressibility of the fluid in the flow line of the tool 10.
- the slope changes when the bubble point is encountered as shown in FTGURE 13 at the line marked "Bubble Point". This change in slope can be caused by formation fluids entering the tool 10, but when the pressure does not start to build up after the end of the drawdown (t end i ), then the bubble point has been exceeded.
- the effective compressibility of the flowline fluid is increased substantially showing the buildup.
- some fluid enters the tool 10 from the formation and at some point the gas is absorbed into solution.
- the compressibility of the flowline fluids is reduced and the buildup rate increases rapidly.
- Both the inflection point during the drawdown and buildup can be used to estimate the bubble point of the fluid in the tool 10. This can be accomplished by monitoring the slope of the buildup using standard regression techniques. For example, the drawdown stage can be analyzed. Initially the slope is very sharp but changes to nearly 0 when the bubble point is encountered. In this case the initial drawdown curve can be compared to the remaining data and the intersection of these two curves is the bubble point.
- n 0 set number of points (usually 30 to 120 points).
- the beginning slope b is much larger than the ending slope b Q and the bubble point is determined by the intersection of the two lines.
- the linear regression techniques shown are one of several methods that can be used to determine curve inflection points and the subsequent bubble points. Derivative and second derivatives and non linear regression methods may also be used.
- the bubble point determined from the buildup is typically higher than that determined from the drawdown (see FIGURE 13). This is due to the thermodynamic changes that occur during the rapid drawdown and then the slow buildup. Typically the fluid is cooled due to adiabatic expansion during the drawdown. This cooling effect tends cause the bubble point to be underestimated. During the buildup the temperature equalizes and the apparent bubble point also increases. In the case where the bubble point and time is determined from the buildup curve, the formation mobility can be estimated by making a few assumptions.
- the formation spherical mobility can be estimated as follows.
- the drawdown method assumes steady state flow. This is one of several that can be used to estimate the mobility. Other methods could include spherical homer and derivative plots.
- the operating mode of the formation tester 10 may be adjusted to account for the bubble point of the formation fluid. For example, if the bubble point is breached, the drawdown piston 170 may be moved back to the starting position and the pressure test performed over again.
- the second pretest is performed at the new rate.
- Still another method of performing the second drawdown is to set a cutoff pressure. The pretest would stop as soon as this pressure is reached. The cutoff pressure would be higher than the estimated bubble point pressure, usually by several hundred psi. Again the second pretest would be performed after the flowline pressure has been equalized back to nearly hydrostatic mud pressure. This second pretest would start at the same rate as the first but then the pretest piston displacement is stopped when the pressure reaches the cutoff pressure. Still another method is to both adjust the flow rate and set a cutoff pressure. It may not be possible for the formation tester 10 to reduce its rate to that required to maintain the pressure above the buddle point. The slower rate reduces the change in pressure over time and makes stopping the pretest piston at the prescribe cutoff pressure more accurate. As another example, if the test is allowed sufficient time to build up as illustrated in
- FIGURE 13 The pressure is allowed to build up and the gas allowed to recombine with the fluids from the formation.
- the amount of time for the gas to recombine may depend on the bubble point pressure and the characteristics of the test fluid. From this information, the formation permeability can be estimated and the drawdown rate can be adjusted so that the drawdown pressure would not fall below the bubble point. Alternatively, the drawdown of the drawdown piston 170 may be done incrementally until a proper drawdown and buildup are achieved. Using this method, the drawdown piston 170 is drawn down, but not to the full extent under a normal pressure test. The pressure is then monitored in the cylinder 175 using the transducers 160.
- the drawdown piston 170 is drawn down again to create more of a pressure drop within the cylinder 175.
- the drawdown may be adjusted by drawing the drawdown piston 170 more or at a faster rate, or a combination of magnitude and rate. This method may be performed until a proper drawdown and build up are achieved.
- parameters for the pressure test may be set based on the incremental drawdown steps to ensure that the bubble point is not reached with further pressure tests.
- Other operating modes involve the formation tester 10 determining the bubble point of the formation fluid by performing a pressure test to purposefully bubble point the formation fluid.
- the flowline valve 179 may be closed and the drawdown piston 170 drawn down to lower the pressure in the cylinder 175 and create a known volume within the cylinder 175. Once the drawdown piston 170 is retracted, the flowline valve 179 may be opened. With enough pressure drop, the formation fluid will breach its bubble point and any gas in the formation fluid will come out of solution. If the bubble point is not breached, then the test is repeated until enough of an initial pressure drop is created to breach the bubble point. Normally the pretest is moved at it slowest rate while monitoring pressure of the sealed flowline. Then the method of determining the bubble point would be similar to that shown earlier for a pretest drawdown. Basically linear regressions can be used to determine when a slope change occurs.
- the first or second derivative as well as nonlinear regression methods can be used to determine the bubble point. It is also desirable to measure the piston displacement to more accurately monitor the actual rate and volume change. Alternatively the volume change over the total initial trapped volume can be plotted against pressure to improve the bubble point estimate and determine fluid compressibility.
- the formation tester 10 may use the position of the drawdown piston 170 as the drawdown piston 170 retracts during the drawdown portion of the pressure test. Knowing the position of the drawdown piston 170, the volume of the cylinder 175 at all positions of drawdown piston 170 may then be calculated.
- One method to determine position of the drawdown piston 170 is to measure the amount of hydraulic fluid used to drawdown the drawdown piston 170, the time, and the flowrate of the hydraulic fluid pumped by the hydraulic pump 66. Then, knowing the surface area of the face of the drawdown piston 170 facing the flowline side 172a of the cylinder 172, the position of the drawdown piston 170 may be calculated.
- the displacement distance of the drawdown piston 170 is the change in volume of the hydraulic fluid divided by the surface area of the drawdown piston 170 facing the flowline side 172a. The change in volume is calculated by multiplying the amount of time by the flowrate of the hydraulic fluid.
- Another method of determining position is using a position indicator such as an acoustic sensor, an optical sensor, a linear variable displacement transducer, a potentiometer, a Hall Effect sensor, or any other suitable position indicator or any other suitable method of determining position of the drawdown piston 170.
- the pressure at which the formation fluid reaches the bubble point can be calculated during the pressure test manually or by using the controller 190.
- the controller 190 continuously records elapsed time and the formation fluid pressure during the pre-test.
- the master controller 190 can continuously calculate the compressibility of the fluid in the flow line 93, where compressibility is the ratio of the formation fluid pressure to the formation fluid volume.
- the bubble point may be the pressure where these calculated ratios change.
- An example of compressibility and bubble point determination is illustrated in
- FIGURE 14 where volume change over the initial volume is plotted against pressure.
- the straight line portion is used to determine the fluid compressibility and the bubble point is determined with the pressure curve deviates from the straight line.
- the bubble point can be determined by the curve fitting methods previously discussed.
- the operating mode of the formation tester 10 may be adjusted so as to stay above the bubble point and keep the gas in solution in the formation fluid during the pressure test.
- the formation tester 10 may variably control the drawdown volume created in the cylinder 175 during the pressure test.
- the most effective method of controlling the drawdown volume is by using the cutoff pressure discussed previously. It is normally desirable to also slow the rate to improve the cutoff pressure methods accuracy.
- formation tester 10 may variably control the drawdown rate of the drawdown piston 170 so as to stay above the bubble point pressure. As discussed previously if the formation spherical mobility can be estimated then a rate can be calculated that would keep the drawdown pressure above the bubble point. Also alternatively, the formation tester 10 may variably control both the drawdown volume and the drawdown rate of the drawdown piston 170 as discussed above. The formation tester 10 may variably control the drawdown of the drawdown piston 170 to maintain a certain pressure within the cylinder 175 manually or automatically. When done manually, the measured pressure information from the pressure test is recorded and/or sent to the surface where it is monitored and analyzed.
- commands may be sent to the formation tester 10 to vary the drawdown procedure and avoid the bubble point for the next pressure test as discussed previously.
- the pressure test information is sent to the controller 190 for analysis of the bubble point.
- the controller 190 then automatically adjusts the drawdown volume and/or rate of the drawdown piston 170 for the next drawdown procedure to avoid breaching the bubble point as discussed above.
- Another mode of operation involves the consistency of the drawdown rate of the drawdown piston 170 during a pressure test.
- the formation tester 10 does not change the drawdown rate of the drawdown piston 170 during a pressure test.
- the controller 190 may change the drawdown rate of the drawdown piston 170 during a drawdown by controlling the hydraulic pump 66.
- the drawdown piston 170 when being drawn down, should maintain a substantially constant drawdown rate until the controller 190 adjusts the drawdown rate.
- the positional information of the drawdown piston 170 during drawdown may be taken into account in any pressure test calculations, not maintaining the drawdown rate of the piston 170 constant may affect the accuracy of pressure test measurements and calculations. Maintaining a constant drawdown rate may be difficult to achieve, however, due to the start-up, shut-down, or otherwise inconsistent output of the electric motor 64 and hydraulic pump 66, as well as other system factors.
- the formation tester 10 may send the drawdown piston 170 positional information to the controller 190.
- the controller 190 uses the positional information to calculate the drawdown rate of the piston 170.
- FIGURE 15 illustrates another method of maintaining a substantially constant drawdown rate using a hydraulic threshold 406, for example a sequencing valve, downstream of the hydraulic pump 66.
- the hydraulic threshold 406 requires that a certain hydraulic pressure be achieved by the electric motor 64 and hydraulic pump 66 before the hydraulic fluid is allowed to pass through the hydraulic threshold 406.
- the minimum hydraulic pressure might be 2500 psi above the borehole pressure.
- the hydraulic threshold 406 acts to allow the pressure to build up before the pressure is allowed to act on the drawdown piston 170.
- FIGURE 16 illustrates another method of maintaining a steady drawdown rate with a pressure compensated variable restrictor 408 in the hydraulic flowline 93 downstream of the hydraulic pump 66.
- the variable restrictor 408 maintains a constant hydraulic flowrate independent of the required hydraulic load. Therefore, the drawdown piston 170 is able to drawdown at a constant rate independent of the actual drawdown pressure achieved within flowline 93.
- FIGURE 17 illustrates another operating mode that allows the formation tester 10 to perform a burst test.
- the burst test may be performed when the drawdown piston 170 cannot drawdown fast enough to create a sufficient pressure drop for the pressure test.
- the formation tester 10 closes the flowline valve 179 to isolate the cylinder 175 from the pad 140.
- the drawdown piston 170 is then drawn down to create a pressure drop within the cylinder 175 and flowline 93 behind the flowline valve 179.
- the flowline valve 179 is then opened to create a pressure drop in the pad 140 side of the flowline 93 that is large enough to get sufficient drawdown for the pressure test.
- the flowline valve 179 is closed by actuating solenoid valve 412, which directs pressurized hydraulic fluid from the pump 66 to the actuator of valve 179.
- the pressure of the flowline upstream of the flowline valve 179 may be monitored by the pressure transducer 160d.
- the flowline valve 179 may be opened by de-actuating solenoid valve 412 and actuating solenoid valve 410.
- the burst test thus allows the formation tester 10 to create a larger pressure drop than if the drawdown piston 170 were drawn down in a typical pressure test due to the creation of the pressure drop before the formation fluid enters the cylinder 175.
- Another operating mode allows the formation tester 10 to make adjustments during the pressure test relating to the seal formed by seal pad 140 of formation probe assembly 50 against the borehole wall 151 or the mudcake 149.
- the operating environment of the borehole 8 can change during the pressure test with either a change in pressure or a deterioration of the borehole wall 151.
- the electric motor 64, hydraulic pump 66, hydraulic manifold 62, equalizer valve 60, formation probe assembly 50, or any other parts of hydraulic system 200 may also affect the ability to maintain a proper seal against the mudcake 149 or borehole wall 151.
- the formation tester 10 makes adjustments by monitoring the integrity of the seal of the pad 140 using the pressure transducers 160a-d.
- the formation tester 10 uses the transducer data to make adjustments manually using data sent back and forth between the surface and the controller 190 or automatically by sending the monitored information to the controller 190 for analysis.
- the controller 190 may retract the pad 140 and re-initiate the pressure test. Alternatively, a leak may occur during the pressure test causing the pad 140 to seal improperly. If the seal deteriorates, the formation tester 10 may make adjustments to the hydraulic system 200 to vary the pad force against the mudcake 149 or borehole wall 151. For example, the controller 190 may increase the hydraulic pressure to exert more force by the pad 140 against the mudcake 149 or the borehole wall 151.
- the tool 10 may send information regarding the adjustments to the surface as well as information regarding the amount of additional time needed to properly run the pressure test.
- the formation tester 10 may comprise a sequencing valve, similar to the valve 192 discussed above, that requires a minimum pressure on the pad 140 to create force against the mudcake 149 or the borehole wall 151 before the pressure test may be performed. Although the amount of pressure may not guarantee a good seal, the sequencing valve ensures that a designated minimum pressure be placed on the pad 140 before the pressure test may be performed.
- the controller 190 may also be used to vary any one of the pressure test parameters to experiment with and optimize the testing procedures.
- the buildup, drawdown rate, drawdown volume, pad load, or any other parameter may be varied to observe the changes, if any, to the results of the formation pressure test.
- the results may then be analyzed by the controller 190 and the testing procedures changed to obtain more precise formation pressure measurements.
Abstract
Description
Claims
Priority Applications (7)
Application Number | Priority Date | Filing Date | Title |
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BRPI0511443A BRPI0511443B1 (en) | 2004-05-21 | 2005-05-23 | method of testing a descending hole formation |
CA2557384A CA2557384C (en) | 2004-05-21 | 2005-05-23 | Methods for using a formation tester |
AU2005245977A AU2005245977B2 (en) | 2004-05-21 | 2005-05-23 | Methods for using a formation tester |
GB0624951A GB2430957B (en) | 2004-05-21 | 2005-05-23 | Methods for using a formation tester |
NO20065932A NO342307B1 (en) | 2004-05-21 | 2006-12-20 | Testing of the bedrock around a borehole with a formation tester on a drill string |
NO20171500A NO343627B1 (en) | 2004-05-21 | 2017-09-18 | Testing of the bedrock around a borehole with a formation tester on a drill string |
NO20171499A NO343465B1 (en) | 2004-05-21 | 2017-09-18 | Testing of the bedrock around a borehole with a formation tester on a drill string |
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US57342304P | 2004-05-21 | 2004-05-21 | |
US60/573,423 | 2004-05-21 | ||
US11/132,475 US7216533B2 (en) | 2004-05-21 | 2005-05-19 | Methods for using a formation tester |
US11/132,475 | 2005-05-19 |
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AU (1) | AU2005245977B2 (en) |
BR (1) | BRPI0511443B1 (en) |
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NO343627B1 (en) | 2019-04-15 |
NO342307B1 (en) | 2018-05-07 |
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GB2450609A (en) | 2008-12-31 |
NO20171500A1 (en) | 2007-02-20 |
CA2557384A1 (en) | 2005-12-01 |
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BRPI0511443A (en) | 2007-12-26 |
GB2430957B (en) | 2009-03-18 |
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US20050268709A1 (en) | 2005-12-08 |
GB0624951D0 (en) | 2007-01-24 |
GB0811260D0 (en) | 2008-07-30 |
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