BRPI0511430B1 - method of using a training property - Google Patents

Abstract

Method of Using a Forming Property This application concerns various methods and apparatus for quickly obtaining accurate forming property data from a drilled ground drillhole. once obtained, formation property data, including formation fluid pressure, can be corrected, calibrated and supplemented using various other data and techniques disclosed herein. In addition, forming property data may be used for a variety of other purposes. for example, the data may be used to correct or supplement other information obtained from the drillhole; they can be used to supplement training images or models; or they can be used to set a drilling or production parameter. Several other uses of accurately and quickly obtained formation property data are also disclosed.

Description

"METHOD OF USING A TRAINING PROPERTY" BACKGROUND OF THE INVENTION

During drilling and completion of oil and gas wells, it may be necessary to perform ancillary operations such as monitoring the operability of equipment used during the drilling process or assessing the production capabilities of wells intercepted by well drilling. After a well or well interval has been drilled, zones of interest are generally tested to determine various formation properties such as permeability, fluid type, fluid quality, formation temperature, formation pressure, bubble point and gradient. Forming pressure, these tests are performed to determine whether commercial exploitation of intercepted formations is feasible and how to optimize production.

Drill line formation (WFT) and drill string testers (DST) have typically been used to perform these tests. The basic DST test tool consists of one or more surface shutters, valves or holes that can be opened and closed from the surface and two or more pressure recording devices. The tool is lowered into a working column to the area to be tested. The shutter (s) are mounted, and drilling fluid is evacuated to isolate the drilling fluid column zone. The valves or orifices are then opened to allow flow of the formation to the test tool while the registers graph the static pressures. A sampling chamber traps clean formation fluids at the end of the test. WFTs generally employ the same testing techniques, but use a drill cable to lower the test tool in the well drilling after the drill string has been recovered from the well drilling, although WFT technology is sometimes deployed in a well. pipe column. The drill rope tool typically uses plugs as well, although the plugs are placed close together compared to testers transferred by the drill pipe for a more efficient forming test. In some cases, shutters are not used. In such cases, the test tool is placed in contact with the intercepted formation and the test is performed without zonal isolation through the axial span of the borehole wall circumference. WFTs may also include a probe assembly for engaging with the borehole wall and acquiring formation fluid samples. The probe assembly may include an insulating block to engage the drillhole wall. The insulating block seals in and around a hollow probe that places an internal cavity in fluid communication with the formation. This creates a fluid path that allows formation fluid to flow between the formation and the formation tester while being isolated from the borehole fluid. In order to acquire a valid sample, the probe must remain isolated from the high relative pressure of the borehole fluid. Therefore, the integrity of the seal that is formed by the insulating block is critical to tool performance. If drillhole fluid can leak into the collected formation fluids, an unrepresentative sample will be obtained and the test will have to be repeated.

Examples of insulating blocks and probes used in WFTs can be found in Halliburton DT, SFTT, SFT4 and RDT tools. Insulating blocks that are used with WFTs are typically rubber blocks attached to the end of the extension sample probe. The rubber is usually attached to a sheet metal that supports the rubber as well as a fitting on the probe. These rubber blocks are usually molded to fit the specific diameter hole in which they will be operating.

Using WFTs and DSTs, the drill string with the drill bit must be retracted from the drillhole. Then a separate working column containing the test rig, or, with WFTs, the drill string tool column, must be lowered into the well to conduct secondary operations. Interrupting the drilling process to perform formation testing can add significant amounts of time to a drilling program. STDs and WFTs may also cause tool sticking or formation damage. There may also be difficulties descending WFTs into highly deviated or extended range wells. WFTs also do not have flow holes for drilling mud flow, nor are they designed to withstand drilling loads such as torque and drill weight.

In addition, the accuracy of drill string test formation pressure measurement and especially of drill string formation tests may be affected by filtrate invasion and accumulation of drilling mud sludge due to quantities significant time lapses before an STD or WFT fit into the formation. Mud filtrate invasion occurs when drilling mud fluids displace formation fluids. Because sludge filtrate ingress into the formation begins at the borehole surface, it is more prevalent there, and generally decreases further inward into the formation. When filtrate invasion occurs, it may be impossible to obtain a representative sample of formation fluids or, at a minimum, the duration of the sampling period must be increased first to remove the drilling fluid and then to obtain a sample. representative of formation fluids. The mud deposit consists of solid particles adhering to the well side by the circulating drilling mud during drilling. The prevalence of the drilling mud sludge deposit on the drillhole surface creates a "wall". Thus, there may be a "wall effect" because the formation testers can only extract fluids from relatively short distances in the formation, thus distorting the representative sample of formation fluids because of the filtrate. The mud deposit also acts as a region of lower permeability adjacent to the borehole. Thus, once the sludge deposit forms, the accuracy of the reservoir pressure measurements decreases, affecting formation permeability and productivity calculations.

Another test device is the FTWD. Typical FTWD forming test equipment is suitable for integration with a drill string during drilling operations. Various devices or systems are used to isolate a formation from the remainder of the well drilling, extract fluid from the formation and measure physical properties of the fluid and formation. For example, the FTWD may use a WFT-like probe that extends to the formation and a small sample chamber to extract formation fluids through the probe to test the formation pressure. To perform a test, the drill string stops rotating and the test procedure, similar to a WFT described above, is performed. US 6157893 discloses an apparatus and method for obtaining samples of untouched formation or fluid formation using a work column designed for other downhole work such as drilling, workover operations. , or reentry operations. US 6044325 discloses a method for generating an improved estimate of horizontal conductivity, dip angle, azimuth parameter and anisotropy of a wellbore penetrated ground formation from double frequency transverse electromagnetic induction measurements. However, none of these documents comprise the features of the present invention which will be described below.

BRIEF DESCRIPTION OF DRAWINGS

For a more detailed description of preferred embodiments of the present invention, reference will now be made to the accompanying drawings, in which: Figure 1 is a schematic elevation view, sparingly in cross section, of one embodiment of a formation test apparatus arranged in an underground well.

Figures 2A-2E are elevational views, partially in cross section, of parts of the bottom hole assembly and formation test assembly shown in Figure 1; Figure 3 is an enlarged elevation view, partially in cross section, of the forming test tool portion of the forming test assembly shown in Figure 2D; Figure 3A is an enlarged cross-sectional view of the lowering piston and chamber shown in Figure 3; Figure 3B is an enlarged cross-sectional view taken along line 3B-3B of Figure 3: Figure 4 is an elevation view of the forming test tool shown in Figure 3; Fig. 5 is a cross-sectional view of the formation probe assembly taken along line 5-5 shown in Fig. 4;

Figures 6A-6C are cross-sectional views of a portion of the forming probe assembly taken along the same line seen in Figure 5, the probe assembly being shown in a different position in each of Figures 6A-6C; Figure 7 is an elevational view of the skirt-mounted probe block employed in the formation probe assembly shown in Figures 4 and 5; Fig. 8 is a top view of the probe block shown in Fig. 7; Figure 9 is a schematic view of a hydraulic circuit employed in the actuation of the forming test apparatus; Figure 10 is a graph of the forming fluid pressure compared to the time measured during the operation of the test apparatus; Figure 11 is another graph of the formation fluid pressure compared to the time measured during operation of the test apparatus and showing pressures measured by different pressure transducers employed in the formation tester; Figure 12 is another graph of the forming fluid pressure compared to the time measured during the operation of the tester that can be used to calibrate the pressure transducers; and Figure 13 is a graph of annular space and formation fluid pressures in response to pressure pulses.

DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

Certain terms are used throughout the following description and claims to refer to particular system components. This document is not intended to distinguish components that differ in name other than function.

In the following discussion and claims, the terms "including" and "comprising" are used widely, and thus should be construed to mean "including, but not limited to". Also, the terms "coupling", "coupling" and "coupled" used to describe any electrical connection shall each mean and refer to either a direct or indirect electrical connection. Thus, for example, if a first device is "coupled" or "coupled" to a second device, such interconnection may be by means of an electrical conductor that directly interconnects the two devices, or by means of an indirect electrical connection through other devices. devices, conductors and connections. Additionally, references to "up" or "down" are for purposes of ease of description, "up" meaning toward the borehole surface, and "down" meaning toward the base or distal end of the borehole. borehole. Moreover, in the following discussion and claims, it may sometimes be stated that certain components or elements are in fluid communication. By this it is understood that the components are constructed and interrelated in such a way that a fluid can communicate with each other, such as via a passageway, tube or conduit. Also, the designations "MWD" or "LWD" are used to mean all apparatus and measuring systems during drilling or mud recording during drilling.

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

Permeability is the ability of a rock formation to allow hydrocarbons to move between their pores and hence to a well drilling. Fluid viscosity is a measure of the ability of hydrocarbons to flow, and permeability divided by viscosity is called "mobility". Porosity is the ratio of empty space to the massive volume of rock formation containing this empty space. Saturation is the fraction or percentage of the pore volume occupied by a specific fluid (eg oil, gas, water, etc.). Wall damage is an indication of how mud filtrate or mud deposits changed permeability near well drilling. Anisotropy is the ratio of vertical and horizontal permeability of formation.

Resistivity of a fluid is the property of the fluid that resists the passage of electric current. Bubble point occurs when a fluid pressure is reduced at a rapid rate and at a low enough pressure for the fluid, or parts thereof, to change to the gas phase. The gases dissolved in the fluid are carried out of the fluid and thus gas is present in the fluid in an undissolved state. Typically, this type of phase change in the hydrocarbons of the formation being tested and measured is undesirable unless the bubble point test is being administered to determine what the bubble point pressure is.

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

Referring to Figure 1, a MWD forming test tool 10 is shown as a part of the bottom hole assembly (BHA) 6 including a sub MWD 13 and a drill bit 7 at its lower end. Bottom bore assembly 6 is lowered by a drill rig 2, such as a ship or other conventional rig, by means of drill string 5. Drill column 5 is disposed through the riser 3 and the drill head. well 4. Conventional drilling rig (not shown) is supported inside crane 1 and rotates drill string 5 and drill bit 7, causing drill 7 to form a borehole 8 through formation material 9. Borehole 8 penetrates underground zones or reservoirs, such as reservoir 11, which are believed to contain hydrocarbons in a commercially viable amount. It should be understood that the formation tester 10 may be employed in other bottom hole assemblies and with other ground-based drilling as well as offshore drilling shown in Figure 1. In all cases, in addition to the formation tester 10, the bottom hole assembly 6 contains a number of conventional apparatus and systems such as a wellbore drilling motor, rotary steerable tool, mud pulse telemetry system, sensors and measuring systems while drilling and others well known in the art.

It is also to be understood that while the MWD 10 formation tester is illustrated as part of the drill string 5, the following embodiments of the invention may be transferred down into the drillhole 8 by means of drill cable technology, as partially described above. It should also be understood that the exact physical configuration of the formation tester and probe assembly is not a requirement of the present invention. The embodiment described below is for an example only. Additional examples of a probe set and methods of use are described in US Patent Application 10 / 440,593, filed May 19, 2003 and entitled "Method and Apparatus for MWD Formation Testing", 10 / 440,835, filed May 19 2003 and entitled "MWD Formation Tester", and 10 / 440,637, filed May 19, 2003 and entitled "Equalizer Valve", each of which is incorporated herein by reference for all purposes. Additional examples of formation test tools, probe assemblies, and methods of use, whether transferred by means of a drill string or drill cable, or any other method, include the US patent application entitled "Downhole Probe Assembly", which has the US express mail stamp number EV 303483549 US and attorney folder number 1391-52601, US patent application entitled "Formation Tester Tool Assembly and Methods of Use" which has the US express mail stamp number EV 303483552 US and attorney folder number 1391-53801, US patent application entitled "Methods and Apparatus for Measuring Formation Properties" which has US express mail stamp number EV 303483566 US and attorney folder number 1391-53901, US patent application entitled "Methods and Apparatus for Controlling a Fomation Tester Tool Assembly" which has the express mail stamp number US EV 303483362 and wanted folder number 1391-54101 and pe U.S. Patent Application entitled "Methods for Measuring a Formation Supercharge Pressure" which has the serial number of patent application 11 / 069,649, each of which is incorporated herein by reference for all purposes. Training test tool 10 is better understood with reference to figures 2A-2E. The forming tester 10 generally comprises a thick walled housing 12 made of multiple piercing collar sections 12a, 12b, 12c and 12d that threadably engage each other to form the complete housing 12. The bottom assembly 6 includes flow hole 14 formed along its length to allow drilling fluids from the surface to pass through the drill string 5 and through the drill 7. The drilling fluid passes through nozzles on the face of the drill bit and flows to up through the borehole 8 along the annular space 150 formed between the housing 12 and the borehole wall 151.

Referring to Figures 2A and 2B, upper section 12a of housing 12 includes upper end 16 and lower end 17. Upper end 16 includes a threaded housing for connecting formation tester 10 to drill string 5. Lower end 17 includes a threaded housing for receiving a correspondingly threaded pin end of the housing section 12b. Disposed between the ends 16 and 17 in the housing section 12a are three aligned and connected tubular sleeves or inserts 24a, b, c which create an annular space 25 between the gloves 24a, b, c and the inner surface of the housing section 12a. The annular space 25 is sealed from the flow hole 14 and is provided to house 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 for interconnecting packets 20, 22 on a common power bus (not shown). Underneath the battery packs 20, 22 and also disposed around the sleeve insert 24c in the annular space 25 is the electronic module 30. The electronic module 30 includes the various circuit boards, capacitor banks and other electrical components, including the capacitors shown at 32. A connector 33 is provided adjacent to the upper end 16 in the housing section 12a for electrically coupling the electrical components in the forming test tool 10 to other bottom hole assembly components 6 which are above the housing 12.

Below the electronics module 30 in the housing section 12a is an insert of adapter 34. Adapter 34 is plugged into sleeve insert 24c into fitting 35 and retains a plurality of spacer rings 36 in a central hole 37 forming a portion of the adapter hole. flow 14. The lower end 17 of the housing section 12a is connected to the housing section 12b in the threaded connection 40. Spacers 38 are disposed between the lower end of the adapter 34 and the pin end of the housing section 12b. Because threaded fittings such as fitting 40 at various times have to be cut and repaired, the length of sections 12a, 12b may vary. The use of spacers 36, 38 allows adjustments to be made to the length of threaded connection 40. Housing section 12b includes an inner sleeve 44 disposed therethrough. Sleeve 44 extends into the housing section 12a above, and into the housing section 12c below. The upper end of the sleeve 44 supports spacers 36 arranged on adapter 34 in the housing section 12a. An annular area 42 is formed between the sleeve 44 and the housing wall 12b and forms a wire path for electrical conductors extending above and below the housing section 12b, including conductors that control the operation of the formation tester 10 in the manner described below.

Referring now to Figures 2B and 2C, housing section 12c includes upper housing end 47 and lower housing end 48 which threadably fit housing section 12b and housing section 12c, respectively. For the reasons previously explained, adjusting spacers 46 are provided in the housing section 12c adjacent the end 47. As previously described, the insert sleeve 44 extends into the housing section 12c where it pierces the inner mandrel 52. The lower end of inner mandrel 52 pierces the upper end of the formation tester mandrel 54, which is composed of three axially aligned and connected sections 54a, b and c. Extending through the mandrel 54 is a portion of the offset flow hole 14a. Bypassing the flow hole 14 to the path of the flow hole 14a provides sufficient space within the housing section 12c for the forming tool components described in more detail below. As best shown in Figure 2E, the diverted flow hole 14a eventually centers near the lower end 48 of the housing section 12c, generally shown at location 56. Referring momentarily to Figure 5, the cross-sectional profile of the flow hole Offset 14a may be non-circular in segment 14b to provide as much environment as possible for the probe assembly 50.

Best shown in Figures 2D and 2E arranged around the formation tester arbor 54 and within the housing section 12c are the electric motor 64, hydraulic pump 66, hydraulic manifold 62, equalizing valve 60, formation probe assembly 50 , pressure transducers 160 and lowering piston 170. Hydraulic accumulators provided as part of the hydraulic system 200 for operating the formation probe assembly 50 are also arranged around the mandrel 54 at various locations, such an accumulator 68 being shown in Figure 2D . The electric motor 64 may be a permanent magnet motor driven by battery packs 20, 22 and capacitor banks 32. The motor 64 is interconnected to the hydraulic pump 66, and drives the same. Pump 66 provides fluid pressure to actuate 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 circuits employed in the actuation and control of the formation probe assembly 50, explained in more detail below.

Referring again to FIG. 2C, mandrel 52 includes a central segment 71. Arranged around segment 71 of mandrel 52 are pressure balancing piston 70 and spring 76. Mandrel 52 includes a spring limiting extension 77 in the upper end of segment 71. Thrust ring 88 is threaded into mandrel 52 and includes a piston limiting cam 80 to engage the corresponding annular shoulder 73 formed on pressure balancing piston 70. Pressure balancing piston 70 further includes a seal annular slide or barrier 69. Barrier 69 consists of a plurality of O-ring seals and inner and outer ferrules arranged axially along the length of the piston 70.

Beneath the piston 70 and extending below the inner mandrel 52 is a lower oil chamber or reservoir 78, described in more detail below. An upper chamber 72 is formed in the annular space between the central part 71 of the mandrel 52 and the housing section wall 12c, and between the spring support part 77 and the pressure balancing piston 70. The spring 76 is retained within 72. The chamber 72 is opened through the bore 74 to the annular space 150. As such, drilling fluids will fill the chamber 72 in operation. An annular seal 67 is disposed around the spring support 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 filled and contained hydraulic oil. in the oil reservoir 78 below the piston 70. The lower chamber 78 extends from the barrier 69 to the 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 the entire space between the housing section 12c and the formation tester arbor 54. The hydraulic oil in chamber 78 can be maintained at slightly greater pressure than the hydrostatic pressure of the drilling fluid in annular space 150. Annular space pressure is applied to piston 70 by drilling fluid entering chamber 72 through orifice 74. Because the lower oil chamber 78 is a vented system, annular space pressure that is applied by means of piston 70 is applied throughout chamber 78. In addition, spring 76 provides slightly higher pressure to closed oil system 78 such that the pressure in oil chamber 78 is substantially equal to the annular space fluid pressure plus pressure added by spring force. This slightly higher oil pressure is desirable in order to maintain positive pressure on all seals in the oil chamber 78. Having these two overall pressures evenly balanced (even if the oil pressure is slightly higher) is easier to maintain than There was a large pressure difference between the hydraulic oil and the drilling fluid. Between barrier 69 on piston 70 and point 83, hydraulic oil fills the entire gap between the outside diameter of the spindles 52, 54 and the inside diameter of the housing section 12c, this region being marked as the distance 82 between points 81 and 83. Oil in reservoir 78 is employed in hydraulic circuit 200 (FIG. 9) used to operate and control formation probe assembly 50 in the manner described in more detail below. The equalizer valve 60, best shown in Figure 3, is disposed in the formation tester chuck 54b between the hydraulic manifold 62 and the formation probe assembly 50. The equalizer valve 60 is in fluid communication with the hydraulic port 85 and with the longitudinal fluid passageway 93 formed in the mandrel 54b. Prior to actuation of the formation probe assembly 50 to test the formation, the drilling fluid fills the passages 85 and 93 as the valve 60 is normally open and communicates with the annular space 150 through the port 84 in the wall. housing section 12c. When formation fluids are being sampled by formation probe assembly 50, valve 60 closes passage 85 to prevent drilling fluids from annular space 150 from entering passage 85 or passage 93.

As shown in figures 3 and 4, housing section 12c includes a recessed portion 135 adjacent the formation probe assembly 50 and equalizer valve 60. The recessed portion 135 includes a flat surface or "flat portion" 136. The holes through the which fluid can pass to equalizer valve 60 and probe assembly 50 extend through the flat portion 136. In this way, as the drill string 5 and formation tester 10 are rotated in the borehole, the probe assembly 50 and equalizer valve 60 are better protected from impact, abrasion and other forces. Flat portion 136 is recessed at least 1/4 inch (6.35 mm) and may be at least 1/2 inch (12.7 mm) from the outside diameter of housing section 12c. Similar flat portions 137, 138 are also formed around the housing section 12c generally at the same axial position as the flat portion 136 to increase the flow area for drilling fluid in the annular space 150 of the borehole.

Arranged around the section of housing 12c adjacent to the probe assembly 50 is the stabilizer 154. The stabilizer 154 may have an outside diameter close to the nominal size of the borehole. As explained below, the formation probe assembly 50 includes a sealing block 140 that is extendable to a position outside the housing 12c to fit into the borehole wall 151. As explained, the probe assembly 50 and sealing block 140 of the formation probe assembly 50 are recessed from the outside diameter of the housing section 12c, but they are otherwise exposed to the annular space environment 150 where they could be impacted by the borehole wall 151 during drilling or during insertion or retrieval of bottom bore assembly 6. Thus, being positioned adjacent to the formation probe assembly 50, stabilizer 154 provides additional protection to seal block 140 during insertion, retrieval and operation of the bottom bore assembly 6. It also provides protection for block 140 during formation tester operation 10. In operation, a piston extends the sealing location 140 to a position where it engages the borehole wall 151. The force of the block 140 against the borehole wall 151 would tend to move the formation tester 10 into the borehole, and such movement would cause the borehole. block 140 is damaged. However, as the formation tester 10 moves sideways within the borehole as the piston is extended to engage the borehole wall 151, the stabilizer 154 engages the borehole wall and provides a reactive force to counteract the force applied to the piston by the formation. In this way the further movement of the forming test tool 10 encounters resistance.

Referring to FIG. 2E, mandrel 54c contains chamber 63 for housing pressure transducers 160a, c and d, as well as electronic components for driving and reading such pressure transducers. In addition, the electronics in chamber 63 contain memory, a microprocessor, and power conversion circuitry to properly utilize power from the power bus (not shown).

Referring further to Figure 2E, housing section 12d includes pin ends 86, 87. Lower end 48 of housing section 12c threadably engages upper end 86 of housing section 12d. Below the housing section 12d, and between forming test tool 10 and drill bit 7, are other sections of the bottom hole assembly 6 that constitute conventional MWD tools, shown generally in Figure 1 as sub MWD 13. In a general sense, the housing section 12d is an adapter used to transition from the lower end of the forming test tool 10 to the remainder of the bottom bore assembly 6. The lower end 87 of the housing 12d section engages. threaded other subassemblies included in the bottom hole assembly 6 below the forming test tool 10. As shown, the flow hole 14 extends through the housing section 12d to such lower subsets and finally to the drill bit. 7

Referring again to FIG. 3 and FIG. 3A, the lowering piston 170 is retained in the lowering manifold 89 which is mounted on the chuck of the formation tester 54b within the housing 12c. Piston 170 includes annular seal 171 and is slidably received in cylinder 172. Spring 173 predisposes piston 170 to its upper or supported position shown in Figure 3A. Separate hydraulic lines (not shown) interconnect cylinder 172 above and below piston 170 at portions 172a, 172b to move piston 170 both up and down within cylinder 172 as described in more detail below. A piston 174 is integral with piston 170, and extends from it. The plunger 174 is slidably disposed on the coaxial cylinder 177 with 172. The cylinder 175 is at the top of the cylinder 177 which is in fluid communication with the longitudinal passageway 93 shown in Figure 3A. Cylinder 175 is flooded with drilling fluid through its interconnection with passage 93. Cylinder 177 is filled with hydraulic fluid under seal 166 through its interconnection with hydraulic cylinder 200. Piston 174 also contains scraper 167 which protects seal 166 from debris in the drilling fluid. Scraper 167 may be an O-ring energized ferrule seal.

Best shown in FIG. 5, the formation probe assembly 50 generally includes rod 92, a clamping sleeve 94, piston 96 adapted to alternate within the generally cylindrical clamping sleeve 94, and a bevel assembly 98 adapted for reciprocating movement. inside piston 96. Housing section 12c and formation tester arbor 54b include aligned openings 90a, 90b, respectively, which together form opening 90 to receive formation probe assembly 50. Rod 92 includes a portion of extending from base 105 is a tubular extension 107 with center passage 108. The end of extension 107 includes internal threads at 109. central passage 108 is in fluid communication with the passage of 91 which, in turn, is in fluid communication with the longitudinal fluid chamber or passageway 93, best shown in FIG. 3. which fits flange 106 to rod 92. Clamping sleeve 94 is secured within opening 90 by threaded engagement with chuck 54b in segment 110. Outer end 112 of clamping sleeve 94 extends substantially aligned with the portion 136 formed in the housing element 12c. Circumferentially spaced around the outermost surface of the clamping sleeve 94 is a plurality of tool recesses 158. These recesses are employed to thread the adapter 94 for engagement and disengagement with the chuck 54b. Clamping sleeve 94 includes cylindrical inner surface 133 having smaller diameter portions 114, 115. A seal 116 is disposed on surface 114. Piston 96 is slidably retained within clamping sleeve 94 and generally includes base section 118 and an extension portion 119 including an internal cylindrical surface 120. Piston 96 additionally includes center bore 121. The sieve 98 includes a base portion 125, a sieve extension 126 and a central passageway 127 extending through the base 125 and extension 126. The forming test apparatus 50 is mounted such that the piston base 118 can alternate along the surface 113 of the clamping sleeve 94. Similarly, the base of the groove 125 is disposed within the piston 96 and the extent of 126 is adapted for reciprocating movement along the surface of the piston 120. The central passage 127 of the 98 is aligned axially with the tubular extension 107 of the hash. te 92 and with screen 100.

Referring to FIGS. 5 and 6C, 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 opening 123 which is disposed about the extension of the rod 107. The screen 100 further includes a flange 130 adjacent the fluid inlet end 131 and an internally slotted segment 133 having slots 134. Holes 129 are formed in the screen 100 adjacent the end 122 Between the slotted segment 133 and the openings 129, the screen 100 includes threaded segment 124 to threadably engage the extension of the bore 126. The scraper 102 includes a central bore 103, threaded extension 104 and openings 101 which are in fluid communication with. central hole 103. Section 104 threadably fits integrally threaded section 109 of rod extension 107, and is disposed within central hole 132 of screen 100.

Referring now to FIGS. 5, 7 and 8, sealing block 140 may have a general threaded shape having base surface 141, an opposite sealing surface 142 for sealing a circumferential edge surface to the borehole wall. 143 and a central opening 144. In the embodiment shown, the base surface 141 is generally flat and is attached to a metal skirt 145 having circumferential edge 153 with recesses 152 and 2008 edges. The sealing block 140 seals and prevents drilling fluid enters the probe assembly 50 during formation testing to allow pressure transducers 160 to measure the pressure of the formation fluid. The rate at which the pressure measured by the formation test tool increases is an indication of the formation permeability 9. More specifically, the sealing block 40 seals in the sludge deposit 49 that forms on the borehole wall 151. Typically, the formation fluid pressure is less than the pressure of the drilling fluids that are circulated in the borehole. A layer of drilling fluid residue forms a mud deposit 49 on the borehole wall and separates the two pressure areas. Block 140, when extended, matches its shape to that of the borehole wall and, together with mud deposit 49, forms a seal through which formation fluids can be collected.

Best shown in FIGS. 3, 5 and 6, block 140 is sized so that it can be fully retracted within opening 90. In this position, block 140 is protected by both the flat portion 136 surrounding opening 90 and recess 135 which places face 136 in a rearward position relative to the outer surface of housing 12. Block 140 is preferably made of an elastomeric material, but is not limited to such a material.

As a feature for a good sealing block, the tool 10 may include, among other things, centralizers to center the formation probe assembly 50 and thereby normalize the block 140 to the drillhole wall. For example, the formation tester may include centering pistons coupled to a hydraulic fluid circuit configured to extend the pistons in such a manner as to protect the probe and block assembly, and also provide a good sealing block. The hydraulic circuit 200 used to operate the probe assembly 50, equalizing valve 60, and lowering piston 170 is illustrated in Figure 9. A microprocessor based controller 190 is electrically coupled to all controlled elements in the hydraulic circuit 200 illustrated in Figure 10. although the electrical connections to such elements are conventional and not illustrated except schematically. Controller 190 is located in electronics module 30 in housing section 12a, although it may be housed anywhere in bottom hole assembly 6. Controller 190 detects control signals transmitted from a main controller (not shown) housed in sub MWD 13 of the bottom hole assembly 6 which in turn receives instructions transmitted from the surface by mud pulse telemetry, or any of a number of other conventional mechanisms for transmitting signals to downhole tools.

When controller 190 receives a command to initiate formation test, the drill string stops rotating. As shown in Fig. 9, motor 64 is coupled to pump 66 which draws hydraulic fluid from hydraulic reservoir 78 via a repairable screen 79. As will be described, pump 66 directs hydraulic fluid to hydraulic circuit 200 which includes a probe assembly. 50, equalizing valve 60, lowering piston 170 and solenoid valves 176, 178, 180. The operation of the forming tester 10 is best understood with reference to FIG. 9 in conjunction with FIGS. 3A 5 and 6A-C. In response to an electrical control signal, controller 190 energizes solenoid valve 180, and starts motor 64. Pump 66 then begins to pressurize hydraulic circuit 200 and, more particularly, charges probe retraction accumulator 182. Charging the accumulator 182 also ensures that the probe assembly 50 is retracted, and that the lowering piston 170 is in its initial supported position described with reference to FIG. 3A. When pressure in system 200 reaches a predetermined value, such as 1,800 psi (12,402 MPa), detected by pressure transducer 160b, controller 190 (which continuously monitors system pressure) energizes solenoid valve 176 and de-energizes solenoid valve 180 , which causes the probe piston 96 and bore 98 to begin to extend toward the borehole wall 151. At the same time, check valve 194 and exhaust valve 193 seal the probe retraction accumulator 182 at a load of up to 40 ° C. approximately 500 to 1,250 psi (3,448 to 8,619 MPa). Piston 96 and squirrel 98 extend from the position shown in figure 6A to that shown in figure 6B where block 140 fits the mud sump 49 to the borehole wall 151. With continuous hydraulic pressure supply on the extension side from piston 96 and squirrel 98, squirrel then enters the sludge deposit as shown in figure 6C. There are two expanded positions of the squirrel 98, shown generally in figures 6B and 6C. Piston 96 and squirrel 98 move outwardly together until block 140 engages the borehole wall 151. This combined motion continues until the force of the borehole wall against block 140 reaches a predetermined magnitude, for example. , 5,500 lbs (2,495 kg), causing block 140 to be compressed. At this point, a second expansion stage occurs, with the squirrel 98 then moving into the cylinders 120 at the piston 96 to penetrate the sludge deposit 49 in the borehole wall 151 and receive formation fluids. Sealing block 140 is pressed against the borehole wall, pressure in circuit 200 increases, and when it reaches a predetermined pressure, valve 192 opens to close equalizing valve 60, thereby isolating fluid flow 93 of annular space. In this way, valve 192 ensures that valve 60 closes only after the sealing block 140 has been in contact with the mud deposit 49 lining the borehole wall 151. Passage 93, now closed to space annular 150, is in fluid communication with cylinder 175 at the upper end of cylinder 177 in the lowering manifold 89, best shown in Figure 3A.

With solenoid valve 176 still energized, probe seal accumulator 184 is charged until the system reaches a predetermined pressure, for example 1,800 psi (12,411 MPa), detected by pressure transducer 160b. When this pressure is reached, controller 190 energizes solenoid valve 178 to begin lowering. Powering up the solenoid valve 189 allows pressurized fluid to enter portion 172a of cylinder 172, causing lowering piston 170 to retract. When this occurs, plunger 174 moves within cylinder 177 such that the volume of fluid passage 93 increases in the volume of the plunger area 174 times the length of its stroke along cylinder 177. This movement increases the volume of the plunger. cylinder 175, thereby increasing the volume of fluid passage 93. For example, the volume of fluid passage 93 may be increased by 10 cm 3 as the piston 170 is retracted. As the lowering piston 170 is actuated, formation fluid can thus be drawn through the center passage 127 of the slug 98 and through the screen 100. The movement of the lowering piston 170 within its cylinder 172 decreases the pressure in the closed passage 93. to a pressure below the forming pressure such that the forming fluid is drawn through the screen 100 and bevel 98 to the opening 101, and then through the passage of the rod 108 to the passage 91 which is in fluid communication with. passage 93 is part of the same closed fluid system. In total, fluid chambers 93 (which include the volume of several interconnected fluid passages, including passages in probe assembly 50, passages 85, 93 (Figure 3), passages 93 interconnecting lowering piston 170 and pressure transducers 160 a, c) may have a volume of approximately 40 cm3. The drilling mud in the annular space 150 is not extracted into the groove 98 because the sealing block 140 seals in the mud sump. The squirrel 98 serves as a conduit through which the formation fluid can pass and the pressure of the formation fluid can be measured at passage 93 while the sealing block 140 serves as a seal to prevent annular fluids from entering the squirrel 98 and invalidating. the formation pressure measurement.

Referring momentarily to FIG. 6B, formation fluid is first extracted into the central bore 132 of screen 100. It then passes through slots 134 in the slotted segment of screen 133 such that particles in the fluid are filtered from the stream and are not filtered. drawn into the passage 93. The forming fluid then passes between the outer surface of the mesh 100 and the inner surface of the spindle extension 126 where it then passes through the openings 123 in the mesh 100 and into a central stem passage 108. 92 passing through the openings 101 and central through hole 103 of the scraper 102.

Referring again to FIG. 9, with sealing block 140 sealed to the borehole wall, check valve 195 maintains the desired pressure acting on piston 96 and seal 98 to maintain proper sealing of block 140. Additionally , because the probe seal accumulator 184 is fully charged, if tool 10 moves during lowering, additional hydraulic fluid volume may be supplied to piston 96 and spline 98 to ensure that sealing block 140 remains hermetically sealed. sealed to the borehole wall. In addition, if the borehole wall 151 moves in the vicinity of block 140, probe seal accumulator 184 will supply additional hydraulic fluid volume to piston 96 and sealing 98 to ensure that sealing block 140 remains tightly sealed. without the borehole 184 in circuit 200, movement of the tool 10 or borehole wall 151, and thus of the probe assembly 50, would result in a loss of sealing in block 140 and a formation test failed.

With the lowering piston 170 in its fully retracted position and the formation fluid drawn into the closed system 93, the pressure will stabilize and allow pressure transducers 160 a, c to detect and measure formation fluid pressure. The measured pressure is transmitted to controller 190 in the electronics section, where information is stored in memory and alternatively, or additionally, is communicated to the main controller in tool MWD 13 below the formation tester 10, where it can be transmitted to surface by means of mud pulse telemetry or any other conventional telemetry mechanism.

When the lowering is completed, piston 170 acts a contact switch 320 mounted on end cap 400 and piston 170 as shown in Figure 3A. The countersunk switch assembly consists of contact 300, wire 308 coupled to contact 300, plunger 302, spring 304, ground spring 306, and retaining ring 310. Piston 170 actuates key 320 causing plunger 302 to engage contact 300 which causes wire 308 to engage in system ground by contact 300 on plunger 302 in ground spring 306 on piston 170 in end cap 400 that is in communication with system ground (not shown).

When contact switch 320 is actuated, controller 190 responds by shutting down motor 64 and pump 66 to save power. Check valve 196 traps hydraulic pressure and holds piston 170 in its retracted position. In the event of any hydraulic fluid leakage that could allow piston 170 to start moving to its original supported position, the lowering accumulator 186 will provide the fluid volume necessary to compensate for such leakage and thereby maintain sufficient force to retain piston 170. in its stowed position.

During this interval, the controller 190 continuously monitors the pressure in the fluid passage 93 by means of pressure transducers 160a, and 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 closed side of equalizer valve 60 and the piston extension side of probe 96. Spring 58 then resumes equalizer valve 60 to its normally open state, and probe retraction accumulator 182 will cause piston 96 and squirrel 98 to retract such that sealing block 140 is detached from the wall of the housing. borehole. Then, controller 190 again drives motor 64 to drive pump 66 and again energizes solenoid valve 180. This step ensures that piston 96 and squirrel 98 are fully retracted and equalizer valve 60 is open. Given this arrangement, the forming tool has a redundant probe retraction mechanism. The active retracting force is provided by the pump 66. A passive retracting force is supplied by the probe retraction accumulator 182 which is capable of retracting the probe even in the event of power loss. The accumulator 182 may be surface loaded prior to being deployed at the rock bottom to provide pressure to retain the piston and the groove in housing 12c.

Referring again briefly to FIGS. 5 and 6, as piston 96 and squirrel 98 retract from their normal positions shown in FIG. 6C to those of FIG. 6B, and then FIG. 6A, screen 100 is shown. as this occurs, the flange on the outer edge of the scraper 102 drags and thus scrapes the inner surface of the screen member 100. In this manner, material sieved from the forming fluid upon its entry into the screen 100 and the screen. 98 is removed from screen 100 and deposited in annular space 150. Similarly, scraper 102 scrapes the inner surface of screen element 100 when the bore 98 and screen 100 extend toward the borehole wall.

After a predetermined pressure, for example 1,800 psi (12,411 MPa), is detected by the pressure transducer 160b and communicated to controller 190 (indicating that the equalizing valve is open and the piston and groove are fully retracted), controller 190 de-energizes solenoid valve 178 to remove pressure from side 172a of lowering piston 170. With solenoid valve 180 remaining energized, positive pressure is applied to side 172b of lowering piston 170 to ensure that piston 170 returns to its original position (shown in figure 3). Controller 190 monitors pressure via pressure transducer 160b and, when a predetermined pressure is reached, controller 190 determines that piston 170 has completely returned and shuts off motor 64 and pump 66, and de-energizes solenoid valve 180. With all solenoid valves 176, 178, 180 are returned to their original positions and with engine 64 turned off, tool 10 returns to its original condition and drilling can be started again. Relief valve 197 protects hydraulic system 200 from overpressure and pressure transients. Several additional exhaust valves may be provided. Thermal relief valve 198 protects trapped pressure sections against overpressure. Check valve 199 prevents backflow at pump 66. Formation test tool 10 can operate in two general modes: operation with pumps on and operation with pumps off. During operation with connected pumps, mud pumps 11 drilling fluid from the surface pump through the drill string 6 and back up into the annular space 150 during the test. Using this drilling fluid column, tool 10 can transmit data to the surface using mud pulse telemetry during formation testing. Tool 10 may also receive surface mud pulse telemetry commands. During a formation test, the drill pipe and formation test tool do not rotate. However, it may be the case where an intermediate movement or rotation of the drill string is required. As a safety feature, at any time during the formation test, an abort command may be transmitted from the surface to the formation test tool 10. In response to this abort command, the formation test tool will immediately interrupt the formation test and retract the probe piston to its normal retracted drilling position. The drill pipe can then move or rotate without damaging the forming test tool.

During pump off operation, a similar safety feature may also be activated. Forming test tool 10 and / or MWD tool 13 may be adapted to detect when sludge pumps are connected. Consequently, the actuation of starting the pumps and restoring flow through the tool may be detected by the pressure transducer 160d or other pressure sensors in the bottom bore assembly 6. This signal will be interpreted by a controller in the MWD 13 tool or other. control and communicated to controller 190 that it is programmed to automatically trigger an abort command on formation test tool 10. At this point, formation test tool 10 will immediately stop the formation test and retract the probe piston to its normal position. for drilling. The drill pipe can then move or rotate without damaging the forming test tool.

Uplink or downlink commands are not limited to mud pulse telemetry. By way of example, and not limitation, other telemetry systems may include manual methods, including pumping cycles, flow / pressure bands, tube rotation or combinations thereof. Other possibilities include electromagnetic (EM) methods, acoustic methods, and wire rope telemetry. An advantage of using alternative telemetry methods is that mud pulse telemetry (both up and down) requires active pumping, but other telemetry systems do not. The safety abort command can therefore be transmitted from the surface to the formation test tool using an alternate telemetry system regardless of whether the sludge pumps are on or off. The downhole receiver for downlink commands or surface data may reside within the forming test tool or within a MWD tool 13 with which it communicates. Similarly, the downhole transmitter 10 for uploading downhole commands or data may reside within the forming test tool 10 or within a MWD tool 13 with which it communicates. The receivers and transmitters may each be positioned on the MWD 13 tool and the receiver signals may be processed, analyzed and transmitted to a master controller on the MWD 13 tool before being transmitted to the local controller 190 on the formation test tool 10.

Commands or data transmitted from the surface to the formation test tool may be used other than to transmit a safety abort command. The formation test tool can have many preprogrammed modes of operation. A surface command can be used to select the desired operating mode. For example, one of a plurality of modes of operation may be selected by transmitting a header sequence indicating a change in mode of operation followed by a number of pulses corresponding to that mode of operation. Other mechanisms for selecting a mode of operation will surely be known to those skilled in the art.

In addition to the operating modes discussed, other information may be transmitted from the surface to the formation test tool 10. This information may include critical operational data such as depth or density of the surface drilling mud. The formation test tool can use this information to help refine downhole measurements or calculations or select an operating mode. Surface commands can also be used to program the formation test tool to perform a mode that is not preprogrammed.

Forming Properties Measurement Referring again to Figure 9, the forming test tool 10 may include four pressure transducers 160: two quartz crystal meters 160a, 10Od, one resistive strain gauge I60c and one resistive strain gauge differential 160b. One of the quartz crystal meters 160a is in communication with the annular space sludge and also detects formation pressures during the formation test. The other quartz crystal meter is in communication with the flow hole 14 at all times. In addition, both 160a and 160d quartz crystal meters may have temperature sensors associated with the crystals. Temperature sensors can be used to compensate for thermal effects in pressure measurement. Temperature sensors can also be used to measure fluid temperatures near pressure transducers. For example, the temperature sensor associated with the quartz crystal gauge 160a is used to measure the temperature of the fluid near the gauge in chamber 93. The third transducer is a resistive strain gauge 160c and is in communication with the slurry. annular space and also detects formation pressures during the formation test. Quartz transducers 160a, 160d provide accurate steady state pressure information, while resistive strain gauge 160c provides faster transient response. In performing sequencing during the formation test, the chamber 93 is closed and both the quarter meter 160a and the annular space resistive strain gauge 160a measure pressure inside the closed chamber 93. The resistive strain gauge transducer 160c is essentially It is used to supplement the 160a quartz meter measurements. When forming tester 10 is not in use, quartz transducers 160a, 160d can operationally measure pressure during drilling to serve as pressure during tool drilling.

Referring now to Figure 10, a pressure versus time graph generally illustrates the pressure detected by the pressure transducers 160a, 160c during operation of the formation tester 10. As formation fluid is drawn into the tester, pressure readings are taken continuously by the transducer 160a, 160c. The initially detected pressure will be equal to the annular space pressure shown in point 201. As block 140 extends and equalizer valve 60 is closed, there will be a slight increase in pressure, shown at 202. This occurs when block 140 seals. in the borehole wall 151 and compresses the drilling fluid trapped in the now isolated passageway 93. As the lowering piston 170 is actuated, the volume of the closed chamber 93 increases, causing the pressure to decrease, as shown in region 203. This is known as the lowering pretest. The combination of flow and inner diameter of the groove determines an effective operating range of tester 10. When the countersunk piston dislodges from cylinder 172, there is a differential pressure with the formation fluid causing the formation fluid to move toward to the low pressure area and thus causing the pressure to rise over time as shown in region 240. The pressure begins to stabilize, and at point 205 it reaches the formation fluid pressure in the zone being tested. After a fixed time, such as three minutes after the end of region 230, the equalizer valve 60 again opens, and the pressure inside chamber 93 equalizes back to the annular space pressure, shown at 206.

In an alternative embodiment of the typical formation test sequence, the test sequence is interrupted after block 140 extends and equalizer valve 60 is closed, and the slight increase in pressure is recorded, as shown in 202 in Figure 10. The normal test sequence is interrupted so that a response to the increase in pressure 202 can be observed. Once the test sequence was interrupted before the lowering piston 170 was actuated, no fluid flow was induced by the formation probe assembly; the formation probe assembly is maintaining a substantially no flow condition. The flowless pressure response to the rise 202 can be recorded and interpreted to determine mud deposit properties, such as mobility. If the response to increase 202 is a rapid equalization of pressure back to hydrostatic 201, then the sludge deposit has high permeability, and is probably not too thick or durable. If the response is a slow decrease in pressure, then the mud deposit is probably thicker and more waterproof.

To assist in determining the thickness of the sludge deposit, in addition to the method described above, the position indicator on the probe assembly, described in US patent application entitled "Downhole Problem Assembly", having the express mail stamp number EV 303483549 US and attorney paste number 1391-52601, can be used to measure how much the probe assembly extends after it fits into the slurry filtrate. This measurement gives an indication of the thickness of the slurry filtrate, and can be used to back up data obtained using the pressure response described above. Again, this measurement may be made in a no flow condition of the formation probe assembly as previously described.

When taking pressure measurements, it is also possible to use the different pressure transducers to verify each meter reading compared to others. Additionally, with multiple transducers, hydrostatic pressure in the borehole can be used to recheck the meters at some location, confirming that they are performing similar hydrostatic measurements. Because quartz meters are more accurate, the quartz meter response can be used to calibrate the resistive strain gauge if the response is not highly transient. Figure 11 illustrates representative formation test pressure curves. The full curve 220 represents pressure readings Psg detected and transmitted by the resistive strain gauge 160c. Similarly, the pressure Pq, indicated by the quartz meter 160a, is shown as a dashed line 222. As noted above, resistive strain gauge transducers generally do not provide the accuracy shown by quartz transducers, and quartz transducers do not provide the transient response offered by resistive strain gauge transducers. Consequently, the instantaneous formation test pressures indicated by the resistive strain gauge transducers 160c and quartz 160a are likely to be different. For example, at the beginning of a formation test, the Phydi pressure readings indicated by the quartz transducer Pq and resistive strain gauge transducer Psg are different, and the difference between these values is indicated as E0ffSi in Figure 11.

Since the reading of the quartz meter Pq is the most accurate of the two readings, the actual formation test pressures can be calculated by adding or subtracting the appropriate deviation error E0ffS from the pressures indicated by the resistive strain gauge Psg for the duration. training test. In this way, the accuracy of the quartz transducer and the transient response of the resistive strain gauge can both be used to generate a corrected test pressure, if desired it is used for real time calculation of formation characteristics or for calibration of one or more. more of the meters. As the formation test continues, it is possible that the resistive strain gauge readings will become more accurate, or the quartz meter readings will approach the actual pressures in the pressure chamber, even if the pressure is changing. In any case, it is likely that the difference between the pressures indicated by the resistive strain gauge transducer and the quartz transducer at a given time point may change with the duration of the formation test. Accordingly, it may be desirable to consider a second deviation error which is determined at the end of the test where steady state conditions have been resumed. Thus, as the Phyd2 pressures level off at the end of the formation test, it may be desirable to calculate a second E0ffS2 offset error. This second E0frS2 offset error can then be used to provide an after-fact adjustment to the formation test pressures, or resistive strain gauge calibration.

E0frsi and E0frS2 offset values can be used to adjust specific data points in the test. For example, all critical points up to Ρ ^ can be adjusted using errors E0ffSi, while all other points can be adjusted using error E0ffS2. Another solution may be to calculate a weighted average between the two deviation values and apply this single weighted average deviation to all resistive strain gauge pressure readings made during the formation test. Other methods of applying deviation error values to accurately determine the actual pressures of the formation test can be used accordingly and are well understood by those skilled in the art.

As previously generally described, quartz meters are used for accuracy because they are balanced and stable over time and maintain their calibrations in a wide variety of conditions. However, they are slow to respond to their environment. There are changes in pressure that occur during measurement that quartz meters cannot detect. On the other hand, resistive strain gauges are susceptible to alteration and calibration effects. However, they are quick to respond to changes in your environment. Thus both gauges can be used, with the quartz gauge used to get an accurate pressure reading, while the resistive strain gauge is used to show pressure differences.

In another mode for calibrating the resistive strain gauge using the quartzodine meter, a simple linear adjustment may be used. Referring to Figure 12, the pressure curve 500 is shown depicting a typical drawdown and buildup curve measured during a forming pressure test. Part 502 of curve 500 shows a stable pressure, which is typically a measure of annular space pressure because the formation test has not yet begun. Annular space pressure will typically be greater than the formation pressure because most wells are drilled in overbalanced situations where drilling fluid in the annular space is maintained at a higher pressure than formation to stabilize the well. borehole and prevent deterioration and overflow of the borehole.

The pressures measured by the quartz gauge PAI and the corrected resistive strain gauge Psgi will be the same on the part of curve 502 where the pressure is stable and close to hydrostatic, and before any dynamic response is detected by any meter. Once the formation pressure test has begun, a slight increase in pressure is illustrated by 501 before the drawdown begins, illustrated by part of curve 504. After the drawdown is completed, the formation pressure may rise back until it stabilizes, illustrated in part of curve 506. Now a second set of stabilized pressures can be taken, Pq2 and Psg2, and they probably will be different, because the dynamic response of the resistive strain gauge is much less accurate than the dynamic response. of the quartz meter.

To recalibrate the strain gauge, two unknown values are identified and a simple linear fit is applied to the known and unknown values. Unknown values can be identified as P0fr, representing the pressure shift between the two sets of stable pressure measurements, and Psiope, representing the slope of the curve between the two sets of stable pressure measurements. The known values are Pqi, Psgi, Pq2 and Psg2. The linear fit equations can be represented as: which can be expressed as: which can be expressed as: With two equations and two unknowns, the equations can be solved as follows. reach PSGCOmgida, a corrected value obtained from the resistive strain gauge. Alternatively, the resistive strain gauge can be corrected based on known values only, substituting P0fr and Psi0pe to acquire the equation: Additionally, these gauge corrections can be made "at run time" or after each test as appropriate. each sequential test is completed in well drilling. Corrections can be made at run time using real-time streaming of data to the surface using telemetry mechanisms, or alternatively using downhole processors and software placed in the tool.

Using the software built into the MWD tool (and neural network techniques) and a wellbore reference standard, such as the quartz meter, each depth point in the drillhole can be corrected with the reference. In a formation tester, there will typically be several types of gauges to measure pressure in the flow lines carrying formation fluids. For example, the formation fluid flow lines, such as lines 91, 93, may be in fluid communication with quartz meters and resistive strain meters, such as the transducers 160a, 160c of Figure 9. where formation fluids are drawn into the formation tester, fluid extraction is interrupted and fluids may accumulate to the surrounding formation pressure. After several level depressions and pressure build-ups, resistive strain gauges may show large errors in their readings. Thus, as mentioned before, these resistive strain gauge pressure transducers need to be calibrated. In one embodiment, the pressure readings at each point in the well where the pressure was measured can be used as a reference point for continuous calibration of resistive strain gauges, thus eliminating the need to calibrate and recalibrate resistive strain gauges.

Each location in the well has a distinct pressure and associated temperature as well stabilization occurs. Each time a pressure test is performed, the pressure taken by the quartz gauge can be used as a continuous calibration point for resistive strain gages. If data is collected continuously, a three-dimensional contour plot of pressure as a function of temperature can be created. The three dimensions that can be used are measured pressure, reference pressure as described, and temperature. Then, neural network techniques found in the software's built-in software can be applied to the collected data so that resistive strain gauge transducers do not require recalibration.

Pressure transducers typically have a pressure data input range in which their accuracy is defined, such as zero to 10,000 psi (60,895 MPa), or zero to 20,000 psi (137,900 MPa). Accuracy is typically measured as a percentage of full scale, so the accuracy of a 10,000 psi (60,895 MPa) meter will be higher because the percentage value of this meter is less than the same percentage value of 20,000 (137,900 MPa). . To increase the accuracy of the forming test tool, several gauges can be used to cover the possible ranges of pressures to be tested, rather than using a full range gauge. Therefore, to take the most accurate tool, multiple meters are used.

Alternatively, the range of a meter can be calibrated to a smaller range to make the most accurate meter. The meter manufacturer can configure the electronics to detect a wide range of pressures. The electronics, which are very similar between one meter and another, can be adjusted to the transducer scale to a smaller range, thus improving accuracy. Similarly, the same transducer may be used for different pressure ranges using two or more calibration tables. The effect of transducer pressure data output over the entire pressure input range can be determined for one pressure transducer, and then two or more calibration tables can be established to interpret the output information given by transducers for different ranges. pressure inlet. Therefore, accuracy can be increased without the use of multiple transducers. Accurate determination of formation pressure is vital for the proper use of measured formation pressures. However, changing fluid densities in the flow lines of the forming test tool can be problematic. The measured pressure can be corrected for the fluid density in the vertical column of the flow line. Pressure transducers may be measuring precise pressures of the formation fluids with which the transducers communicate, but these transducers are removed from the probe site that collects the formation fluids. For example, transducers 160a, 160c, 10Od are located below the probe assembly illustrated in Figure 2D-E. Thus, the pressure in the probe may differ from the pressure measured on the transducers because of this site shift.

Preferably, the vertical displacement between the transducer reference point and the probe fluid entry point is a known distance. Additionally, if the formation test tool is located in a deviated or inclined well, the orientation of the tool may be known from a navigational package. Thus, the vertical distance between the transducer and the probe inlet can be calculated for any tool inclination in the well. Finally, if the fluid present in the flow line connecting the transducer and probe inlet is known, then the pressure gradient of that fluid can be used to calculate the pressure at the probe inlet relative to the pressure in the transducer.

For example, water has a pressure gradient of 0.433 psi (2.986 MPa) per foot (30.48 cm). If it was known that water was present in the flow line and that there was a foot difference between the pressure transducer and the probe inlet, a 0.433 psi (2.986 MPa) correction could be made by reading the pressure transducer.

Thus, it is preferable that the pressure transducers be arranged as close as possible to the probe assembly.

In another embodiment of the formation test, although the formation probe assembly is fitted into the borehole, rather than dragging fluids to the probe assembly, or after dragging fluids to the probe assembly, fluids may be dragged into the probe. out of the set for training. Thus, fluid communication can be established with formation in the opposite direction of lowering, with such communication tending to pressurize formation. This can be achieved by adjusting the previously described sequence of events. Now the response to this pressurization can be recorded, and the pressure over time can be observed for a part of the formation. How the formation responds can be interpreted to obtain many of the formation properties previously described. Specifically, the pressure transient response to the change in formation pressure can be used to determine sludge permeability, estimating the formation damage of the near well drilling and calculating formation mobility. For further details on the process described above, reference may be made to the work of the Society of Petroleum Engineers No. 36,524 entitled "Supercharge Pressure Compensation Using a New Wireline Method and Newly Develops Early Time Spherical Flow Model" and US Patent 5,644,075 entitled "Wireline Formation Tester Supercharge Correction Method", each incorporated herein by reference for all purposes.

In addition, the formation may be pressurized in the manner described above except at the point where the formation material ruptures or fractures. This is called injectability testing, and can be done with fluid from the same area (at the present measurement site), or fluid, such as water, that can be obtained from another area of the formation. Fluids obtained from another area can be stored in either a pressure vessel or a lowering piston assembly, and then injected into another area containing a different fluid. Fluids can also be lifted off the surface and selectively injected into the formation.

If injection rates are high enough to materially rupture or induce formation fracture, a change in pressure can be observed and interpreted as previously described to obtain formation properties such as fracture pressure that can be used. to efficiently design fracture stimulation and completion programs. It should be noted that injectivity may be performed to test the ability of the sludge deposit to prevent fluid from entering the formation. Alternatively, the test may be done after a demotion and the mud deposit is no longer present.

Formation testers may also be used to obtain additional information beyond the properties of the producible hydrocarbon fluids. For example, formation test tool instruments can be used to determine water resistivity, which can be used in calculating formation water saturation. Knowing water saturation helps predict training productivity. Sensor packages, such as induction packages or button electrode packages, may be added adjacent to the probe assembly that is suitable for measuring the resistivity of the bound water in the formation. Such sensors would preferably be arranged on the extension portions of the probe assembly, such as the slug 98 which may penetrate the sludge deposit and formation as shown in Figure 6C. In addition, sensors may be arranged in flow lines, such as flow lines 91, 93, to measure water properties in the fluids that are extracted into the formation test set. The advantage of the probe formation test tool described herein is the flexibility of placing the probe in a specific position over the borehole to better obtain the formation pressure, or alternatively not placing the probe in an undesired location. A tool such as an acoustic imaging device can provide a real time image of the borehole so that the operator can determine where to perform a pressure test. Additionally, the image from a porosity tool can provide porosity quality information in an orientation within a well portion at a constant depth, or in a direction along the well drilling (constant azimuth). It can also provide a real-time image of fractures that intersect well drilling, providing the opportunity to prevent these fractures from getting a good matrix pressure test, or to test on those fractures to determine fracture properties. The image of these tools can be sensitive enough to determine that the pressure probe probe has actually tested at the predetermined position and to verify that the test has been performed at the chosen position. These tools can also be used to examine the condition of well drilling. This can be significant in wide or horizontal well drilling, where debris such as unremoved shavings may still be in place or may interfere with accurate measurement of forming pressure. It is common for the borehole to show abnormalities due to erosion by the drill string or circulated drilling fluids. Abnormalities may also exist because of faulty lines and different types of formations supporting each other. Thus, it is usually necessary to have a pre-existing image of the formation so that pressure measurements can be made at exact locations rather than at random locations in the formation. Acoustic, sonic, density, resistivity, gamma-ray imaging techniques and other techniques can be used to image real-time imaging. Then the forming test tool may be oriented azimultaneously to locations of higher or lower porosity, permeability, density or other forming property, depending on what should be gained from the pressure measurement or other measurement of the forming test tool. . In cases where imaging tools indicate a "hermetic" seal or zone, pressure measurements may be used to check whether or not fluid communication exists. Alternatively, imaging tools can be used to find zones that should not be pressure tested, such as highly dense or impermeable zones.

Then, the previously mentioned imaging techniques can be used to verify where the pressure measurement or other measurement was taken. The sealing block can leave an impression on the drillhole wall, so an electric imaging tool or acoustic scan tool can be used to form post-test imaging to verify the location of the block on the drillhole wall. .

Pressure measurements and other formation test tool measurements can be made with mud pumps on or off. Pressure in the annular space is greater with pumps on than pumps off, and pressure drops in the flow direction. With higher circulation pressures, there is a higher inflow rate of drilling and filtrate fluids penetrating the formation, thus forming a sludge deposit more quickly. Equivalent circulating density (ECD) is a measure of drilling fluid density taking into account suspended drilling chips, fluid compressibility and fluid flow-related frictional pressure losses. ECD will decrease over time if circulation continues, but drilling stops because, as drilling mud circulates, most drilling chips are filtered while new chips are not being added. If pressure measurements are being made by the formation tester, a difference can be observed in the formation pressure because of the change in ECD from connected pumps to disconnected pumps.

For example, the formation probe assembly may extend and a drawdown test may be performed wherein the pressure decreases as fluids are drawn into the formation tester. Then, after the lowering chamber is full, the pressure may rise back to balance with the pressure in the undisturbed formation. Now, if the pumps are started, the ECD in the annular space increases, increasing the pressure detected by the formation tester. If the pumps are turned off, the pressure will return to the original pressure before the pumps are started. This pressure difference is because of the difference in ECD and hydrostatic pressure, and can be used to indicate how much drilling fluid is penetrating into the formation, or how much communication exists between the drilling fluids and the formation. This difference can be equated for mobility or pressure transients, thus obtaining more accurate measurements. These effects are associated with pressures and overload effects, which are described in more detail in several of the previously incorporated embodiments.

With the pumps on, pressure pulses are transmitted to the downstream hole by mud pumps, communication pulses, or other devices, and the pulses can be seen to have sinusoidal behavior. During a pressure test, with the probe assembly extended, the probe can detect such pressure pulses through formation because the inside of the probe assembly is relatively isolated from well drilling fluids. Pressure pulses detected at well drilling can be compared with pressure pulses detected by the formation tester.

Referring now to Figure 13, a pressure pulse curve 600 represents pressures created by mud pumps or pulsators and detected by a pressure sensor in communication with annular space such as a PWD sensor in the MWD 13 tool, or other tool. LWD. Pressure curve 602 represents pressures detected by the formation probe assembly, which are the pressure pulses that have displaced from the annular space through the formation and into the isolated probe assembly. Pressure curves 600 and 602 have peaks 604, 606 and 608, 610, respectively. These peaks can be used to determine peak shifts or phase delay 612 and amplitude difference 614. With phase delay 612 and amplitude difference 614, mud deposit properties such as permeability, porosity and thickness can be determined. Additionally, similar formation properties can be determined.

In an alternative embodiment of the above described embodiment, the formation test tool includes more than one formation probe assembly. Instead of creating pressure pulses on the well drilling surface, the pulses can be created by one probe assembly, while the other probe assembly makes measurements. While at least two formation probe assemblies extend and engage the drillhole wall, one probe assembly may pulse fluid into the assembly and back into the formation by alternating the lowering pistons. In the meantime, the other probe assembly makes measurements as described above.

Formation tests can be done with the formation test tool once the drill bit has entered the formation. For example, formation tests can be done immediately after the formation has been drilled, such as within ten minutes of penetration. Testing at this time means there is less mud invasion and less mud deposition to combat, resulting in better pressure and / or permeability testing, better formation fluid samples (less contamination) and less drilling rig time required. to get this data. Performing tests immediately after drilling will also allow the drilling operator to look for liner points immediately. These tests may also indicate if the zone has been depleted or if hole collapse is imminent. Corrective actions can then be taken such as bore lining, mud properties change, drilling continuity or others.

Additionally, the formation can be tested on the way to the drilled hole and at the exit of the hole to observe changes in sludge deposit and formation over time. The two sets of measurements can be compared to identify changes occurring in the borehole and surrounding formation. Differences over time may indicate overload effects, more fully developed in the various references previously mentioned, and can be used to correct a formation model to account for overload pressure. Pore pressure prediction is typically obtained by measuring if the magnitude of the formation compaction. Formation compaction typically occurs in shales, so shale formations must be drilled and drilled recorded to obtain the data needed to create pore prediction models. The formation test tool described herein can measure pore pressure directly. This measurement is more accurate and can be used to calibrate pore pressure predictor models.

Use of Forming Property Data After measuring forming pressure, permeability and other forming properties, this information may be transmitted to the surface using mud pulse telemetry, or any of several other conventional mechanisms for transmitting tooling signals. descending hole. On the surface, the drilling operator can use this information to optimize drill cutting properties, drilling parameters or downhole operation. Knowing the properties of the sludge deposit allows adjustments of certain drilling parameters if the sludge deposit differs from a known or desired predetermined value; Adjustments to the sludge system itself can also be made to improve sludge properties and reduce sludge deposit thickness or filtrate invasion rate. For example, if the mud sump is found to be contaminated or impermeable, the properties of the drilling mud may be adjusted to reduce the pressure in the mud sump or to reduce the amount of contaminants entering the mud sump, or chemicals. can be added to the mud system to correct the thickness of the mud deposit.

In addition, downhole pressure measurements may indicate the need to make downhole pressure adjustments, and if again downward hole measurements differ from a known or predetermined desired value. However, instead of adjusting mud properties, other mechanical means can be used to control downhole pressure. For example, with a restrictor control or explosion protection system (BOP), the rotary BOP restrictor or restriction can be manipulated to mechanically increase or decrease surface flow resistance, thereby adjusting downhole pressure.

An exemplary drilling parameter that can be adjusted is the penetration rate of the drill bit. Using the formation tester in the ways described above, certain rock properties, also described above, can be measured. These properties can be directed to the surface in real time to optimize penetration speed during drilling. With a certain shape of probe, and knowing the shape of the front contact area of the borehole wall, certain forming properties can be measured. If a formation probe assembly, such as that illustrated in Figures 5 and 6A-C, or in the US patent application entitled "Downhole Probe Assembly", previously mentioned and incorporated by reference, is used to fit the formation, the force in The displacement function of the probe assembly can then be determined using a strain gauge or potentiometer. Force versus displacement information can be used to calculate compressive strength, compressive modulus, and other properties of the formation materials themselves. These properties of the forming material are used to determine and optimize the penetration rate of the drill bit.

Measurements made by the formation test tool can be used to optimize additional drilling applications. For example, the forming pressure may be used to determine coating requirements. Forming pressures made in the downhole can be used to determine the optimum coating size and strength required. If the formation is considered to have a high forming pressure, then the bore may be jacketed with a relatively resistant coating material to ensure that the integrity of the borehole is maintained in the high pressure formation. If the formation is considered to have low pressure, the size of the coating may be reduced and different materials may be used to reduce costs. Rock strength measurements made with the tool can also aid in the requirements of the coating. Solid rock formations require less cladding material because they are stable, whereas sediment composite formations require thicker cladding.

In inclined or horizontal wells, and particularly when the drilling fluid ceases to circulate, higher density particles in the drilling fluid sediment towards the underside of the borehole. This condition is undesirable because the effective density of the fluid is decreased. When the formation around it is at a higher pressure than the drilling fluid, hole overflow becomes more likely. To detect this condition, the formation test tool can be oriented to the underside of the borehole where measurements can now be made. In one embodiment, the probe assembly may extend and pressure measurements be made. Preferably, pressure transducers that are in communication with the annular space, such as the transducer 160c or the PWD sensor in the MWD tool, can be used to measure annular space fluid pressure without extending the probe. If it is observed that the fluid on the low side of the borehole has a higher density or weight than the equivalent drilling fluid density or weight, then the properties of the drilling fluid may be adjusted to correct this condition. Alternatively, or in addition, measurements can be made at other locations in the borehole, such as on the upper side.

Anisotropic formations have properties, any property, with different values when measured in different directions. For example, resistivity may differ in horizontal direction from vertical direction, which may be attributed to the presence of multiple beds of formation or stratification in certain rock types.

For example, forming anisotropy can be determined by making measurements of the formation, such as pressure and temperature, reorienting the tool rotationally and making additional measurements at additional angles around the borehole. Alternatively, if multiple probe sets or other measuring devices are arranged around the tool, these measurements made around the tool may be taken simultaneously. In addition to making direct measurements of the formation, the tool can make other measurements, such as sonic or electromagnetic measurements. Once all such measurements have been made, the formation anisotropy for each type of measurement can be calculated. A forming anisotropy value can be linked to or compared to acoustic, resistivity, or other measurements made by other tools. This would, for example, allow resistivity to be correlated with changes in permeability using known formation models (described in detail below).

Typically, formation pressure measurements are estimated and / or predicted by interpreting certain formation measurements other than direct measurement of formation pressure. For example, drilling pressure (PWD) and drilling mud log (LWD) measurements are obtained and analyzed to predict the actual forming pressure. Data analysis such as rock properties and stress orientation, and models such as fracture gradient models and trend-based models, can be used to predict the actual formation pressure. In addition, direct formation measurements can be used to supplement, correct or adjust these data and models to more accurately predict formation pressures. The advantage with the formation test tools described and referenced herein is that pressure and other formation data can be transmitted up the hole in real time, thus allowing models to be updated in real time.

Additionally, each measured formation property, including those previously listed and defined, can itself be used to map or image the formation. Finally, a formation model is developed and so it is known what the formation looks like on a computer screen on the drillhole surface. An example of such a formation model is the Landmark land model. Each additional measured property of the formation can be used to make complementary images, with each new property and image adding to the accuracy of the model or image of the formation. Thus, the properties obtained by the formation test tools referenced herein, particularly pressure data, can be used to create better models, or improve existing ones, to better understand the formations being penetrated. As described above, these models and data can be updated "during operation" to calibrate multiple models for better formation pressure predictions.

Similarly, formation test data, such as pressure, temperature and other previously described data obtained using a formation test tool 10 can be used to improve or correct other measurements, and vice versa. Other measurements that may benefit from pressure data and real-time pressure gradient information include: Punching Pressure (PWD), sonic or acoustic tool measurements, nuclear magnetic resonance imaging, resistivity, density, porosity, etc. These measurement or interpretive tools, such as pore pressure prediction tools or models, may be updated based on physical measurements, and are at least somewhat dependent on pressure and other forming properties. Drilling mud properties can also be adjusted in a similar manner based on real-time formation measurements. Additionally, training data may be used to assist in other services, including drilling fluid services and completion services, and operation of other tools.

During drilling, LWD tools may be measuring resistivity of forming fluids and creating resistivity records. From the resistivity record and other data, formation water saturation can be calculated. Changes in water saturation with depth can be observed and can be consolidated into a gradient. The water saturation level is related to how far the test depth is above 100% of the free water level. Water saturation and gradient levels can be used to create a capillary pressure curve. The pressure data of the forming test tool can be matched to the capillary pressure curve, which can then be projected to the bottom to estimate the free water level. The free water level can be used to determine the amount of hydrocarbons, especially gas, that are available for production. At the 100% free water level, production is not viable. Thus, the free water level can be determined without having to test below to the actual free water level.

Pressure measurements can also be used to drive the bottom hole assembly (BHA). If formation pressure measurements indicate that the current zone is not productive, or otherwise unattractive to drilling, then the BHA, including the drill bit, may be driven in another direction. An example of a drivable BHA set is the Halliburton GeoPilot system. Such directional drilling is intended to lead the BHA to higher pressure parts of the reservoir, to keep the BHA in the same pressure zone, or to avoid a lower pressure zone. Again, petrophysical data, such as previously mentioned forming properties, can also be used to more precisely direct the BHA. The previously defined bubble point can be a beneficial real-time measurement. Measuring changes in the formation fluid bubble point with the depth of the well drilling formation test tool allows the bubble point gradient to be determined. Plotting the bubble point gradient graph generally allows forward and backward transitions between gas, water and oil to be observed, or the identification of a zone that is not connected to another zone based on pressure measurements. descending hole. The bubble point gradient can be used to drive the BHA. Downward direction towards denser fluids is desirable, as lighter fluids, that is, those with higher vapor points because of retaining more dissolved gases, tend to move upwards. Therefore, as fluids with lower vapor points are found, BHA is directed towards these fluids. Bubble point gradient, as well as other gradients, can be computed during operation, as bubble point and pressure measurements are made at different depths during the same descent into the borehole. Data is transmitted to the surface in real time for gradients to be calculated and used.

As described above, the pressure during drilling in the annular space and the true forming pressure are two distinct measurements. With the ability to obtain true formation pressure, these two measurements can be combined and interpreted by flags, or alerts, and the flags can then be transmitted to the surface. Prior to the advent of FTWD, these measurements had to be combined and interpreted on the surface because the true forming pressure could be obtained only after the drilling had stopped. Therefore, the warning could be determined only after this fact. Types of signals that can be transmitted to the surface include annular space pressure that is below the forming pressure and annular space pressure that is above the fracture gradient. The discussion presented is to be illustrative of the principles and various embodiments of the present invention. Although the preferred embodiment of the invention and its method of use have been shown and described, modifications thereof may be made by those skilled in the art without departing from the spirit and precepts of the invention. The embodiments described herein are exemplary only, not limiting. Many variations and modifications of the invention and apparatus and methods disclosed herein are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited by the above description but is limited only by the following claims, that scope including all equivalents of the subject matter of the claims.

Claims (22)

Method of using a forming property, characterized in that it comprises: arranging a bottom hole assembly (6) adjacent to the distal end of a drill string, the bottom hole assembly (6) having: a drill drilling (7); and a formation test tool (10) having an extendable probe (50) and a first sensor, the extendable probe (50) includes a first extendable element in addition to the formation test tool (10) and a nickel (98). ) extendable beyond the first element; drill a borehole (8) to a first depth; extending the first element of the probe to fit into a formation; extending the probe groove (98) to fit the formation; measure a training property; and adjust a descending hole parameter if the forming property differs from a known value, Method according to claim 1, characterized in that the forming property comprises at least one of a sludge property, a property of the forming material (9) and a forming fluid pressure. Method according to claim 2, characterized in that it further comprises: recording a plurality of probe clamping force values and probe deviation values; and calculating at least one of a compressive strength and a compressive modulus. Method according to claim 1, characterized in that the downhole parameter comprises at least one of a rate at which a drilling fluid is pumped, a property of the drilling fluid, a requirement of the borehole lining. borehole (8), a drill bit penetration rate (7) and a downward bore pressure * A method according to claim 1, characterized in that the forming property comprises a forming fluid pressure, and adjusting a downhole parameter comprises mechanically manipulating a downward hole pressure on a borehole surface ( 8) if the formation fluid pressure differs from a known value. Method according to claim 1, characterized in that the drilling of a borehole (8) comprises drilling a borehole (8) inclined to a first depth, the borehole (8) having a side. high and a low side, the method further comprising: orienting the extendable probe (50) toward a predetermined location; communicating an adjacent fluid from a predetermined location to the first sensor; measure a fluid pressure; calculate a fluid density value; and wherein adjusting a downhole parameter comprises adjusting a drilling parameter if the density value differs from a known value. Method according to claim 6, characterized in that the fluid is selected from the group consisting of annular space fluid and formation fluid. Method according to claim 6, characterized in that the perforation parameter comprises a property of the perforation fluid. A method according to claim 6, characterized in that the known value comprises at least one of an equivalent drilling fluid density, an equivalent circulating density and an equivalent formation fluid density. Method according to claim 9, characterized in that the predetermined location is the low side of the borehole (8), and adjusting a drilling parameter further comprises adjusting at least one of the densities if the value of calculated density is greater than at least one density. A method according to claim 9, characterized in that the predetermined location is the high side of the borehole (8), and adjusting a drilling parameter further comprises adjusting at least one of the densities if the value of calculated density is less than at least one density, Method according to claim 1, characterized in that: the forming property comprises a bubble point value of a forming fluid; and the descending hole parameter comprises a drilling direction of the bottom hole assembly (6). A method according to claim 12, further comprising: measuring a second bubble point value at a second depth; and calculate a bubble point gradient. A method according to claim 1, further comprising: communicating the formation property to a formation description data set known during drilling of the borehole (8); and adjusting the formation description data set known in response to the formation property during drilling of the borehole (8). A method according to claim 14, characterized in that the forming property comprises a pressure of the forming fluid. Method according to claim 14, characterized in that the known data set comprises at least one of a formation model, pressure measurements during drilling, sonic measurements, acoustic measurements, resonance imaging measurements. nuclear magnetic, resistivity measurements, density measurements and porosity measurements. A method according to claim 14, further comprising: measuring a plurality of forming properties at a plurality of depths in the borehole (8); continuously communicating each of the plurality of forming properties after each property is measured; and continuously adjusting the known data set after each property is reported. The method according to claim 14, characterized in that the forming property comprises a fluid pressure and the known data set comprises a fluid resistance data set, and further comprises providing a saturation level. of water to a second depth below the first depth. Method of using a forming property, characterized in that it comprises: arranging a drill collar (12a, 12b, 12c, 12d) in a borehole (8) to a first depth, the drill collar (12a) 12b, 12e, 12d) comprising a forming test tool (10), a forming probe assembly (50) and a first sensor; measuring a first forming property at a first location at the first depth with the drill collar (12a, 12b, 12c, 12d); measuring a second forming property at a second location at the first depth with the drill collar (12a, 12b, 12c, 12d); and manipulating the first and second forming properties to obtain downhole information, A method according to claim 19, characterized in that manipulating the first and second forming properties comprises calculating a forming anisotropy. A method according to claim 20, further comprising: measuring a third forming property; and correlate the third formation property and the anisotropy of fonnation by entering the values in a formation model. The method according to claim 19, characterized in that the first forming property is an annular space fluid pressure and the second forming property is a forming fluid pressure, and manipulating the fluid pressures comprises calculating a difference value between pressures, the method further comprising: transmitting an alert if the difference value is different from a known value.