Patent Publication Number: US-11655705-B2

Title: Pressure measurement mitigation

Description:
BACKGROUND 
     The disclosure generally relates to the field of measurement, and more particularly to pressure measurement. 
     Various well operations, such as stimulation operations and drilling operations, include activities to measure formation pressure of a fluid within the formation from within a borehole. The formation pressure can be measured by establishing a sealed connection volume between a pressure sensor located in the wellbore and the formation. During measurement, the pressure sensor can measure the pressure of fluids in the sealed connection volume which are in hydraulic communication with the fluids in the formation. The pressure value measured by the sensor can be processed by a downhole tool or transmitted to a device outside of the borehole. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Aspects of the disclosure may be better understood by referencing the accompanying drawings. 
         FIG.  1    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having pads. 
         FIG.  2    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having both pads and a pad. 
         FIG.  3    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having pads. 
         FIG.  4    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having four pads and a pad. 
         FIG.  5    is an elevation view of an onshore drilling system operating a downhole drilling assembly that includes a pressure measurement system having pads. 
         FIG.  6    is an isometric view of a first pad that is concentric with a second pad. 
         FIG.  7    are two plots showing different pressure patterns during a series of buildup and drawdown cycles. 
         FIG.  8    is a flowchart of operations to measure a formation pressure. 
         FIG.  9    is a schematic diagram of an example computer device. 
     
    
    
     DESCRIPTION OF EMBODIMENTS 
     The description that follows includes example systems, methods, techniques, and program flows that embody elements of the disclosure. However, it is understood that this disclosure can be practiced without these specific details. For instance, this disclosure refers to pressure measurements acquired during or after a buildup or drawdown operation. Aspects of this disclosure can instead be applied to pressure measurements acquired during or after other operations, such as during or after a fluid injection operation, foaming operation, or drilling operation. In other cases, well-known instruction instances, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description. 
     Various embodiments can relate to a pressure measurement method and related measurement devices or systems for measuring a pressure. The pressure measurement method can provide increased accuracy when faced with physical phenomena such as supercharging, wherein a measured formation pressure is artificially altered by a well operation and the measured result may not equal to a true formation pressure. For example, supercharging can occur from active influx of fluid from the wellbore into the formation. The pressure measurement method can include acquiring a series of pressure measurements using a pressure sensor and detecting/determining a pressure measurement pattern over the series of pressure measurements to control a wellbore fluid influx guarded in order to mitigate the effects of supercharging or other artificial influences on formation pressure. By measuring pressure changes over time using a pressure sensor in hydraulic communication with a formation and a guard probe also in hydraulic communication with the formation which isolates the first guard from wellbore hydrostatic pressure, a pressure measurement system or device can overcome the influences that well operations can have on formation pressures. As used in this application, a probe can be a pad, a packer, or any portion of a tool that can form a sealed volume with the borehole wall and isolate fluid inside of the probe from fluids outside of the probe. 
     In some embodiments, the pressure measurement method can include forming a sealed connection volume between a formation and the pressure sensor in the borehole. The method can include raising the pressure measured by the pressure sensor by performing a buildup operation and then lowering the pressure measured by the pressure sensor during a drawdown operation. The pressure sensor can then acquire a pressure measurement from fluids in the sealed connection volume. The pressure of a second volume formed by the guard probe around the sealed connection of the first volume can then be lowered relative to the pressure measurement to an equilibrium drawdown as measured by a second pressure gage in communication with the second volume. The pressure sensor can then acquire a series of pressure measurements over multiple buildup/drawdown operations, during which the pressure of the volume around the sealed connection volume is lowered during or after some or all of the operations. 
     For example, the pressure sensor can acquire a second pressure measurement after the pressure of the volume around the sealed connection volume is lowered. A pressure measurement system or device can perform another buildup/drawdown operation and then reduce the pressure of the volume around the sealed connection volume a second time. The pressure sensor can acquire a third measurement after the second pressure reduction of the volume around the sealed connection volume. Based on at least a portion of the series of pressure measurements, the pressure measurement system or device can determine whether a measurement pattern shows a trend to a formation pressure value. For example, based on a first, second, and third pressure measurement, the pressure measurement system or device can determine that a measurement pattern shows a trend to a formation pressure value. 
     If the device or system determines that the measurement pattern shows a trend to a stable formation pressure measurement value, the device or system can set that formation pressure value as an actual formation pressure. Otherwise, the device or system can acquire additional pressure measurements using the pressure sensor after additional pressure reductions in the volume around the pressure sensor to determine if an updated measurement pattern shows a trend to a formation pressure value. In addition, the device or system can predict a formation property such as the amount of hydrocarbon in place, the type(s) of hydrocarbon in place, and/or a formation permeability based on the formation pressure value. By increasing the accuracy of a formation pressure measurement, the pressure measurement methods and related devices and systems disclosed herein can also increase the accuracy of volume predictions for formation fluid in a reservoir and other formation property predictions. 
     Example Wireline Systems 
       FIG.  1    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having pads. A wireline system  100  is operated at a rig  101  located at a surface  111  and positioned above a borehole  103  within a formation  102 . The wireline system  100  can include a wireline  104  supporting a formation tester tool  109  that includes an outer pad  119  and an inner pad  120 . Both the outer pad  119  and the inner pad  120  can extract and isolate a formation fluid sample from their respective radially outward ends. A surface system  110  located at the surface  111  can include a processor  112  and memory device and can communicate with components of the formation tester tool  109  such as the outer pad  119  and the inner pad  120 . 
     During the pressure measurement operation, the inner pad  120  can radially extend with respect to the axis of the formation tester tool  109  to form an inner sealed connection volume  130  with a wall of the borehole  103 . Fluids in the inner sealed connection volume  130  can be isolated from fluids flowing in the exposed borehole region  105  or from fluids in an outer sealed connection volume  129 . Similarly, the outer pad  119  can radially extend with respect to the axis of the formation tester tool  109  to form the outer sealed connection volume  129  with the wall of the borehole  103 , wherein fluids in the outer sealed connection volume  129  can be isolated from fluids flowing in the exposed borehole region  105  or from fluids in the inner sealed connection volume  130 . As it is to be understood in this disclosure, a sealed connection volume refers to a volume having a sealed connection between a borehole wall and a pad or other enclosed space of the formation tester tool  109 . The second, outer pad may extend with the first pad, or independent of the first pad being either prior to or after the first pad. 
     During a pressure measurement operation, the wireline system  100  can perform a drawdown operation and a buildup operation. The wireline tool can induce a drawdown by operation of a mechanical pump moving a volume of fluid from through a hydraulically sealed pad. Buildup occurs as the drawdown operation is stopped and the pressure at the measurement point rebounds to the sandface pressure, wherein the sandface pressure can be the pressure at the point that the pad contacts the formation. The sandface pressure may be different from the formation pressure due to effects such as supercharging. As described further below, the wireline system  100  can perform repeated drawdown/buildup operations. In some embodiments, the wireline system can determine a formation pressure based on the measured sandface pressure. 
     A pressure sensor  170  of the inner pad  120  can acquire a first pressure measurement from fluids within the inner sealed connection volume  130 . The outer pad  119  can act as a pressure control system and reduce the pressure around the inner pad  120  during a first depressurization interval to a pressure lower than at least one of the borehole pressure and the first pressure measurement by drawing fluid into the formation tester tool  109  through the outer sealed connection volume  129 , wherein the pressure in the outer sealed connection volume  129  can be measured by a pressure sensor  169 . The drawdown on the outer volume may be operated as a constant rate drawdown or a constant pressure drawdown. The wireline system  100  can acquire a second pressure measurement using the pressure sensor  170  during or after the depressurization interval. The wireline system  100  can then perform at least one additional iteration to acquire one or more pressure measurements using the pressure sensor  170 , wherein the iteration can include a buildup operation, a drawdown operation, and/or an operation to reduce the pressure around the sealed connection volume  130  during another depressurization interval. As described further below in the description corresponding with the flowchart  800  of  FIG.  8   , the system can perform repeated iterations of these operations to determine a measurement pattern for predicting one or more formation properties based on a trend of the measurement pattern and/or the pressure measurements used to generate the measurement pattern. 
     In some embodiments, pressure measurements from the formation tester tool  109  are transmitted to the surface  111  via the wireline  104 . In some embodiments, the results provided from a processor  115  in the formation tester tool  109  using the operations disclosed below for flowchart  800  of  FIG.  8    can be transmitted via the wireline  104 . Alternatively, or in addition, pressure measurements and/or the results based on the pressure measurements can be communicated via fluid pulses traveling through fluids in the borehole  103  or electromagnetic signals projected toward the surface  111 . Once at the surface  111 , the pressure measurements and/or results based on the pressure measurements can be communicated to the processor  112  in the surface system  110 . In addition, the wireline  104  can include a fluid tube through which fluid can be passed to the surface. 
       FIG.  2    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having both pads and a pad. A wireline system  200  includes a rig  201  located at a surface  211  and positioned above a borehole  203  within a subterranean formation  202 . The wireline system  200  can include a wireline  204  supporting a formation tester tool  209  that includes tool packers  231 - 232  and a pad  220 . The pad  220  can extract and isolate a formation fluid sample from its radially outward end. The tool packers  231 - 232  can radially expand from the formation tester tool  209  until they form a sealed volume  206  that is isolated from the exposed borehole region  205 . The formation tester tool  209  can also include a fluid extraction path  251  that can extract fluid from the sealed volume  206  into the formation tester tool  209  and into a fluid conduit in the wireline  204 . A surface system  210  located at the surface  211  can include a processor  212  and memory device and can communicate with components of the formation tester tool  209  such as the tool packers  231 - 232  and the pad  220 . 
     During pressure measurement operations, the pad  220  can form a sealed connection volume  230  with a wall of the borehole  203 , wherein fluids in the sealed connection volume  230  can be isolated from fluids flowing in the exposed borehole region  205  or from fluids in the sealed volume  206 . Similarly, the tool packers  231 - 232  can be activated to form the sealed volume  206 , wherein fluids in the sealed volume  206  can be isolated from fluids flowing in the exposed borehole region  205 . In addition, the sealed volume  206  can be isolated from fluids in the sealed connection volume  230  while the pad  220  forms a sealed connection volume  230  with the wall of the borehole  203 . 
     A pressure sensor  270  of the pad  220  can acquire a first pressure measurement from fluids within the sealed connection volume  230 . In some embodiments, one or both of the tool packers  231 - 232  form part of a pressure control system that can extract fluid from the sealed volume  206  via one or more fluid conduits in one or both the tool packers  231 - 232 . Alternatively, or in addition, a pressure control system can include the combination of tool packers  231 - 232  and equipment in the formation tester tool  209  that can extract fluid from the sealed volume  206  through the fluid extraction path  251 . The pressure control system can extract fluid from the sealed volume  206  to reduce the pressure around the pad  220  during a first depressurization interval to a pressure lower than at least one of the borehole pressure and the first pressure measurement. The system can acquire a second pressure measurement using the pressure sensor  270  during or after the depressurization interval. The system can then perform at least one additional iteration to acquire one or more pressure measurements using the pressure sensor  270 , wherein the iteration includes a buildup operation, a drawdown operation, and an operation to reduce the pressure around the sealed connection volume  230  during another depressurization interval. As described further below in the description corresponding with the flowchart  800  of  FIG.  8   , the system can perform repeated iterations of these operations to determine a measurement pattern for predicting one or more formation properties based on the formation pressure trend. 
     In some embodiments, the wireline  204  can transmit pressure measurements from the formation tester tool  209  to the surface  211  via the wireline  204 . In some embodiments, the results provided from a processor  215  in the formation tester tool  209  using the operations disclosed below for the flowchart  800  of  FIG.  8    can be transmitted via the wireline  204 . Alternatively, or in addition, pressure measurements and/or the results based on the pressure measurements can be communicated via fluid pulses traveling through fluids in the borehole  203  or via electromagnetic signals directed to the surface  211 . Once at the surface  211 , the pressure measurements and/or results based on the pressure measurements can be communicated to the processor  212  in the surface system  210 . In addition, the wireline  204  can include a fluid tube through which fluid extracted by the formation tester tool  209  can be passed to the surface. 
       FIG.  3    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having pads. A wireline system  300  includes a rig  301  located at a surface  311  and positioned above a borehole  303  within a subterranean formation  302 . The wireline system  300  can include a wireline  304  supporting a formation tester tool  309  that includes outer tool packers  331 - 332  and inner tool packers  333 - 334  between the outer tool packers  331 - 332 . The outer tool packers  331 - 332  and inner tool packers  333 - 334  can radially expand from the formation tester tool  309  until they form sealed volumes  306 - 308 , each of which can be isolated from the exposed borehole region  305 . As shown in  FIG.  3   , radially expanding different combinations of the inner and outer tool packers  331 - 334  can form different sections of the sealed volumes  306 - 308 . Radially expanding the inner tool packer  333  and outer tool packer  331  can form the sealed volume  306 . Radially expanding the inner tool packer  334  and outer tool packer  332  can form the sealed volume  307 . Radially expanding the inner tool packers  333 - 334  can form the sealed volume  308 . 
     The formation tester tool  309  can also include a fluid extraction path  351 , wherein the formation tester tool  309  can extract fluid from the sealed volume  306  into the formation tester tool  309  through the fluid extraction path  351 . Similarly, the formation tester tool  309  can extract fluid from the sealed volumes  307  and  308  via fluid extraction paths  352  and  353  respectively. A surface system  310  located at the surface  311  can include a processor  312  and memory device and can communicate with components of the formation tester tool  309  such as the outer tool packers  331 - 332  and the inner tool packers  333 - 334 . 
     During pressure measurement operations, each of the outer tool packers  331 - 332  and the inner tool packers  333 - 334  can radially expand to form the sealed volumes  306 - 308 . In some embodiments, one or both of the inner tool packers  333 - 334  can include equipment that can be used to acquire a formation pressure measurement. Radial expansion of the inner tool packer  333  can result in a sealed connection volume  363  between the inner tool packer  333  and a wall of the borehole  303 , wherein the sealed connection volume  363  includes a pressure sensor  373 . Fluids in the sealed connection volume  363  can be isolated from fluids in the sealed volumes  306  and  308  surrounding the sealed connection volume  363 . Similarly, radial expansion of the inner tool packer  334  can result in a sealed connection volume  364  between the inner tool packer  334  and a wall of the borehole  303 , wherein the sealed connection volume  364  includes a pressure sensor  374 . Fluids in the sealed connection volume  364  can be isolated from fluids in the sealed volumes  307  and  308  surrounding the sealed connection volume  364 . 
     The pressure sensor  373  of the inner tool packers  333  can acquire a first pressure measurement from fluids within the sealed connection volume  363 . Similarly, the pressure sensor  374  of the inner tool packers  334  can acquire a first pressure measurement from fluids within the sealed connection volume  364 . In some embodiments, one or more of the tool packers  331 - 334  can form a part of a pressure control system that can extract fluid from the sealed volumes  306 - 308 . Alternatively, or in addition, a pressure control system can include the combination of some or all of the tool packers  331 - 334  and equipment in the formation tester tool  309  that can extract fluid from the sealed volumes  306 - 308  through the fluid extraction path  351 - 353 . The formation tester tool  309  can then operate to extract fluid from the sealed volumes  306 - 308  through the fluid extraction paths  351 - 353 , respectively, to reduce the pressure around the pressure sensors  373 - 374 . The pressures around the pressure sensors  373 - 374  can be lowered to a value less than at least one of the borehole pressure and the first pressure measurement during a first depressurization interval. The wireline system  300  can acquire a second pressure measurement using at least one of the pressure sensors  373 - 374  during or after the depressurization interval. The system can then perform at least one additional iteration to acquire one or more pressure measurements using the pressure sensor  370 , wherein the iteration can include a buildup operation, a drawdown operation, and an operation to reduce the pressure around the sealed connection volume  330  during another depressurization interval. As described further below in the description corresponding with the flowchart  800  of  FIG.  8   , the system can perform repeated iterations of these operations to determine a measurement pattern for predicting one or more formation properties based on the formation pressure trend. 
     In some embodiments, the wireline  304  can transmit pressure measurements from the formation tester tool  309  to the surface  311  via the wireline  304 . In some embodiments, the results provided from a processor  315  in the formation tester tool  309  using the operations disclosed below for the flowchart  800  of  FIG.  8    can be transmitted via the wireline  304 . Alternatively, or in addition, pressure measurements and/or the results based on the pressure measurements can be communicated via fluid pulses traveling through fluids in the borehole  303  or via electromagnetic signals to the surface  311 . Once at the surface  311 , the pressure measurements and/or results based on the pressure measurements can be communicated to the processor  315  in the surface system  310 . In addition, the wireline  304  can include a fluid tube through which fluid extracted by the formation tester tool  309  can be passed to the surface. 
       FIG.  4    is an elevation view of an onshore wireline system operating a formation tester tool that includes a pressure measurement system having four pads and a pad. A wireline system  400  includes a rig  401  located at a surface  411  and positioned above a borehole  403  within a subterranean formation  402 . The wireline system  400  can include a wireline  404  supporting a formation tester tool  409  that includes outer tool packers  431 - 432 , inner tool packers  433 - 434  between the outer tool packers  431 - 432  with respect to the axis of the formation tester tool  409 , and a pad  420  between the inner tool packers  433 - 434 . The outer tool packers  431 - 432  and inner tool packers  433 - 434  can radially expand from the formation tester tool  409  until they form sealed volumes  406 - 408 , each of which can be isolated from the exposed borehole region  405 . As shown in  FIG.  4   , radially expanding different combinations of the inner and outer tool packers  431 - 434  can form different sections of the sealed volumes  406 - 408 . Radially expanding the inner tool packer  433  and outer tool packer  431  can form the sealed volume  406 . Radially expanding the inner tool packer  434  and outer tool packer  432  can form the sealed volume  407 . Radially expanding the inner tool packers  433 - 434  can form the sealed volume  408 , wherein the pad  420  is within the sealed volume  408 . 
     The formation tester tool  409  can also include a fluid extraction path  451 , wherein the formation tester tool  409  can extract fluid from the sealed volume  406  into the formation tester tool  409  through the fluid extraction path  451 . Similarly, the formation tester tool  409  can extract fluid from the sealed volumes  407  and  408  via fluid extraction paths  452  and  453  respectively. A surface system  410  located at the surface  411  can include a processor  412  and memory device and can communicate with components of the formation tester tool  409  such as the outer tool packers  431 - 432  and the inner tool packers  433 - 434 . 
     During pressure measurement operations, the pad  420  can radially extend with respect to the axis of the formation tester tool  409  to form a sealed connection volume  430  with a wall of the borehole  403 . Fluids in the sealed connection volume  430  can be isolated from fluids flowing in the exposed borehole region  405  or from fluids in the sealed volume  408  that surrounds the pad  420 . In addition, each of the outer tool packers  431 - 432  and the inner tool packers  433 - 434  can radially expand to form the sealed volumes  406 - 408 . For example, the tool packers  433 - 434  can be activated to form the sealed volume  408 , wherein fluids in the sealed volume  408  can be isolated from fluids flowing in the exposed borehole region  405  or from the sealed volumes  406 - 407 . In addition, the sealed volume  408  can be isolated from fluids in the sealed connection volume  430  formed by the pad  420 . In some embodiments, each of the sealed volumes  406 - 408  can be formed to increase the isolation with respect to any materials in the sealed connection volume  430 . 
     A pressure sensor  470  of the pad  420  can acquire a first pressure measurement from fluids within the sealed connection volume  430 . In some embodiments, one or more of the tool packers  431 - 434  can form a part of a pressure control system that can extract fluid from the sealed volumes  406 - 408 . Alternatively, or in addition, a pressure control system can include the combination of some or all of the tool packers  431 - 434  and equipment in the formation tester tool  409  that can extract fluid from the sealed volumes  406 - 408  through the fluid extraction path  451 - 453 . The formation tester tool  409  can then operate to extract fluid from the sealed volumes  406 - 408  through the fluid extraction paths  451 - 453 . Extracting fluid from the sealed volume  408  can reduce the pressure around the pad  420  during a first depressurization interval to a pressure lower than at least one of the borehole pressure and the first pressure measurement. Extracting fluid from the sealed volumes  406 - 407  can increase the pressure reduction effect. The system can acquire a second pressure measurement using the pressure sensor  470  during or after the depressurization interval. The system can then perform at least one additional iteration to acquire one or more pressure measurements using the pressure sensor  470 , wherein the iteration includes a drawdown operation, a buildup operation and an operation to reduce the pressure around the sealed connection volume  430  during another depressurization interval. As described further below in the description corresponding with the flowchart  800  of  FIG.  8   , the system can perform repeated iterations of these operations to determine a measurement pattern for predicting one or more formation properties based on the formation pressure trend. 
     In some embodiments, the wireline  404  can transmit pressure measurements from the formation tester tool  409  to the surface  411  via the wireline  404 . In some embodiments, the results provided from a processor  415  in the formation tester tool  409  using the operations disclosed below for the flowchart  800  of  FIG.  8    can be transmitted via the wireline  404 . Alternatively, or in addition, pressure measurements and/or the results based on the pressure measurements can be communicated via fluid pulses traveling through fluids in the borehole  403  or via electromagnetic signals to the surface  411 . Once at the surface  411 , the pressure measurements and/or results based on the pressure measurements can be communicated to the processor  415  in the surface system  410 . 
     Example Drilling System 
       FIG.  5    is an elevation view of an onshore drilling system operating a downhole drilling assembly that includes a pressure measurement system having pads. A drilling system  500  includes a rig  501  located at a formation surface  511  and positioned above a borehole  503  within a subsurface formation  502 . In some embodiments, a drilling assembly  504  can be coupled to the rig  501  using a drill string  505 . The drilling assembly  504  can include a bottom hole assembly (BHA). The BHA can include a drill bit  557 , a steering assembly  508 , and a logging-while-drilling (LWD)/measurement-while-drilling (MWD) apparatus having a formation tester tool  509 . The formation tester tool  509  can include an inner pad  520  and an outer pad  519 , either which can be used to isolate a fluid to acquire pressure measurements. The formation tester tool  509  or another component of the BHA can also include a first processor  515  to perform operations and generate results based on the measurements made by the formation tester tool  509 . 
     During drilling operations, a mud pump  532  may pump drilling fluid into the drill string  505  and down to the drill bit  557 . The drilling fluid can flow out from the drill bit  557  and be returned to the formation surface  511  through an annular area  540  between the drill string  505  and the sides of the borehole  503 . In some embodiments, the drilling fluid can be used to cool the drill bit  557 , as well as to provide lubrication for the drill bit  557  during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation  502  cuttings created by operating the drill bit  557 . Measurements or generated results can be transmitted to the formation surface  511  using mud pulses (or other physical fluid pulses) traveling through the drilling mud (or other fluid) in the borehole  503 . These mud pulses can be received at the formation surface  511  and communicated to a second processor  512  in the control and surface system  510  located at the formation surface  511 . 
     During pressure measurement operations, the inner pad  520  can form an inner sealed connection volume  530  with a wall of the borehole  503 , wherein fluids in the inner sealed connection volume  530  can be isolated from fluids flowing in the annular area  540  or from fluids in the outer sealed connection volume  529 . Similarly, the outer pad  519  can form an outer sealed connection volume  529  with the wall of the borehole  503 , wherein fluids in the outer sealed connection volume  529  can be isolated from fluids flowing in the annular area  540  or from fluids in the inner sealed connection volume  530 . As it is to be understood in this disclosure, a sealed connection volume refers to a volume having a sealed connection between a borehole wall and a pad or other enclosed space of the formation tester tool  509 . 
     A pressure sensor  570  of the inner pad  520  can acquire a first pressure measurement from fluids within the inner sealed connection volume  530 . The outer pad  519  can then reduce the pressure around the inner pad  520  during a first depressurization interval to a pressure lower than at least one of the borehole pressure and the first pressure measurement by drawing fluid into the formation tester tool  209  through the outer sealed connection volume  529 , wherein the pressure in the outer sealed connection volume  529  can be measured by a pressure sensor  569 . The drilling system  500  can acquire a second pressure measurement using the pressure sensor  570  during or after the depressurization interval. The drilling system  500  can then perform at least one additional iteration of acquiring one or more the pressure measurements using the pressure sensor  570  while performing a drawdown through the inner sealed connection volume  530  and reducing the pressure around the inner pad  520  using the outer pad  519  during another depressurization interval. As described further below in the description corresponding with  FIG.  8   , the system can perform at least one additional iteration to acquire one or more pressure measurements using the pressure sensor  570 , wherein the iteration includes a buildup operation, a drawdown operation, and an operation to reduce the pressure around the sealed connection volume  530  during another depressurization interval. As described further below in the description corresponding with  FIG.  8   , the system can perform repeated iterations of these operations to determine a measurement pattern for predicting one or more formation properties based on the formation pressure trend. 
     Example Pad 
       FIG.  6    is an isometric view of a first pad that is concentric with a second pad.  FIG.  6    shows a portion of a formation tester tool  609  comprising a pad device  601 . The pad device  601  includes an outer pad comprising an outer pad wall  612  surrounding an outer pad volume  614 , wherein a pressure sensor  634  is within the outer pad volume  614 . The pad device  601  also includes an inner pad comprising an inner pad wall  616  surrounding an inner pad volume  618  surrounded by the inner pad wall  616  and a pressure sensor  638  within the inner pad volume  618 . The pressure sensor  634  can measure the pressure of the outer pad volume  614  and the pressure sensor  638  can measure the pressure of the inner pad volume  618 . With further reference to  FIG.  1   , the pressure sensor  169  can be similar to or the same as the pressure sensor  634  and the pressure sensor  170  can be similar to or the same as the pressure sensor  170 . With further respect to  FIG.  1   , the outer pad of  FIG.  6    can be similar to or the same as the outer pad  119  and the inner pad of  FIG.  6    can be similar to or the same as the inner pad  120 . 
     During a pressure measurement operation, the pad device  601  can be extended such that ends of the outer pad wall  612  and the inner pad wall  616  sealingly engage with a borehole wall. Such sealing engagement can convert the outer pad volume  614  into an outer sealed connection volume and the inner pad volume  618  into an inner sealed connection volume. In some embodiments, formation fluid can flow into the inner pad volume  618  and the pressure of this formation fluid can be measured by the pressure sensor  638 . Similarly, formation fluid can flow into the inner pad volume  618  and the pressure of this formation fluid can be measured by the pressure sensor  638 . The formation tester tool  609  can extract fluid through the outer pad volume  614  until the pressure of the outer pad volume  614 , as measured by the pressure sensor  634 , is less than the pressure of the inner pad volume  618 , as measured by the pressure sensor  638 . 
     Example Data 
       FIG.  7    are two plots showing different pressure patterns during a series of buildup and drawdown cycles. The first plot  700  depicts a first set of pressure measurements over time during repeated drawdown iterations while the outer pressure is reduced. The vertical axis  701  represents pressure measurements, which can be units such as pounds per square inch (psi) or kilopascals (kPa). The horizontal axis  702  represents time, which can be measured in units such as seconds, minutes, hours, or days. The trendline  703  represents pressure measurements over time. 
     In some embodiments, buildup can naturally occur after depressurization, wherein fluid flow from the formation to the surface is stopped. During buildup, formation fluid can flow to fill the depressurized region around the wellbore at the point of contact with a probe. This phenomenon can cause a pressure rebound that can be measured by a pressure sensor, wherein the pressure can asymptotically approach the formation pressure over time. As the pressure stabilizes over time, the late time pressure measurement can be indicative of a sandface pressure or even a formation pressure. 
     In some embodiments, the time corresponding with a “late time” can be determined as the time during and after the period when the pressure measurement or other measurement correlated with pressure is determined to be stable. As used in this disclosure, a pressure can be determined to be stable based on various methods. In some embodiments, an operation can determine that a measurement is stable based on statistical methods. For example, an operation can determine that a pressure is stable based on whether a portion of a measured pressure with respect to time can be fitted to a measurement pattern such as a linear segment, wherein a determination that the slope of the linear segment satisfies its corresponding slope threshold is indicative of stability. As another example, an operation can determine that a pressure is stable based on whether the standard deviation of a portion of a measured pressure with respect to time satisfying its corresponding slope threshold is indicative of stability. 
     In some embodiments, an operation can determine that a measurement is stable based on analytical methods. For example, an operation can determine that a pressure measurement is stable based on an implementation of Darcy&#39;s flow equations to determine whether the rebound of a fluid pressure can be described as asymptotic. Alternatively, or in addition, operation can determine that a pressure measurement is stable based on approximate flow equations to determine whether the rebound of a fluid pressure can be described as asymptotic. 
     Each of the points  711 - 715  represent different pressure measurements acquired by a pressure sensor over an increasing time period. Point A  711  represents a pressure measurement after an initial buildup/drawdown after a pressure buildup, wherein a buildup operation comprises preventing formation fluid from escaping the formation. Point B  712  represents a pressure measurement during a second buildup. Point C  713  represents a pressure measurement after a second drawdown after the second buildup while a pressure surrounding the pressure sensor is reduced. Point D  714  represents a pressure measurement during a third buildup. Point E  715  represents a pressure measurement after a third drawdown after the third buildup while a pressure surrounding the pressure sensor is reduced. Point F  716  represents a pressure measurement during a fourth buildup. In some embodiments, each of points B  712 , D  714  and F  716  can be considered to be build-up pressures corresponding with a late time based on one or more of the analytical or statistical operations described above. 
     A system having a processor can analyze some or all of the points  711 - 716  to determine a measurement pattern, wherein a measurement pattern can be any function fitted to at least a subset of the analyzed points. For example, a measurement pattern can be represented as a horizontal line that indicates that a pressure measurement value is constant. Alternatively, the measurement pattern can be represented as an asymptotic curve and the measurement pattern can be analyzed to predict an asymptotic value representing a formation pressure value. In addition, the system can include other points along the trendline  703  in its analysis. 
     Based on a pattern of the plurality of the points  711 - 716 , the system can determine a formation pressure value. For example, the system can determine that the pressure difference between Point A and Point C is equal greater than a pressure similarity threshold, and that the value is still declining, whereas the pressure difference between Point C  713  and Point E  715  satisfy a pressure similarity threshold. In some embodiments, the pressure similarity threshold can be equal to a pre-set value, such as a value ranging between 0 psi to 100 psi. Alternatively, or in addition, the system can determine a formation pressure value based on an asymptotic value of the measurements. For example, the system can analyze the points corresponding with the buildup pressure (e.g. Point B  712 , Point D  714 , and point F  716 ) and determine that the buildup trend has reached an asymptotic value of 5000 psi based on each of the three points being within a threshold distance of an average value of the set of three points, and that this asymptotic value is the formation pressure. 
     The second plot  750  depicts a first set of pressure measurements over time during a repeated buildup/drawdown iterations when the formation pressure is artificially influenced. For example, the formation pressure can be artificially influenced during supercharging, wherein the formation pressure is affected by active invasion from a borehole pressure. The vertical axis  751  represents pressure measurements, which can be units such as psi or kPa. The horizontal axis  752  represents time, which can be measured in units such as seconds, minutes, hours, or days. The trendline  753  represents pressure measurements over time. 
     Each of the points  771 - 775  represent different pressure measurements acquired by a pressure sensor over time. Point M  771  represents a pressure measurement after an initial drawdown after a pressure buildup. Point N  772  represents a pressure measurement during a second buildup. Point P  773  represents a pressure measurement after a second drawdown after the second buildup. Point Q  774  represents a pressure measurement during a third buildup. Point R  775  represents a pressure measurement after a third drawdown after the third buildup. Point S  776  represents a pressure measurement during a fourth buildup. As shown in the second plot  750 , the pressure measurements corresponding with each drawdown valley (e.g. Point M  771 , Point P  773  and Point R  775 ) are lower than the last, and can approach an asymptotic value over time that can be based on a borehole pressure and can be greater than an actual formation pressure. 
     In some embodiments, point N  772 , point Q  774  and/or point S  776  can be considered to be build-up pressures corresponding with a late time based on one or more of the analytical or statistical operations described above. Alternatively, an operation can determine that these points do not correspond with a late time. For example, as further described below in the description for the flowchart  800 , an operation can determine that a pressure trend during buildup deviates from an expected Darcy profile, and/or that the deviation corresponds with a phenomenon such as supercharging. In response to the trend deviation, the operation can include reducing an outer volume pressure until a Darcy profile is achieved on the center volume. 
     A system having a processor can analyze some or all of the points  771 - 776  to determine a measurement pattern, wherein a measurement pattern can be any predicted trend or function fitted to at least a subset of the analyzed points. For example, a measurement pattern can be represented as a horizontal line that indicates that a pressure measurement value is constant. Alternatively, the measurement pattern can be represented as an asymptotic curve and the measurement pattern can be analyzed to predict an asymptotic value representing an actual pressure. In addition, the system can include other points along the trendline  753  in its analysis. Based on a pattern of the plurality of the points  771 - 776 , the system can determine a pressure measurement value based on the buildup pressure measurements as the formation pressure. However, as discussed above, a pressure measurement value can be greater than the corresponding actual formation pressure when the formation pressure is artificially influenced. 
     Example Flowchart 
     The flowcharts described below are provided to aid in understanding the illustrations and should not to be used to limit the scope of the claims. Each flowchart depicts example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations shown may be performed in parallel; and the operations shown may be performed in a different order. For example, the operations depicted in blocks  804 - 832  of  FIG.  8    can be performed in parallel or serially for multiple pressure measurement systems. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general purpose computer, special purpose computer, or other programmable machine or apparatus, for execution. 
       FIG.  8    is a flowchart of operations to measure a formation pressure.  FIG.  8    depicts a flowchart  800  of operations to generate one or more formation property predictions using a device or system that includes a processor. For example, operations of the flowchart  800  can be performed using a system similar to the surface systems  110 ,  210 ,  310 ,  410 ,  510  and/or computer device  900  shown in  FIG.  1   ,  FIG.  2   ,  FIG.  3   ,  FIG.  4   ,  FIG.  5    and  FIG.  9   , respectively. Operations of the flowchart  800  start at block  804 . 
     At block  804 , the device or system lowers a pressure measurement tool with a pressure sensor into a borehole. The pressure measurement tool can include a pressure measurement sensor. For example, with reference to  FIG.  1    and  FIG.  5   , the pressure measurement tool can include the formation tester tool  109  or the formation tester tool  509 . The pressure sensor can be any device capable of measuring formation pressure at a borehole wall, such as a pressure sensor within an extended pad or a pressure sensor attached to a sealing pad. In some embodiments, the pressure control system can include a pad surrounding the pressure sensor. For example, the pressure sensor can be inside a first pad and the pressure control system can be a second extended pad that is concentric with the first pad and has a greater radius than the first pad. Alternatively, or in addition, the pressure control system can include a set of pads surrounding the pressure sensor. 
     At block  806 , the device or system can operate to form a sealed connection volume between the pressure sensor and a formation. In some embodiments, the device or system can control a pad and instruct the pad to extend and sealingly engage with a borehole wall of a formation until a hydraulic connection is formed with the formation. For example, with reference to  FIG.  1   , the inner pad  120  and outer pad  119  can extend to engage with the wall of the borehole  103  until fluid can flow from the formation  102  into the sealed connection volume  130  and not escape into the exposed borehole region  105 . Alternatively, or in addition, the device or system can control a pad containing the pressure sensor to extend and sealingly engage with the borehole wall of a formation. For example, with reference to  FIG.  3   , the inner tool packer can be commanded to extend and form a sealing engagement with the borehole wall of a formation. 
     At block  808 , the device or system can perform a buildup operation and/or drawdown operation with the pressure measurement tool. In some embodiments, the device or system can perform a buildup operation by stopping fluid flow through the formation tester tool, allowing a pressure to increase. For example, with reference to  FIG.  1   , the device or system can perform the buildup operation by stopping fluid flow from the formation  102 . In some embodiments, the device or system can perform a drawdown operation after the buildup operation. In some embodiments, the device or system can perform the drawdown operation by allowing fluid to flow through the formation tester tool. For example, with reference to  FIG.  1   , the device or system can perform a drawdown by allowing fluid to flow through the inner pad  120 . In addition, the device or system can allow fluid to flow around the formation tester tool. Alternatively, or in addition, the device or system can pressurize the entire borehole by injecting additional fluid into the borehole. For example, with reference to  FIG.  1   , the device or system can increase the pressure of the entire borehole  103 . The pressure sensor can acquire one or more pressure measurements during any or all of the operations described for block  808 . As described below for block  812 , the device or system can acquire one or more first measurements while the system performs a buildup and/or drawdown operation. Alternatively, or in addition, the pressure sensor can acquire the one or more first measurements after the system has completed performing the buildup and/or drawdown operation. 
     At block  812 , the device or system can acquire one or more first pressure measurements in a sealed connection volume using the pressure sensor. In some embodiments, the device or system can acquire the first pressure measurement of the fluid in the sealed connection volume within an extended pad. Alternatively, the device or system can acquire the first pressure measurement of a sealed connection volume within a tool packer. As used herein, it should be understood that a first pressure measurement is not required to be the initial pressure measurement taken during a series of measurements but is labeled as the first pressure measurement only with respect to the order of measurements with respect to the second pressure measurement described below. For example, the pressure sensor can have acquired an initial  5000  pressure measurements before acquiring the first pressure measurement described for block  812 . 
     At block  816 , the device or system can lower an outer pressure surrounding the sealed connection volume. In some embodiments, the sealed connection volume can be an inner sealed volume that is surrounded by an outer sealed volume, and the device or system can lower the outer pressure by lowering the fluid pressure in the outer sealed volume. For example, with reference to  FIG.  1   , the device or system can lower the fluid pressure in the outer sealed connection volume  129  that surrounds the inner sealed connection volume  130 . In some embodiments, the device or system can lower the outer pressure to be less than or equal to 50% of at least one of the borehole pressure and/or one of the first pressure measurements to increase the probability that the system detects a measurement pattern, as further described for block  828 . For example, the device or system can lower the outer pressure to be less than or equal to 50% of a maximum of the first pressure measurements. Alternatively, or in addition, the device or system can lower the outer pressure to be a value greater than 50% and less than 100% of the first pressure measurement. For example, the device or system can lower the outer pressure to be 75% of the first pressure measurement. As another example, the device or system can lower the outer pressure to be 50% or 75% of the borehole pressure. As further described below, the device or system can acquire one or more second measurements during the operations of block  816 . 
     At block  820 , the device or system can acquire one or more second pressure measurements with the pressure sensor. In some embodiments, the device or system can acquire the one or more second pressure measurements of the fluid in the sealed connection volume within an extended pad. Alternatively, the device or system can acquire the second pressure measurement(s) of a sealed connection volume within a tool packer. As used herein, it should be understood that a second pressure measurement is not required to be the pressure measurement acquired immediately after acquisition of the first pressure measurement, but is labeled as the second pressure measurement only with respect to the order of measurements with respect to the first pressure measurement(s) described below. For example, the pressure sensor can have acquired a subsequent  50  pressure measurements after acquiring the first pressure measurement and before acquiring the second pressure measurement. 
     At block  822 , the device or system can perform an additional buildup operation and/or drawdown operation. The system can perform the additional buildup and/or drawdown operation using the same parameters as the buildup/drawdown operation for block  808 . Alternatively, the device or system can perform the additional buildup and/or drawdown operation using different parameters from one or more previous iterations of buildup/drawdown operations. For example, the device or system can increase a buildup time decrease a buildup time, increase a drawdown time, or decrease a drawdown time relative to a previous buildup and/or drawdown operation. 
     At block  824 , the device or system can lower the outer pressure surrounding the sealed connection volume during or after the buildup/drawdown operation. The system can lower the outer pressure to the same lowered pressure value used at block  816 . Alternatively, the device or system can lower the outer pressure to a different pressure value based on an updated borehole pressure and/or an updated pressure measurement. For example, the device or system can lower the outer pressure to 300 psi for operations corresponding with block  816  and lower the outer pressure to 250 psi for operations corresponding with block  826  based on a previous pressure measurement being less than a first pressure measurement. 
     At block  826 , the device or system can acquire one or more additional pressure measurements with the pressure sensor. In some embodiments, the device or system can acquire additional pressure measurements during and/or after the operations described for block  824 . For example, the device or system can begin to acquire one or more additional pressure measurements during a buildup operation and continue to acquire the additional pressure measurements after a subsequent drawdown operation. In some embodiments, a subset of the set of measurements including the one or more first pressure measurements, the one or more second pressure measurements and the one or more additional pressure measurements can be described as a series of pressure measurements. 
     At block  828 , the system determines whether a measurement pattern that is based on the pressure measurements shows a trend to a formation pressure value. In some embodiments, the device or system can determine a measurement pattern based a fitted curve, wherein the fitted curve is fitted to a series of pressure measurements that includes some or all of the first measurement(s), second measurement(s), and/or additional measurement(s) described above. In some embodiments, the fitted curve of the plurality of pressure measurements can be described by functions such as Equations 1 and 2 below, wherein P is a pressure value, b is a constant value, e is Euler&#39;s number, and t is time:
 
 P=b   (1)
 
 P=be   −t   (2)
 
     For example, the fitted curve can be fitted to the three or five most recent pressure measurements taken during or a buildup operation. In response to determining that the confidence value corresponding to the fitted curve satisfies a confidence threshold, the device or system can determine that a measurement pattern has been detected. The system can then determine that the measurement pattern shows a trend to a formation pressure value by analyzing the measurement pattern to determine a constant value or asymptotic value to represent the formation pressure value. Alternatively, or as an additional threshold, the device or system can use other statistical or data-based thresholds to detect a measurement pattern, such as a statistical deviation, variance, etc. For example, the device or system can determine whether a standard deviation corresponding with the fitted curve satisfies a statistical deviation threshold and, in response to determining that both a confidence interval and a standard deviation threshold are satisfied, determine that a measurement pattern has been detected. As described further below for block  832 , the device or system can then select a statistical average such as a mean pressure measurement value or median pressure measurement value to represent the formation pressure value. 
     Alternatively, or in addition, the system can determine whether a set of pressure measurements trend to a formation pressure based on an implementation of Darcy&#39;s equations and/or approximate flow equations. For example, the system can determine that a set of measurements do not trend to a formation pressure based on a determination that the set of measurements do not show an expected Darcy profile. In some embodiments, the system can determine that a deviation from the expected Darcy profile corresponds specifically to a supercharging phenomenon. 
     In some embodiments, the values used to determine whether a measurement pattern shows a trend to a formation pressure can be different from the values of the measurement pattern used to determine the formation pressure. For example, the device or system can use a first set of pressure measurements fitted by a function to determine that a measurement pattern has been detected, wherein the first set of pressure measurements are each acquired after a drawdown operation and before a buildup operation. The system can then use a second set of pressure measurements to determine an actual formation pressure, wherein the second set of pressure measurements are each acquired during a buildup operation. 
     As described above, the lower the ratio between the outer pressure surrounding the sealed connection volume and the pressure inside the sealed connection volume, the faster the rate at which the pressure measurements converge to a steady state formation pressure value. Thus, the lower the ratio between the lowered outer pressure and the inner pressure of the sealed connection volume, the greater the probability that the device or system can detect whether a measurement pattern shows a trend to a formation pressure value for any particular iteration of the operations described for block  822 , block  824 , block  826  and block  828 . If the system determines a pressure trend is detected, the device or system can proceed to block  832 . Otherwise, the device or system can return to block  808 . 
     At block  832 , the device or system can generate one or more formation property predictions based on the measurement pattern. In some embodiments, the formation property prediction can be the formation pressure value itself. For example, after determining that the measurement pattern is sufficiently similar to an average pressure value based on a previous three pressure measurements at the end of the most recent three buildups each being within a threshold range of the average pressure value, the device or system can set the formation pressure value to be equal to the average pressure value. In some embodiments, the device or system can have a pre-established rule that establishes the formation pressure as an average of pressure measurements. For example, the device or system can establish that the formation pressure is equal to the average pressure measurement value P avg  of a first pressure measurement and a last pressure measurement, as shown below in Equation 3, wherein P1 is a first pressure measurement and P2 is a second pressure measurement: 
     
       
         
           
             
               
                 
                   
                     
                       
                         P 
                         ⁢ 
                         1 
                       
                       + 
                       
                         P 
                         ⁢ 
                         2 
                       
                     
                     2 
                   
                   = 
                   
                     P 
                     avg 
                   
                 
               
               
                 
                   ( 
                   3 
                   ) 
                 
               
             
           
         
       
     
     While the above discloses establishing an actual formation pressure as a mean average of two pressure measurements, the device or system can establish an actual formation pressure based on a mean, median, or other statistical function of two or more pressure measurements. Alternatively, or in addition, the formation property prediction can be for a correlated formation property such as mud weight, permeability, hydrocarbon in place, etc. For example, the device or system can first predict a formation pressure based on an asymptotic trend of a measurement pattern and then use the formation pressure prediction to generate a prediction of a mud weight. Once the system has generated one or more formation property predictions, operations of the flowchart  800  can be considered complete. 
     Example Computer 
       FIG.  9    is a schematic diagram of an example computer device. A computer device  900  includes a processor  901  (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer device  900  includes a memory  907 . The memory  907  may comprise system memory. Example system memory can include one or more of cache, static random access memory (RAM), dynamic RAM, zero capacitor RAM, Twin Transistor RAM, enhanced dynamic RAM, extended data output RAM, double data rate RAM, electrically erasable programmable read-only memory, nano RAM, resistive RAM, “silicon-oxide-nitride-oxide-silicon memory, parameter RAM, etc., and/or any one or more of the above already described possible realizations of machine-readable media. The computer device  900  also includes a bus  903 . The bus  903  can include buses such as Peripheral Component Interconnect (PCI), Industry Standard Architecture (ISA), PCI-Express, HyperTransport® bus, InfiniBand® bus, NuBus, etc. The computer device  900  can also include a network interface  905  (e.g., a Fiber Channel interface, an Ethernet interface, an internet small computer system interface, synchronous optical networking interface, wireless interface, etc.). 
     The computer device  900  can include a measurement operations controller  911 . The measurement operations controller  911  can perform one or more operations to control a pressure sensor and/or equipment attached to a pressure sensor as described above. For example, the measurement operations controller  911  can generate instructions to radially extend a pad. Additionally, the measurement operations controller  911  can acquire one or more pressure measurements. With respect to  FIG.  1   ,  FIG.  2   ,  FIG.  3   , and  FIG.  4   , the measurement operations controller  911  may be similar to or identical to any of the surface systems  110 ,  210 ,  310 , or  410 . 
     Any one of the previously described functionalities can be partially (or entirely) implemented in hardware and/or on the processor  901 . For example, the functionality can be implemented with an application specific integrated circuit, in logic implemented in the processor  901 , in a co-processor on a peripheral device or card, etc. Further, realizations can include fewer or additional components not illustrated in  FIG.  9    (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor  901  and the network interface  905  are coupled to the bus  903 . Although illustrated as being coupled to the bus  903 , the memory  907  can be coupled to the processor  901 . Moreover, while the computer device  900  is depicted as a computer, some embodiments can be any type of device or apparatus to perform operations described herein. 
     As will be appreciated, aspects of the disclosure can be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects can take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that can all generally be referred to herein as a “circuit” or “system.” The functionality presented as individual units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc. 
     Any combination of one or more machine readable medium(s) can be utilized. The machine-readable medium can be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium can be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium can be any tangible medium that can contain, or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium. 
     A machine-readable signal medium can include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal can take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium can be any machine readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device. 
     Program code embodied on a machine-readable medium can be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing. 
     Computer program code for carrying out operations for aspects of the disclosure can be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code can execute entirely on a stand-alone machine, can execute in a distributed manner across multiple machines, and can execute on one machine while providing results and or accepting input on another machine. 
     Terminology and Variations 
     The program code/instructions can also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks. 
     Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations, and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure. 
     Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed. A set of items can have only one item or more than one item. For example, a set of numbers can be used to describe a single number or multiple numbers. As used herein, a formation tester tool can be any tool or set of physically connected components that can be used to measure a property of a formation or a signal traveling through a formation. 
     Example Embodiments 
     Example embodiments include the following: 
     Embodiment 1: A method comprises forming a first sealed connection volume between a formation and a first pressure sensor in a borehole, forming a second sealed connection volume between the formation and a second pressure sensor in the borehole, wherein the second sealed connection volume surrounds the first sealed connection volume, lowering a pressure of the second sealed connection volume to be less than a borehole pressure, acquiring a first pressure measurement using the first pressure sensor, wherein the first pressure measurement is acquired before lowering the pressure of the second sealed connection volume, and wherein lowering the pressure comprises lowering the pressure to a first lowered outer volume pressure during a first interval, acquiring a second pressure measurement using the first pressure sensor during or after the first interval, and, in response to a determination that a measurement pattern shows a trend to a formation pressure value, generating a formation property prediction based on the second pressure measurement, wherein the measurement pattern is based on the second pressure measurement. 
     Embodiment 2: The method of Embodiment 1, further comprising increasing the pressure in the borehole. 
     Embodiment 3: The method of any of Embodiments 1-2, wherein lowering the pressure comprises lowering the pressure to a pressure value less than or equal to 75% of the borehole pressure. 
     Embodiment 4: The method of any of Embodiments 1-3, further comprising lowering the pressure of the second sealed connection volume during a second interval to a second lowered outer volume pressure, wherein the second lowered outer volume pressure is less than the first lowered outer volume pressure, and acquiring a third pressure measurement using the first pressure sensor during or after the second interval, wherein determining whether the measurement pattern shows the trend to the formation pressure value is based on the first pressure measurement, the second pressure measurement and the third pressure measurement. 
     Embodiment 5: The method of any of Embodiments 1-4, wherein generating the formation property prediction comprises establishing an average pressure measurement value as an actual formation pressure, wherein the average pressure measurement value is based on a series of pressure measurements comprising the first pressure measurement and the second pressure measurement. 
     Embodiment 6: The method of any of Embodiments 1-5, wherein determining whether the measurement pattern shows the trend to the formation pressure value comprising determining an asymptotic value based on the first pressure measurement and the second pressure measurement. 
     Embodiment 7: The method of any of Embodiments 1-6, wherein the method further comprises in response to a determination that the measurement pattern does not show the trend to the formation pressure value, perform a buildup operation, lower the pressure of the second sealed connection volume during an interval after the buildup operation, and acquire an additional pressure measurement using the first pressure sensor during or after the interval. 
     Embodiment 8: The method of any of Embodiments 1-7, wherein the formation property prediction comprises a mud weight. 
     Embodiment 9: An apparatus comprising a formation tester tool in a borehole within a formation, a first pressure sensor attached to the formation tester tool, a device to, form a first sealed connection volume between the formation and the first pressure sensor, form a second sealed connection volume between the formation and a second pressure sensor in the borehole, wherein the second sealed connection volume surrounds the first sealed connection volume, lower a pressure of the second sealed connection volume to be less than a borehole pressure, acquire a first pressure measurement using the first pressure sensor, wherein the first pressure measurement is acquired before lowering the pressure of the second sealed connection volume, and wherein lowering the pressure comprises lowering the pressure to a first lowered outer volume pressure during a first interval, acquire a second pressure measurement using the first pressure sensor during or after the first interval, and, in response to a determination that a measurement pattern shows a trend to a formation pressure value, generate a formation property prediction based on the second pressure measurement, wherein the measurement pattern is based on the second pressure measurement. 
     Embodiment 10: The apparatus of Embodiment 9, wherein the formation tester tool comprises a first pad, wherein the first pad is radially extendable with respect to an axis of the formation tester tool, and wherein the first pressure sensor is inside the first pad, and a second pad, wherein at least a portion of the first pad is inside of the second pad, and wherein the second pad is radially extendable with respect to the axis of the formation tester tool. 
     Embodiment 11: The apparatus of any of Embodiments 9-10, wherein the formation tester tool comprises a first pad, wherein the first pad is radially extendable with respect to an axis of the formation tester tool, and wherein the first pressure sensor is inside the first pad, a first radially extendable packer attached to the formation tester tool, wherein the first radially extendable packer is axially above the first pad with respect to the axis of the formation tester tool, and a second radially extendable packer attached to the formation tester tool, wherein the second radially extendable packer is axially below the first pad with respect to the axis of the formation tester tool. 
     Embodiment 12: The apparatus of any of Embodiments 9-11, wherein the formation tester tool comprises a first radially extendable packer attached to the formation tester tool, and a second radially extendable packer attached to the formation tester tool, wherein the second radially extendable packer is axially below the first radially extendable packer with respect to an axis of the formation tester tool, a first fluid extraction path that is exposed to a first volume between the first radially extendable packer and second radially extendable packer, a third radially extendable packer attached to the formation tester tool, wherein the third radially extendable packer is axially below the second radially extendable packer with respect to the axis of the formation tester tool, a second fluid extraction path that is exposed to a second volume between the second radially extendable packer and third radially extendable packer, wherein the second volume is at least a part of the second sealed connection volume, a fourth radially extendable packer attached to the formation tester tool, wherein the fourth radially extendable packer is axially below the third radially extendable packer with respect to the axis of the formation tester tool, and a third fluid extraction path that is exposed to a third volume between the third radially extendable packer and fourth radially extendable packer. 
     Embodiment 13: The apparatus of Embodiment 12, wherein the first pressure sensor is inside at least one of the second radially extendable packer and the third radially extendable packer. 
     Embodiment 13: The apparatus of any of Embodiments 12-13, wherein the formation tester tool comprises a pad, wherein the pad is radially extendable with respect to an axis of the formation tester tool, and wherein the first pressure sensor is inside the pad, and wherein the pad is within the second volume. 
     Embodiment 15: One or more non-transitory machine-readable media comprising program code for generating a formation property prediction, the program code to form a first sealed connection volume between a formation and a first pressure sensor, form a second sealed connection volume between the formation and a second pressure sensor in a borehole, wherein the second sealed connection volume surrounds the first sealed connection volume, lower a pressure of the second sealed connection volume to be less than a borehole pressure, acquire a first pressure measurement using the first pressure sensor, wherein the first pressure measurement is acquired before lowering the pressure of the second sealed connection volume, and wherein lowering the pressure comprises lowering the pressure to a first lowered outer volume pressure during a first interval, acquire a second pressure measurement using the first pressure sensor during or after the first interval, and, in response to a determination that a measurement pattern shows a trend to a formation pressure value, generate the formation property prediction based on the second pressure measurement, wherein the measurement pattern is based on the second pressure measurement. 
     Embodiment 16: The one or more non-transitory machine-readable media of Embodiment 15, further comprising program code to lower the pressure of the second sealed connection volume during a second interval to a second lowered outer volume pressure, wherein the second lowered outer volume pressure is less than the first lowered outer volume pressure, and acquire a third pressure measurement using the first pressure sensor during or after the second interval, wherein determining whether the measurement pattern shows the trend to the formation pressure value is based on the first pressure measurement, the second pressure measurement and the third pressure measurement. 
     Embodiment 17: The one or more non-transitory machine-readable media of any of Embodiments 15-16, further comprising program code to establish an average pressure measurement value as an actual formation pressure, wherein the average pressure measurement value is based on the the first pressure measurement and the second pressure measurement. 
     Embodiment 18: The one or more non-transitory machine-readable media of any of Embodiments 15-17, wherein determining whether the measurement pattern shows the trend to the formation pressure value comprising determining an asymptotic value based on the first pressure measurement and the second pressure measurement. 
     Embodiment 19: The one or more non-transitory machine-readable media of any of Embodiments 15-18, further comprising program code to, in response to a determination that the measurement pattern does not show the trend to the formation pressure value, perform a buildup operation, lower the pressure of the second sealed connection volume during an interval after performing the buildup operation, and acquire an additional pressure measurement using the first pressure sensor during or after the interval. 
     Embodiment 20: The one or more non-transitory machine-readable media of any of Embodiments 15-19, wherein the formation property prediction comprises a mud weight.