Patent Publication Number: US-11661809-B2

Title: Logging a well

Description:
TECHNICAL FIELD 
     This disclosure relates to logging a well and, more particularly, logging a well downhole of a hydrocarbon production unit positioned in a wellbore. 
     BACKGROUND 
     Gaining access within a wellbore below hydrocarbon production unit, such as a pump or production inlet, may be desirable for a field asset operator to determine, for example, reservoir characteristics. Conventionally, bypass equipment, such as a “Y-tool,” allows the capability of accessing a reservoir for logging purposes when a pump (for example, an electrical submersible pump (ESP)) is installed. Installation of Y-tools are typically restricted to a casing size of a completion of the wellbore. To log a well with a Y-Tool installed, a logging crew needs to be mobilized for the operation. Access to the well is via the by-pass leg of the Y-Tool. Mobilizing crews to perform logging operations can take some time to schedule the job depending on, for example, an availability of the logging crew. This incurs non-productive time for the field asset operator to acquire needed reservoir data for production planning. Furthermore, mobilizing a logging crew can be expensive, and even more so when there may be limited availability of the crew. Such high costs translate to a non-economical bottom line for a well operator. 
     SUMMARY 
     This disclosure describes a downhole tool for logging a well (also called a wellbore). In some aspects, the downhole tool includes a production sub-assembly and a logging sub-assembly coupled to a downhole end of the production sub-assembly. The production sub-assembly operates to produce a wellbore fluid to the surface (for example, by artificial lift or natural circulation, or both) in a production operation. The logging sub-assembly operates to log a portion of the wellbore downhole of the downhole tool in a logging operation. In some aspects, the downhole tool may simultaneously complete the production operation and the logging operation. 
     In an example implementation, a downhole tool includes a production unit configured to fluidly couple to a production tubing positioned in a wellbore that is formed from a terranean surface to a subterranean formation. The production unit includes an inlet configured to fluidly couple to the wellbore to receive a production fluid. The tool further includes a logging unit coupled to a downhole end of the production unit. The logging unit includes a cable spooler configured to move a cable from the cable spooler through the wellbore downhole of the production unit, the cable including one or more logging sensors, and a cable motor configured to operate the cable spooler to move the cable through the wellbore downhole of the production unit. 
     In an aspect combinable with the example implementation, the production unit includes a downhole pump assembly. 
     In another aspect combinable with any of the previous aspects, the downhole pump assembly includes a pump motor, a production fluid pump coupled to the pump motor, and a pump intake that includes the inlet. 
     In another aspect combinable with any of the previous aspects, the downhole pump assembly further includes a monitoring sub-assembly coupled to a downhole end of the pump motor, and a motor protector coupled between the pump motor and the intake. 
     In another aspect combinable with any of the previous aspects, the logging unit is coupled to the monitoring sub-assembly. 
     In another aspect combinable with any of the previous aspects, the downhole pump assembly includes an electrical submersible pump (ESP). 
     In another aspect combinable with any of the previous aspects, the cable includes a fiber optic cable. 
     In another aspect combinable with any of the previous aspects, the logging unit further includes a weight attached to a downhole end of the cable. 
     In another aspect combinable with any of the previous aspects, the one or more logging sensors is configured to record at least one of a resistivity, a conductivity, a pressure, a temperature, or a sonic property of the subterranean formation. 
     In another aspect combinable with any of the previous aspects, the logging unit is coupled to the inlet of the production unit. 
     In another aspect combinable with any of the previous aspects, the cable includes a fiber optic cable. 
     In another aspect combinable with any of the previous aspects, the logging unit further includes a weight attached to a downhole end of the cable. 
     In another aspect combinable with any of the previous aspects, the one or more logging sensors is configured to record at least one of a resistivity, a conductivity, a pressure, a temperature, or a sonic property of the subterranean formation. 
     In another example implementation, a method includes running a downhole tool into a wellbore on a production tubular. The wellbore is formed from a terranean surface to a subterranean formation. The downhole tool includes a production unit and a logging unit coupled to a downhole end of the production unit. The method further includes positioning the downhole tool in the wellbore adjacent the subterranean formation; unspooling a cable from the logging unit in a direction downhole of the downhole tool; logging the wellbore with the unspooled cable; and during logging of the wellbore, producing a wellbore fluid from the wellbore through an inlet of the production unit and into the production tubular. 
     In an aspect combinable with the example implementation, producing the wellbore fluid from the wellbore includes pumping the wellbore fluid from the wellbore with a downhole pump assembly of the production unit. 
     Another aspect combinable with any of the previous aspects further includes, during production of the wellbore fluid, measuring at least one parameter associated with the downhole pump assembly; and transmitting the measured at least one parameter to the terranean surface. 
     In another aspect combinable with any of the previous aspects, pumping the wellbore fluid from the wellbore with the downhole pump assembly of the production unit includes pumping the wellbore fluid from the wellbore with an electrical submersible pump (ESP) that includes an intake that includes the inlet. 
     In another aspect combinable with any of the previous aspects, logging the wellbore includes measuring one or more parameters of the subterranean formation with the cable that includes a fiber optic cable. 
     In another aspect combinable with any of the previous aspects, the one or more measured parameters of the subterranean formation includes at least one of a resistivity, a conductivity, a pressure, a temperature, or a sonic property. 
     In another aspect combinable with any of the previous aspects, producing the wellbore fluid from the wellbore includes receiving the wellbore fluid into the inlet of the production unit based at least in part on a pressure difference between the subterranean formation and the production string. 
     In another aspect combinable with any of the previous aspects, logging the wellbore includes measuring one or more parameters of the subterranean formation with the cable that includes a fiber optic cable. 
     In another aspect combinable with any of the previous aspects, the one or more measured parameters of the subterranean formation includes at least one of a resistivity, a conductivity, a pressure, a temperature, or a sonic property. 
     In another example implementation, a downhole tool system includes an electrical submersible pump (ESP) assembly configured to couple to a downhole conveyance that includes a production fluid flow path for a production fluid from a subterranean formation; and a logging sub-assembly directly coupled to a downhole end of the ESP assembly and including a length of logging cable spoolable off a cable spool of the logging sub-assembly within a wellbore. 
     In an aspect combinable with the example implementation, the ESP assembly includes a pump that includes an intake configured to fluidly couple to an annulus of the wellbore to receive the production fluid from the subterranean formation; and a pump motor coupled to the intake at a downhole end of the pump. 
     In another aspect combinable with any of the previous aspects, the logging sub-assembly further includes a spooler motor coupled to the cable spool and operable to spool the logging cable from and onto the cable spool; and a weight coupled to first portion of the logging cable opposite a second portion of the logging cable that is coupled to the cable spool. 
     Another aspect combinable with any of the previous aspects further includes at least one power cable electrically coupled to at least one of the pump motor or the spooler motor and configured to transfer electric current to the at least one of the pump motor or the spooler motor from a terranean surface. 
     In another aspect combinable with any of the previous aspects, the logging cable includes at least one fiber optic cable that includes at least one logging sensor. 
     In another aspect combinable with any of the previous aspects, the at least one logging sensor is configured to measure at least one of a resistivity, a conductivity, a pressure, a temperature, or a sonic property of the subterranean formation. 
     Implementations of a downhole tool according to the present disclosure may include one or more of the following features. For example, the downhole tool may enable or help enable logging access below a downhole pump, such as an electric submersible pump. As another example, the downhole tool may save service crew costs associated with logging a well if a conventional Y-tool (by-pass) tool was installed. As yet a further example, the downhole tool may save time required to schedule and mobilize a logging crew and unit when logging of a wellbore under (or directly before or after) production is desired. As another example, the downhole tool may enable independent control and operation of a logging unit separate from a pumping unit within a single tool or tool assembly. As a further example, the downhole tool may be integrated seamlessly into existing downhole pump (for example, ESP) completions. 
     The details of one or more implementations of the subject matter described in this disclosure are set forth in the accompanying drawings and the description below. Other features, aspects, and advantages of the subject matter will become apparent from the description, the drawings, and the claims. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG.  1    is a schematic diagram of an example system that includes a downhole tool according to the present disclosure. 
         FIGS.  2 A and  2 B  are schematic diagrams of an example implementation of a downhole tool according to the present disclosure during non-production of a wellbore fluid. 
         FIGS.  3 A and  3 B  are schematic diagrams of the downhole tool of  FIGS.  2 A and  2 B  during production of a wellbore fluid. 
         FIGS.  4 A and  4 B  are schematic diagrams of another example implementation of a downhole tool according to the present disclosure during non-production of a wellbore fluid. 
         FIGS.  5 A and  5 B  are schematic diagrams of the downhole tool of  FIGS.  4 A and  4 B  during production of a wellbore fluid. 
         FIG.  6    is a flowchart that describes an example operation with a downhole tool according to the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
       FIG.  1    is a schematic diagram of an example wellbore system  10  including a downhole tool  100 . Generally,  FIG.  1    illustrates a portion of one embodiment of a wellbore system  10  according to the present disclosure in which the downhole tool  100  may be run into a wellbore  20  and operated when the downhole tool  100  reaches a particular location of a wellbore tubular  17  (or simply, tubular  17  or production string  17 ) within the wellbore  20 . The downhole tool  100 , in some aspects, includes a production unit (or sub-assembly) that is integrated with or coupled to a logging unit (or sub-assembly) without a Y tool or other bypass tool. In some aspects, the production unit operates to produce the production fluid  50  toward a terranean surface  12  within the wellbore tubular  17  while the logging unit logs a portion of the wellbore  20  downhole of the downhole tool  100 . In some aspects, the production unit ceases production operation while the logging unit logs the portion of the wellbore  20  downhole of the downhole tool  100 . In some aspects, the production unit operates to produce the production fluid  50  toward the terranean surface  12  within the wellbore tubular  17  without simultaneous operation of the logging unit. 
     As shown, the wellbore system  10  accesses a subterranean formation  40  and provides access to the production fluid  50  (for example, hydrocarbons or otherwise) located in such subterranean formation  40 . In an example implementation of system  10 , the system  10  may be used for a production operation in which a production fluid  50  (for example, oil, gas, mixed oil and gas, water) may be produced from the subterranean formation  40  within the wellbore tubular  17  (for example, as a production tubing). 
     A drilling assembly (not shown) may be used to form the wellbore  20  extending from the terranean surface  12  and through one or more geological formations in the Earth. One or more subterranean formations, such as subterranean zone  40 , are located under the terranean surface  12 . As will be explained in more detail below, one or more wellbore casings, such as a surface casing  30  and intermediate casing  35 , may be installed in at least a portion of the wellbore  20 . In some embodiments, a drilling assembly used to form the wellbore  20  may be deployed on a body of water rather than the terranean surface  12 . For instance, in some embodiments, the terranean surface  12  may be submerged under an ocean, gulf, sea, or any other body of water under which hydrocarbon-bearing formations may be found. In short, reference to the terranean surface  12  includes both land and underwater surfaces and contemplates forming and developing one or more wellbore systems  10  from either or both locations. 
     In some embodiments of the wellbore system  10 , the wellbore  20  may be cased with one or more casings. As illustrated, the wellbore  20  includes a conductor casing  25 , which extends from the terranean surface  12  shortly into the Earth. A portion of the wellbore  20  enclosed by the conductor casing  25  may be a large diameter borehole. Additionally, in some embodiments, the wellbore  20  may be offset from vertical (for example, a slant wellbore). Even further, in some embodiments, the wellbore  20  may be a stepped wellbore, such that a portion is drilled vertically downward and then curved to a substantially horizontal wellbore portion. Additional substantially vertical and horizontal wellbore portions may be added according to, for example, the type of terranean surface  12 , the depth of one or more target subterranean formations, the depth of one or more productive subterranean formations, or other criteria. 
     Downhole of the conductor casing  25  may be the surface casing  30 . The surface casing  30  may enclose a slightly smaller borehole and protect the wellbore  20  from intrusion of, for example, freshwater aquifers located near the terranean surface  12 . The wellbore  20  may then extend vertically downward. This portion of the wellbore  20  may be enclosed by the intermediate casing  35 . In some aspects, the intermediate casing  35  may be a production casing  35  in which one or more perforations (not shown in  FIG.  1   ) may be formed to fluidly couple an annulus  60  of the wellbore  20  with the subterranean formation  40 . In some aspects, one or more hydraulic fractures (not shown) may also be formed in the subterranean formation  40  from the wellbore  20  in order to enhance or increase production of the production fluid  50  into the wellbore  20 . 
     As shown in  FIG.  1   , the downhole tool  100  may be run into the wellbore  20  from the terranean surface  12  and positioned adjacent the subterranean formation  40 . Once positioned, the downhole tool  100  may be operated to perform production and logging operations as described in more detail with reference to the remaining figures. In some aspects, the production and logging operations may be performed serially or in parallel with the downhole tool  100 . 
       FIGS.  2 A- 2 B  are schematic diagrams of an example implementation of a downhole tool  200  during non-production of a wellbore fluid, such as, the production fluid  50  shown in  FIG.  1   . In some aspects, downhole tool  200  may be used as the downhole tool  100  in the wellbore system  10  of  FIG.  1   .  FIG.  2 A  illustrates the downhole tool  200  and its components when positioned in the wellbore  20  as shown.  FIG.  2 A  illustrates the downhole tool  200  during a logging operation (for example, logging of a portion of the wellbore  20  downhole of the tool  200 ) but not during a simultaneous production operation (for example, producing a wellbore fluid to the production tubing  17  with the downhole tool  200 ). As shown in  FIG.  2 A , the downhole tool  200  includes a production unit  202  and a logging unit  204  that is coupled to a downhole end of the production unit  202 . In this example, the logging unit  204  is coupled directly to the downhole end of the production unit  202 . The production unit  202  is coupled (for example, fluidly and mechanically) to the production tubing  17 . The downhole tool  200  is positioned within the production casing  35  and adjacent the subterranean formation  40  within the wellbore  20 . 
     In this example, the downhole tool  200  is positioned just uphole of perforations  65  that have been formed (for instance, shot) in the production casing  35 . As shown in this example, downhole tool  200  is positioned downhole of a wellbore seal  55  (for example, a packer, bridge plug, or other wellbore seal) within the annulus  60  of the wellbore  20 . The production tubing  17  extends through the wellbore seal  55  and to the surface. The wellbore seal  55 , therefore, creates a production zone of the wellbore  20  downhole of the seal  55 , and wellbore fluids (such as production fluid  50 ) are not fluidly communicated from the production zone uphole of the wellbore seal  55 . 
     In this example implementation of the downhole tool  200 , the production unit  202  includes a pump  206 . In some aspects, the pump  206  is an electrical submersible pump (ESP) (ESP  206 ). Alternatively, the pump  206  may be a progressive cavity pump, centrifugal pump, or other downhole artificial lift device that obstructs access to the subterranean formation  40  for logging purposes. The pump  206 , in this example, is used to lift wellbore fluids (for example, production fluid  50 ) to the terranean surface  12 , or if at or near the terranean surface  12 , transfers fluid from one location to another. 
     Directly downhole of the pump  206  in the production unit  202  is an intake  208 . The intake  208  includes one or more apertures (for example, adjustable to open and close or fixed in an open position) that fluidly couples the pump  206  with the annulus  60  of the wellbore  20 . The pump  206 , in fluid communication with the annulus  60  through the intake  208 , may then receive a wellbore fluid therein to lift the fluid to the terranean surface  12  during operation. 
     In some aspects, the pump  206  includes one or more stages, each of which comprises an impeller and a diffuser. An impeller, which is rotating, adds energy to the wellbore fluid received into the intake  208  to provide head. The diffuser, which is stationary, converts the kinetic energy of the wellbore fluid from the impeller into head. In some aspects, the pump stages are stacked in series to form a multi-stage system that is contained within the pump  206 . The sum of head generated by each individual stage is cumulative; hence, the total head developed by a multi-stage system increases linearly from the first to the last stage of the pump  206 . 
     In this example, a pump motor protector  210  is coupled to the intake  208  and to a pump motor  212 . The pump motor  212 , generally, provides mechanical power required to drive the pump  206  via a shaft. As shown in this example, the pump motor  212  is an electric motor that receives electric power through a pump power cable  216  that extends through the annulus  60  (and through the wellbore seal  55 ) to electrically couple to the pump motor  212 . Thus, in this example, the pump power cable  216  provides electrical power from the terranean surface  12  to the pump motor  212 . The pump motor protector  210 , in this example, operates to absorb a thrust load from the pump  206 , transmits power from the motor  212  to the pump  206 , equalizes pressure, provides/receives additional motor oil as the motor temperature changes, and prevents wellbore fluid from entering the pump motor  212 . 
     Certain pump motor operational parameters, such as pump intake and discharge pressures, motor oil and winding temperature, and vibration may be measured by the monitoring sub-assembly  214  that is directly coupled to a downhole end of the pump motor  212  in this example implementation. The monitoring sub-assembly  214 , in this example, may communicate such measured parameters to the terranean surface  12  through the pump power cable  216 . 
     In alternative implementations of the downhole tool  200 , the pump motor  212  may be positioned uphole of the pump  206  in the tool  200 . For example, the production unit  202  may include an inverted ESP, such that the pump motor  212  is uphole of the pump motor protector  210 , which is uphole of the pump  206 . In other alternative implementations, the downhole tool  200  may be deployed on a wireline or other cable downhole conveyance (in a regular or inverted order) rather than the production tubing  17 . 
     As shown in  FIG.  2 A , the logging unit  204  is coupled to a downhole end of the production unit  202  (in other words, the monitoring sub-assembly  214 ), through a spacer  218 . In some aspects, the spacer  218  is part of the logging unit  204 . The spacer  218 , in this example, is attached above a spooler motor protector  220 , and provides an axial distance between the spooler motor protector  220  and the monitoring sub-assembly  214  of the production unit  202 . In some aspects, there is no shaft through the spacer  218 , thus ensuring no contact between a rotating shaft of the spooler motor protector  220  and the (non-rotating) monitoring sub-assembly  214 . 
     Directly coupled to the spooler motor protector  220  is a spooler motor  222 . The spooler motor  222 , in this example, is an electric motor that includes a motor shaft coupled to a shaft of a cable spooler  224  coupled to the downhole end of the spooler motor  222 . The spooler motor  222 , in this example, provides the mechanical power to rotate the shaft of the cable spooler  224  to unwind a logging cable  230 . In some aspects, the electrical power to drive the spooler motor  222  is provided from the terranean surface  12  via by a spooler power cable  226  dedicated for the spooler motor  222 . Alternatively, the spooler power cable  226  can be eliminated and electric power to the spooler motor  222  can be provided via an addressable power unit via the pump power cable  216 . 
     In the illustrated implementation, there may be little or no pump thrust load to be handled by the spooler motor protector  220 . Thus, in some aspects, no thrust bearing or a very low-capacity thrust bearing may be used in the spooler motor protector  220  to take up any residual thrust loads. In some aspects, the spooler motor protector  220  may operate primarily to equalize pressure, provide/receive additional oil to/from the spooler motor  222  as temperature changes, and prevent wellbore fluid from entering the spooler motor  222 . 
     Coupled to the spooler motor  222  is a cable spooler  224  on which a length of the logging cable  230  (shown in  FIG.  2 B ) is spooled for storage and spoolable off of the cable spooler  224  to log the wellbore  20 . In the example implementation, the spooler motor  222  is attached above the cable spooler  224  and the motor shaft is coupled to a shaft within the cable spooler  224 . As the shaft of the spooler motor  222  rotates, the shaft of the cable spooler  224  rotates to unspool the logging cable  230  off of the cable spooler  224 , or spool the logging cable  230  onto the cable spooler  224 . For storage purposes (such as during a production only operation or during running into or out of the wellbore), the logging cable  230  can be wrapped round a shaft or drum (not shown) within the cable spooler  224 . 
     As shown in  FIG.  2 B , a weight  228  is attached to an end of the logging cable  230  (and another end of the logging cable  230  may be attached to the cable spooler  224 ). In some aspects, the weight  228  may be selected to ensure that the logging cable is not damaged during cable unspooling, but yet able to be lowered into the wellbore  20  even during production operations of the production unit  202  (as explained later). In some aspects, the weight  228  may also be selected to ensure that the logging cable  230  can be lowered in a downhole direction from the cable spooler  224  due to gravity, and also to keep the logging cable  230  taut after unspooling (for example, during a logging operation). 
     In this example, the logging cable  230  may be a fiber optic logging cable. For example, the fiber optic logging cable can be a single mode or multimode cable, but in the preferred implementation, a multimode fiber optic cable may be used. In some aspects, logging data may be communicated to the terranean surface  12  via either a dedicated fiber embedded in the spooler motor power cable  226 . Alternatively, a laser source for the fiber optic cable and electronics may be included to convert a light pulse to an electronic signal and incorporated in a housing just above the cable spooler  224 . 
     In some alternative aspects, logging data may be transmitted electrically via communication over power on the spooler motor power cable  226 . For example, if the fiber optic cable is carried via an embedded fiber optic in the spooler motor power cable  226  to the terranean surface  12 , the laser light source could be located at the terranean surface  12 . Further, electronic signal processing for the received logging data may occur at the terranean surface  12 . In some aspects, a fiber optic rotary union (for example, by Moog Inc. (www.moog.com/products/fiber-optic-rotary-joints.html)) may be used at the cable spooler  224  to allow the transmission of the light from a stationary fiber optic cable as part of the spooler motor power cable  226  to the logging cable  230  that moves and rotates on the cable spooler  224 . 
     As shown in  FIG.  2 A , the downhole tool  200  is positioned in the wellbore  20  (for example, adjacent or near perforations  65  made in the production casing  35 ) but is not shown performing a production or logging operation. In some aspects, the downhole tool  200  may simultaneously perform production and logging operations (without running the downhole tool  200  out of the wellbore or running a separate logging tool into the wellbore). In some aspects, the downhole tool  200  may perform a production operation without performing a logging operation. In some aspects, the downhole tool  200  may perform a logging operation without performing a production operation. For example,  FIG.  2 B  shows an example in which the downhole tool  200  is performing a logging operation of a portion of the wellbore  20  (in other words, the subterranean formation  40 ) downhole of the downhole tool  200  without performing a production operation (such as prior or subsequent to a previous production operation without running the downhole tool  200  out of the wellbore or running a separate logging tool into the wellbore). 
     In an example operation illustrated in  FIG.  2 B , the spooler motor  222  operates to rotate the shaft of the cable spooler  224  to unspool the logging cable  230  as shown in  FIG.  2 B . In some aspects, a maximum depth that can be reached within the wellbore  20  by the logging cable  230  is a function of the cable length available within the cable spooler  224 . As the logging cable  230  unspools, the weight  228  may help “pull” the logging cable  230  in a direction downhole while also keeping the logging cable  230  taut and stable within the wellbore  20 . Once the desired logging depth is reached by at least a portion of the logging cable  230 , motor rotation of the cable spooler motor  222  can be stopped. Logging of reservoir pressure and temperature is performed via the logging cable  230 . The data received from the logging cable  230  is transmitted, for example, through the spooler motor power cable  226  to the terranean surface  12 . The logging data generated from such a log can be used to obtain characteristics of the subterranean formation  40 , such as pressure, temperature, and other data. Once logging has been completed, the spooler motor  222  can be switched on to rotate in a direction opposite that during the logging cable unspooling operation. This ensures that the logging cable  230  retracts back onto the cable spooler  224  to the original position as shown in  FIG.  2 A . Operation of the spooler motor  222  can be commanded, for example, according to commands provided from the terranean surface  12  (for example, through the power cable  226 ), from preprogrammed instructions in the logging unit  204 , or otherwise. 
       FIG.  3 A  illustrates a situation in which the downhole tool  200  is performing a production operation without performing a logging operation. In this example, a production operation includes operation of the production unit  202  so that the pump  206  is operated (in other words, rotated) by the pump motor  212  to circulate production fluid  50  from the wellbore  20  to the terranean surface  12 . Electric power may be supplied to the pump motor  212  through the pump power cable  216 , which initiates operation of the pump motor  212 . The operating pump motor  212 , in turn, rotates the pump  206  to circulate production fluid  50  from the subterranean formation  40 , through the perforations  65 , and into the intake  208  of the production unit  202 . The pump  206  continues to operate to lift the production fluid  50  through the intake  208  and into the production tubing  17  to the terranean surface  12 . 
       FIG.  3 B  illustrates a situation in which the downhole tool  200  is performing a production operation simultaneously while performing a logging operation. For example, as described with reference to  FIG.  3 A , the production unit  202  may be operated to circulate production fluid  50  from the subterranean formation  40 , through the perforations  65 , into the intake  208  and through the intake  208  and into the production tubing  17  to the terranean surface  12 . Simultaneously with operation of the production unit  202 , the logging unit  204  may be operated (for example, as described with reference to  FIG.  2 B ) to log the subterranean formation  40  downhole of the downhole tool  200 . For example, the logging unit  204  can be operated to unspool the logging cable  230  from the cable spooler  224  to a particular downhole depth below the downhole tool  200 . The logging cable  230  can then measure particular formation parameters, such as temperature, pressure, resistivity, gamma ray, sonic. The measured data can be transmitted, for example, to the terranean surface  12  on the spooler motor power cable  226  (or within, for instance, a fiber optic cable embedded in the power cable  226 ). 
     In some aspects, downhole tool  200 , which includes the pump  206  within the production unit  202 , may be used for subterranean formations that do not have sufficient natural drive (for example, pressure difference between formation pressure and the wellbore  20 ) to lift wellbore fluid into the production unit  202  (and through the production tubing  17 ) to the terranean surface  12 . Alternatively, in some aspects, the downhole tool  200  may be used in reservoirs with some natural drive, but the pump  206  of the production unit  202  is used to boost production (for instance, flow rate) of the production fluid  50  to the terranean surface  12 . 
       FIGS.  4 A- 4 B  are schematic diagrams of another example implementation of a downhole tool  300  during non-production of a wellbore fluid, such as, the production fluid  50  shown in  FIG.  1   . In some aspects, downhole tool  300  may be used as the downhole tool  100  in the wellbore system  10  of  FIG.  1   .  FIG.  4 A  illustrates the downhole tool  300  and its components when positioned in the wellbore  20  as shown.  FIG.  4 B  illustrates the downhole tool  300  during a logging operation (for example, logging of a portion of the wellbore  20  downhole of the tool  300 ) but not during a simultaneous production operation (for example, producing a wellbore fluid to the production tubing  17  with the downhole tool  300 ). As shown in  FIG.  4 A , the downhole tool  300  includes a production unit  302  and a logging unit  304  that is coupled to a downhole end of the production unit  302 . In this example, the logging unit  304  is coupled directly to the downhole end of the production unit  302 . The production unit  302  is coupled (for example, fluidly and mechanically) to the production tubing  17 . The downhole tool  300  is positioned within the production casing  35  and adjacent the subterranean formation  40  within the wellbore  20 . 
     In this example, the downhole tool  300  is positioned just uphole of perforations  65  that have been formed (for instance, shot) in the production casing  35 . As shown in this example, downhole tool  300  is positioned downhole of a wellbore seal  55  (for example, a packer, bridge plug, or other wellbore seal) within the annulus  60  of the wellbore  20 . The production tubing  17  extends through the wellbore seal  55  and to the surface. The wellbore seal  55 , therefore, creates a production zone of the wellbore  20  downhole of the seal  55 , and wellbore fluids (such as production fluid  50 ) are not fluidly communicated from the production zone uphole of the wellbore seal  55 . 
     In this example implementation of the downhole tool  300 , the production unit  302  includes an intake  308 , but not a pump (or other artificial lift device). The intake  308  includes one or more apertures (for example, adjustable to open and close or fixed in an open position) that fluidly couples the production unit  302  (and thus the production tubing  17 ) with the annulus  60  of the wellbore  20 . The intake  308  may receive a wellbore fluid therein to communicate the fluid to the terranean surface  12  during operation. For example, in some aspects, the downhole tool  300  with production unit  302  may be used in reservoirs with sufficient natural energy (for instance, difference in formation pressure vs. annulus pressure) to drive the wellbore fluid into the intake  308  and up the production tubing  17  to the terranean surface  12 . 
     As shown in  FIG.  4 A , the logging unit  304  is coupled to a downhole end of the production unit  302  (in other words, the intake  308 ). In this example, a spooler motor protector  320  is directly coupled to the intake  308  of the production unit  302 . Directly coupled to the spooler motor protector  320  is a spooler motor  322 . The spooler motor  322 , in this example, is an electric motor that includes a motor shaft coupled to a shaft of a cable spooler  324  coupled to the downhole end of the spooler motor  322 . The spooler motor  322 , in this example, provides the mechanical power to rotate the shaft of the cable spooler  324  to unwind a logging cable  330 . In some aspects, the electrical power to drive the spooler motor  322  is provided from the terranean surface  12  via by a spooler power cable  326  dedicated for the spooler motor  322 . 
     In the illustrated implementation, there may be little or no pump thrust load to be handled by the spooler motor protector  320 . Thus, in some aspects, no thrust bearing or a very low-capacity thrust bearing may be used in the spooler motor protector  320  to take up any residual thrust loads. In some aspects, the spooler motor protector  320  may operate primarily to equalize pressure, provide/receive additional oil to/from the spooler motor  322  as temperature changes, and prevent wellbore fluid from entering the spooler motor  322 . 
     Coupled to the spooler motor  322  is a cable spooler  324  on which a length of the logging cable  330  (shown in  FIG.  4 B ) is spooled for storage and spoolable off of the cable spooler  324  to log the wellbore  20 . In the example implementation, the spooler motor  322  is attached above the cable spooler  324  and the motor shaft is coupled to a shaft within the cable spooler  324 . As the shaft of the spooler motor  322  rotates, the shaft of the cable spooler  324  rotates to unspool the logging cable  330  off of the cable spooler  324 , or spool the logging cable  330  onto the cable spooler  324 . For storage purposes (such as during a production only operation or during running into or out of the wellbore), the logging cable  330  can be wrapped round a shaft or drum (not shown) within the cable spooler  324 . 
     As shown in  FIG.  4 B , a weight  328  is attached to an end of the logging cable  330  (and another end of the logging cable  330  may be attached to the cable spooler  324 ). In some aspects, the weight  328  may be selected to ensure that the logging cable is not damaged during cable unspooling, but yet able to be lowered into the wellbore  20  even during production operations of the production unit  302  (as explained later). In some aspects, the weight  328  may also be selected to ensure that the logging cable  330  can be lowered in a downhole direction from the cable spooler  324  due to gravity, and also to keep the logging cable  330  taut after unspooling (for example, during a logging operation). 
     In this example, the logging cable  330  may be a fiber optic logging cable. For example, the fiber optic logging cable can be a single mode or multimode cable, but in the preferred implementation, a multimode fiber optic cable may be used. In some aspects, logging data may be communicated to the terranean surface  12  via either a dedicated fiber embedded in the spooler motor power cable  326 . Alternatively, a laser source for the fiber optic cable and electronics may be included to convert a light pulse to an electronic signal and incorporated in a housing just above the cable spooler  324 . 
     In some alternative aspects, logging data may be transmitted electrically via communication over power on the spooler motor power cable  326 . For example, if the fiber optic cable is carried via an embedded fiber optic in the spooler motor power cable  326  to the terranean surface  12 , the laser light source could be located at the terranean surface  12 . Further, electronic signal processing for the received logging data may occur at the terranean surface  12 . In some aspects, a fiber optic rotary union (for example, by Moog Inc. (www.moog.com/products/fiber-optic-rotary-joints.html)) may be used at the cable spooler  324  to allow the transmission of the light from a stationary fiber optic cable as part of the spooler motor power cable  326  to the logging cable  330  that moves and rotates on the cable spooler  324 . 
     As shown in  FIG.  4 A , the downhole tool  300  is positioned in the wellbore  20  (for example, adjacent or near perforations  65  made in the production casing  35 ) but is not shown performing a production or logging operation. In some aspects, the downhole tool  300  may simultaneously perform production and logging operations (without running the downhole tool  300  out of the wellbore or running a separate logging tool into the wellbore). In some aspects, the downhole tool  300  may perform a production operation without performing a logging operation. In some aspects, the downhole tool  300  may perform a logging operation without performing a production operation. For example,  FIG.  4 B  shows an example in which the downhole tool  300  is performing a logging operation of a portion of the wellbore  20  (in other words, the subterranean formation  40 ) downhole of the downhole tool  300  without performing a production operation (such as prior or subsequent to a previous production operation without running the downhole tool  300  out of the wellbore or running a separate logging tool into the wellbore). 
     In an example operation illustrated in  FIG.  4 B , the spooler motor  322  operates to rotate the shaft of the cable spooler  324  to unspool the logging cable  330  as shown in  FIG.  4 B . In some aspects, a maximum depth that can be reached within the wellbore  20  by the logging cable  330  is a function of the cable length available within the cable spooler  324 . As the logging cable  330  unspools, the weight  328  may help “pull” the logging cable  330  in a direction downhole while also keeping the logging cable  330  taut and stable within the wellbore  20 . Once the desired logging depth is reached by at least a portion of the logging cable  330 , motor rotation of the cable spooler motor  322  can be stopped. Logging of reservoir pressure and temperature is performed via the logging cable  330 . The data received from the logging cable  330  is transmitted, for example, through the spooler motor power cable  326  to the terranean surface  12 . The logging data generated from such a log can be used to obtain characteristics of the subterranean formation  40 , such as pressure, temperature, and other data. Once logging has been completed, the spooler motor  322  can be switched on to rotate in a direction opposite that during the logging cable unspooling operation. This ensures that the logging cable  330  retracts back onto the cable spooler  324  to the original position as shown in  FIG.  4 A . Operation of the spooler motor  322  can be commanded, for example, according to commands provided from the terranean surface  12  (for example, through the power cable  326 ), from preprogrammed instructions in the logging unit  304 , or otherwise. 
       FIG.  5 A  illustrates a situation in which the downhole tool  300  is performing a production operation without performing a logging operation. In this example, a production operation includes operation of the production unit  302 . In some aspects, operation of the production unit  302  may include opening one or more sliding doors (or sleeves) of the intake  308  to fluidly couple the intake  308  (and production tubing  17 ) with the annulus  60  of the wellbore  20 . Alternatively, a plug or seal internal to the intake  308  may be removed or adjusted to fluidly couple the intake  308  (and production tubing  17 ) with the annulus  60  of the wellbore  20 . Once fluidly coupled, the production fluid  50  circulates into the intake  308  (for instance, due to the natural drive of the subterranean formation  40 ) and up the production tubing  17  to the terranean surface  12 . 
       FIG.  5 B  illustrates a situation in which the downhole tool  300  is performing a production operation simultaneously while performing a logging operation. For example, as described with reference to  FIG.  5 A , the production unit  302  may be operated to circulate production fluid  50  from the subterranean formation  40 , through the perforations  65 , into the intake  308  and through the intake  308  and into the production tubing  17  to the terranean surface  12 . Simultaneously with operation of the production unit  302 , the logging unit  304  may be operated (for example, as described with reference to  FIG.  4 B ) to log the subterranean formation  40  downhole of the downhole tool  300 . For example, the logging unit  304  can be operated to unspool the logging cable  330  from the cable spooler  324  to a particular downhole depth below the downhole tool  300 . The logging cable  330  can then measure particular formation parameters, such as temperature, pressure, resistivity, gamma ray, sonic. The measured data can be transmitted, for example, to the terranean surface  12  on the spooler motor power cable  326  (or within, for instance, a fiber optic cable embedded in the power cable  326 ). 
       FIG.  6    illustrates a flowchart of a method  600  for an example operation with a downhole tool, such as the downhole tool  200  or the downhole tool  300 . Method  600  may begin at step  602 , which includes running a downhole tool that includes a production unit and a logging tool coupled to a downhole end of the production unit into a wellbore on a production string. For example, the downhole tool  200  or the downhole tool  300  may be run into the wellbore  20  on a downhole conveyance, such as the production conduit or tubing  17 . In alternative aspects, the tool  200  or the tool  300  may be run into the wellbore  20  on a different type of downhole conveyance, such as a wireline or other cable conveyance. In some aspects, the wellbore  20  includes the production casing  35  (and other casings) through which the downhole tool  200  or the downhole tool  300  may be inserted. 
     Method  600  may continue at step  604 , which includes positioning the downhole tool in the wellbore adjacent a subterranean formation. For example, once in the wellbore  20 , the downhole tool  200  or the downhole tool  300  may be positioned at or near a subterranean formation, such as formation  40 , from which a wellbore fluid is produced. In some aspects, the wellbore fluid is a hydrocarbon fluid, such as oil, gas, or a mixed phases of oil and gas. Alternatively, the subterranean formation may produce another fluid, such as brine. In some aspects, as part of step  604  (or just subsequent to step  604 ), a wellbore seal, such as packer  55 , may be set in the wellbore uphole of the positioned downhole tool in order to define a production zone downhole of the wellbore seal. Wellbore fluid downhole of the wellbore seal, therefore, may not pass through the annulus  60  of the wellbore  20  across the seal. 
     Method  600  may continue at step  606 , which includes unspooling a cable from the logging tool in a direction downhole of the downhole tool. For example, once the downhole tool  200  or downhole tool  300  is at the desired position, a logging operation may commence with a logging unit (unit  204  or  304 , respectively) of the downhole tool  200  or  300 . As described, the logging cable may be unspooled from a cable spooler ( 224  or  324 ) through operation of a spooler motor ( 222  or  322 ) that is rotatably coupled to the cable spooler. In some aspects, power to the spooler motor may be received from a spooler motor power cable ( 226  or  326 ) that extends to the logging unit from the terranean surface  12 . Alternatively, power to the spooler motor may be received from a pump power cable  216  that extends to the production unit from the terranean surface  12 . In still other aspects, power to the spooler motor may be received from a power source internal to the downhole tool, such as a battery or other stored electrical energy source. 
     In some aspects, unspooling the logging cable also includes maintaining the logging cable relatively concentric with a radial centerline axis of the wellbore  20 . For example, a weight ( 228  or  328 ) may be placed on an end of the logging cable and exert a force in a downhole direction (due to gravity) to keep the logging cable relatively centered in the wellbore  20 , as well as taut. 
     Method  600  may continue at step  608 , which includes logging at least a portion of the wellbore with the unspooled cable. For example, the logging cable, in some aspects, may include or be a fiber optic logging cable that includes one or more sensors. Such sensors include, for example, pressure, temperature, resistivity, gamma, or sonic to name a few. Logging data from the subterranean formation  40 , the wellbore fluid, or both, may be measured by the one or more sensors. In some aspects, step  608  also includes transmitting such measured data to the terranean surface  12 . For example, the measured logging data may be transmitted to the terranean surface  12  on a dedicated fiber optic cable that extends from the logging unit to the surface  12 , or within the spooler motor power cable (or other power cable) that extends from the downhole tool  200  or  300  to the terranean surface  12 . Alternatively, such measured data may be stored (for example, in a non-transitory computer media) within the downhole tool  200  or  300  and later retrieved once the tool  200  or  300  is run out of the wellbore  20  and brought to the surface  12 . 
     Method  600  may continue at step  610 , which includes, during logging of the wellbore, producing a wellbore fluid from the wellbore through an inlet of the production unit and into the production conduit or tubing. For example, in the case of the downhole tool  200 , the production unit  202  includes a pump assembly (such as an ESP assembly) that includes pump  206  and pump motor  212  (as well as other components as described). The pump motor  212  may operate the pump  206  to circulate the wellbore fluid (for example, production fluid  50 ) through an intake  208  of the production unit  202  and into the production conduit or tubing  17 . Such a scenario may occur, for example, when the subterranean formation  40  does not have sufficient natural drive to produce the wellbore fluid to the terranean surface  12  without artificial lift. In the case of the downhole tool  300 , the production unit  302  includes an intake  308 , through which wellbore fluid may naturally circulate and enter the production conduit or tubing  17  to be produced to the terranean surface  12 . Such a scenario may occur, for example, when the subterranean formation  40  has sufficient natural drive to produce the wellbore fluid to the terranean surface  12  without artificial lift. 
     In some aspects, the steps of method  600  may be performed in a different order without departing from the scope of the present disclosure. For example, step  610  may be performed between steps  604  and  606 . Thus, in some aspects, the production step  610  may begin prior to the logging steps  606 - 608 , and continue during the logging steps  606 - 608 . Alternatively, in some aspects, the logging steps  606 - 608  may be performed absent the production step  610 . In other aspects, the production step  610  may be performed absent the logging steps  606 - 608 . In some aspects, steps  606 - 608  may be performed prior to step  610 , may not be performed during the performance of step  610 , but may be performed again subsequent to the production step  610 . 
     A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.