Patent Publication Number: US-2016237814-A1

Title: Estimation of Formation Properties by Analyzing Response to Pressure Changes in a Wellbore

Description:
FIELD OF THE INVENTION 
     The present disclosure relates generally to systems and methods for determining the properties of a geological formation that surrounds one or more wells by monitoring the response of the formation to changes in pressure in the wells. 
     DESCRIPTION OF RELATED ART 
     Wells are drilled at various depths to access and produce oil, gas, minerals, and other naturally-occurring deposits from subterranean geological formations. The drilling of a well is typically accomplished with a drill bit that is rotated within the well to advance the well by removing topsoil, sand, clay, limestone, calcites, dolomites, or other materials. 
     After drilling, the well is typically completed through a number of additional tasks that may include installing casing through the wellbore, perforating the casing in regions of the formation that are expected to produce hydrocarbons, and by inserting additional tools that may enhance the performance of the well. Such additional tools may assist the extraction of fluids from the wellbore or inject fluids from the surface into the geological formation surrounding the wellbore. 
     In wells that contain heavy oil, an artificial lift system may be deployed to assist the oil to reach the surface. Such an artificial lift system may include an electric submersible pump that augments the flow of fluid from the formation toward the surface of the well. The electric submersible pump may be powered by an electrical power cable that supplies power to the pump from a power source located at the surface of the well. In addition, the electric submersible pump may be controlled by a surface controller that is operable to adjust the rate at which the pump operates. 
     During the operation of a pressurized well that includes an artificial lift system, a well operator may conduct a variety of diagnostic processes to gather information about the well and a geological formation that surrounds the well. In particular, the well operator may gather information that is indicative of the ability of the well to produce hydrocarbons. For example, the well operator may conduct tests that indicate formation properties such as permeability, resistivity to flow, porosity, pressure, and the density of fluids produced by the formation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  illustrates a schematic view of a well in which a system for determining the properties of a formation surrounding a wellbore by monitoring the formation&#39;s response to a change in wellbore pressure is deployed; 
         FIG. 2  depicts a front, detail view of a submersible pump deployed within the wellbore in the system of  FIG. 1 ; 
         FIG. 3  is a schematic view of a power source, submersible pump, sensor, and controller deployed in the well of  FIG. 1 ; 
         FIG. 4  is a graph showing a change in the amount of power delivered to the pump of  FIG. 3  in correlation with a sensor output showing the level of fluid in the well; 
         FIG. 5  is a schematic view of a wellbore pressure regulator operable to change the wellbore pressure in response to input from a controller; 
         FIG. 6  is a graph showing a change in the wellbore pressure in correlation with a sensor output showing the level of fluid in the well; 
         FIG. 7  is a schematic view of a hydrocarbon-producing field having three wells and two potential well sites; 
         FIG. 8  is a set of graphs showing a change in pump rate for one of the three wells of  FIG. 7  in correlation with changes in fluid level of all three of the wells; 
         FIG. 9  is a schematic view of a field having four producing wells and one pressurization well; 
         FIG. 10  is a set of graphs showing how power pulses may be provided to pumps deployed in the pressurizing well and three of the producing wells in correlation with changes in fluid level of the fourth producing well; 
         FIG. 11  is a flowchart showing an illustrative process for determining a formation property in response to varying a wellbore pressure; and 
         FIG. 12  is a flowchart showing an illustrative process for determining formation properties near a plurality of wellbores in response to varying wellbore pressure in the plurality of wellbores. 
     
    
    
     DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS 
     In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof These embodiments are described in sufficient detail to enable those skilled in the art to practice the invention, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the spirit or scope of the invention. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense, and the scope of the illustrative embodiments is defined only by the appended claims. 
     When conducting conventional formation testing, such as drill stem testing, a well operator may have to choose between operating the well to produce hydrocarbons and removing production equipment from the well in order to deploy dedicated testing components that are able to conduct the desired testing but do not facilitate normal operation of the well. In some instances, deployment of dedicated testing equipment may require significant downtime and delay the well&#39;s return to production. 
     The systems, devices, and methods described herein relate to the testing of a geological formation surrounding a wellbore using equipment that can be included in a production string. Including such equipment in the production string may be beneficial because extensive testing can be conducted without extended interruption of well operation, which may prove costly to the well owner. The systems, devices and methods described herein may be deployed in a single well system to gather information about the formation in one or more zones that correspond to different depths in the wellbore. In addition, the systems, devices, and methods described herein may be deployed across a number of wells in a hydrocarbon-producing field to generate data that indicates the extent to which flow or pressure in one well affects the flow and pressure in other wells in the field, and the extent to which multiple wells may be connected through the same geological formation. 
     Referring now to the figures,  FIG. 1  shows an example of a production system  100  that includes diagnostic functionalities for determining the properties of a geological formation  106  surrounding a wellbore  108 . The production system  100  includes a rig  116  atop the surface  132  of a well  101 . Beneath the rig  116 , the wellbore  108  is formed within the geological formation  106 , which is expected to produce hydrocarbons. The wellbore  108  may be formed in the geological formation  106  using a drill string that includes a drill bit to remove material from the geological formation  106 . The wellbore  108  in  FIG. 1  is shown as being near-vertical, but may be formed at any suitable angle to reach a hydrocarbon-rich portion of the geological formation  106 . As such, in an embodiment, the wellbore  108  may follow a vertical, partially vertical, angled, or even a partially horizontal path through the geological formation  106 . 
     Following or during formation of the wellbore  108 , a production tool string  112  may be deployed that includes tools for use in the wellbore  108  to operate and maintain the well  101 . For example, the production tool string  112  may include an artificial lift system to assist fluids from the geological formation to reach the surface  132  of the well  101 . Such an artificial lift system may include an electric submersible pump  102 , sucker rods, a gas lift system, or any other suitable system for generating a pressure differential. The pump  102  receives power from the surface  132  from a power transmission cable  110 , which may also be referred to as an “umbilical cable.” In such systems, a well operator may monitor the condition of the well  101  and components of the production tool string  112  to ensure that the well operates efficiently. For example, the well operator may monitor the power transmission cable  110 , pump, or other components connected thereto to verify that power is being effectively transferred to the pump  102 , to ensure that the pump  102  provides the desired amount of lift in the wellbore  108 , and to ensure that there are no unplanned outages of an operating well that includes such an artificial lift system. 
     A typical electric submersible pump configuration may include on or more staged centrifugal pump sections that are tuned to the production characteristics and wellbore characteristics of a well. In some embodiments, the electric submersible pump may be formed by two or more independent electric submersible pumps coupled together in series for redundancy and augmented flow. In the embodiment of  FIG. 1 , the surface controller  120  provides the functionality of both a power source and a controller relative to the electric submersible pump  102 . In an embodiment, the surface controller  120  may also include a signal generator and a wired or wireless transceiver for communicating with sensors deployed in the wellbore  108 . 
     The electric submersible pump  102  is deployed from the rig  116 , which may be a drilling rig, a completion rig, a workover rig, or another type of rig. The rig  116  includes a derrick  109  and a rig floor  111 . The production tool string  112  extends downward through the rig floor, through a fluid diverter  144  and blowout preventer  142  that provide a fluidly sealed interface between the wellbore  108  and external environment, and into the wellbore  108  and formation  106 . The rig  116  may also include a motorized winch  130  and other equipment for extending the tool string  112  into the wellbore  108 , retrieving the tool string  112  from the wellbore  108 , and positioning the tool string  112  at a selected depth within the wellbore  108 . 
     While the operating environment shown in  FIG. 1  relates to a stationary, land-based rig  116  for raising, lowering and setting the tool string  112 , in alternative embodiments, mobile rigs, wellbore servicing units (such as coiled tubing units, slickline units, or wireline units), and the like may be used to lower the tool string  112 . Further, while the operating environment is generally discussed as relating to a land-based well, the systems and methods described herein may instead be operated in subsea well configurations accessed by a fixed or floating platform. 
     In operation, fluids  146  are extracted from the formation  106  and delivered to the surface  132  via the wellbore  108 . The submersible pump  102  may be used to provide a reduced pressure in the wellbore and pump fluid from the wellbore  108  to the surface  132  through the production tool string  112 . The wellbore  108  may pass through multiple zones within the formation  106 , each of which may be operated at a different pressure. Each such zone may be separated from an adjacent zone by a packer  154  that inflates or expands and forms a fluid seal in the annulus  118  between the wellbore casing  114  and production tool string  112 . Within each zone, a submersible pump  102  may decrease pressure in the annulus  118  to encourage fluids  146  from the formation  106  while increasing pressure in the production tool string  112  which forms a fluid flow path to the surface  132 . As fluid  146  is transported to the surface  132 , the fluid passes through the blowout preventer  142  and a fluid diverter  144  that diverts fluid  146  to a collection tank  140  for subsequent processing and refinement. 
     Once the production tool string  112  is deployed, it may be difficult, expensive, and time consuming to extract the production tool string  112  from the wellbore  108  to conduct further testing of the wellbore  108  and surrounding formation  106 . However, to intelligently continue operations of the well  101 , subsequent development of the well  101 , and subsequent development of a hydrocarbon-producing field that surrounds the well  101 , subsequent testing may be beneficial. To facilitate and mitigate the costs of such testing, a sensor  150 , which may be a contact sensor that contacts fluid  146  for diagnostic purposes, may be affixed to the pump  102  or otherwise coupled to the tool string  112 . Additionally or in the alternative, at the top of a zone, or the top of the wellbore that comprises only one zone, a second sensor  148 , which may be a noncontact sensor, such as an echo-meter, may be deployed to monitor the fluid level  152  of the fluid  146  and the wellbore  108 . 
       FIG. 2  shows a detail view of the submersible pump  102  of  FIG. 1  showing the pump  102  partially submerged in fluid  146  that is being extracted from the formation  106 . Affixed to the pump  102 , the sensor  150  is shown being deployed on the production tool string  112  and in contact with the fluid  146 . The sensor  150  may be operable to determine a number of fluid properties, including the fluid level  152 , fluid density, and wellbore pressure. 
       FIG. 3  shows a schematic view of the system  100  of  FIG. 1  deployed in a well configuration that enables testing of the surrounding formation  106 . The submersible pump  102  is deployed within the formation  106  in the wellbore  108 , and is deployed in conjunction with the sensor  150 . The submersible pump  102  is coupled to a power source  122  and to the controller  120 , which may be a computer or computing system that communicates with the pump  102  and sensor  150 . In an embodiment, the computer includes a memory, a power source, a processer, and a transceiver. The transceiver is operable to communicate with the sensor  150  and any other sensors included within the system  100  in addition to the pump  102  and other devices in the tool string  112 . The memory, which may also be referred to as a computer readable medium, includes instructions to cause the processor to initiate and control the test processes described herein. 
     In the embodiment of  FIG. 3 , the controller  120  is operable to control the pump  102  either directly or via the power source  122  to adjust the pressure differential supplied by the pump  102 , which may also be referred to as the pump rate. The controller  120  is also operable to receive data from the sensor  150  and any other sensors included within the system  100 . 
     To test the properties of the surrounding formation  106 , after operating the pump  102  for a first time period extending from an initial time to a second time, the pump rate may be adjusted to alter the pressure differential supplied by the pump  102 , thereby changing the pressure in the wellbore  108 , or zone of the wellbore  108  subject to test. For example, the pump  102  may be deactivated at the second time and the pressure in the wellbore  108  may increase. Upon the change in wellbore pressure, the fluid level  152  may be monitored by the sensor  150 , which is in contact with the fluid  146 . By monitoring and analyzing the fluid level fluctuations over time when pump  102  is, for example, deactivated, certain properties of the formation may be estimated. For example, the rate of change of the fluid level and the rate of change of the rate of change of the fluid level, which, respectively, may also be referred to as the first derivative and second derivative of the fluid level viewed over time, are indicative of the permeability, porosity, pressure, resistivity to flow, and recoverable reserve of the formation  106 . Collectively, these traits may be referred to as formation properties or properties of the formation  106 . 
     An example equation that demonstrates the relationship between the aforementioned wellbore properties is given by “Application of the Drill-Stem Test to Hydrogeology” by D. A. Hackbarth in Vol 16, No 1 of  Ground Water,  January-February 1978, which states that during a complete cessation of the artificial lift system (i.e., deactivation of the pump), shut-in pressure (P w ), can be calculated as a function of the reservoir pressure (P o ), the flow rate during production (q), the ease of flow through the formation as dictated by the permeability (k), pay thickness (h), and viscosity of the liquid (μ), as expressed in the following equation: 
     
       
         
           
             
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               w 
             
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                 P 
                 o 
               
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                     t 
                   
                 
               
             
           
         
       
     
     where: 
     t=total flowing time, and 
     Δt=time since shut-in started (time since deactivation of the pump or lift system). Further, when pressure is known, this equation can be solved for permeability as follows: 
     
       
         
           
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     It follows that, depending on which wellbore parameters are known, other wellbore properties may also be estimated by applying the principles set forth in the equations above. 
     In an embodiment, production from the pump  102  or other artificial lift source may not be completely ceased. Instead, the rate of production from the artificial lift may merely be altered. As a result, the mathematical relationships between the wellbore properties described above may not be easily derived using a closed form solution. Thus, an iterative solution or numerical method known to one of skill in the art, such as a finite element technique, a finite difference technique, or a sequential partial differential equation, may be applied in lieu of the equations above. Using such techniques, an operator may account for additional variations in wellbore properties, such as skin thickness, reservoir fractures, mixed phases, trapped gasses, and different compressibility. 
     As shown in the graph of  FIG. 4 , as the operator temporarily reduces the power delivered to the pump  102 , the fluid level increases over time with a positive first derivative, a negative second derivative, and a varying third derivative. These rates of change may be monitored and analyzed to determine or estimate properties of the formation  106 . At a third time following the second time, the operator may return the pump  102  to normal operation. In an embodiment, reactivation of the pump  102  prompts a second change in the fluid level  152 , which may be further monitored and analyzed to determine properties of the formation  106 . 
     In the embodiment of  FIG. 5 , a similar test may be conducted by changing the pressure in a wellbore  208  using a pressure regulator  258  in addition to or instead of altering the operation of a submersible pump  102 . The pressure regulator  258  may be a pressure release valve, a pneumatic or fluid pump, gas lift system or any other suitable device. In such an embodiment, a pump  202  may again be deployed within a production tool string  212 , but instead of varying the power level or pump rate of the pump  202 , the pressure in the wellbore is varied using the pressure regulator  258 . 
     As shown in the graph of  FIG. 6 , the operator changes the pressure in the wellbore  108  after a first time period extending from an initial time to a second time. Again, after the change in wellbore pressure, the fluid level  252  increases over time with a positive first derivative, a negative second derivative, and a varying third derivative. At a third time following the second time, the operator may return the wellbore  108  to its original operating pressure. Each change in the fluid level  152  may be further monitored and analyzed to estimate properties of the formation  106 . 
     In an embodiment, the test process described above is deployed across a geographic area that is expected to produce hydrocarbons, which may be referred to as a field. Each such field may include multiple wells. In such an embodiment, the test process is used to estimate the extent to which operation in a well affects operation of another well, formation properties in the portion of the formation that surrounds each well, and the extent to which wells may be interconnected to the same hydrocarbon producing formation. 
     For example,  FIG. 7  is a schematic view of a field  300  overlying a formation  301  and including one or more wells and potential well locations. Here, the field  300  includes a first well  302 , a second well  304 , and a third well  306 , in addition to a first potential well site  308  and a second potential well site  310 . The test processes described above may be performed in each of the wells  302 ,  304 , and  306  to estimate the formation properties in the portion of the formation  301  that surrounds each well, and to provide an estimate of formation properties at locations between the wells  302 ,  304 , and  306 . 
     In accordance with the embodiment of  FIG. 7 , and as shown in the graphs of  FIG. 8 , the test process may be implemented and executed by varying the pump rate or pressure of the wellbore of the wells  302 ,  304 , and  306 . For example, the pump rate  322  may be varied at the second pump  304  to change the pressure of the wellbore of the well  304  for an extended time period. The fluid level  320  of the second well may vary in correspondence to the change in pressure. If the first and third wells  302 ,  306  are fluidly connected to the same formation that surrounds the second well  304 , then fluid level changes may also be observed at the first and third wells  302 ,  306 . 
     As shown in the graphs of  FIG. 8 , for example, the pump rate of the first well  332  and pump rate of the third well  342  are held constant over the test period. Despite the constant pump rates in each of these wells, however, the fluid level of the third well  340  varies in response to the change in pump rate  332  at the second well. Over the same time period, the fluid level at the first well  330  remains constant. Such test results may indicate that the second well  304  and third well  306  share a production region of the same formation  301 , while the first well  302  is isolated from the second well  304  and third well  306 . To the extent the second well  304  and third well  306  share a production region, the wells may be referred to as “coupled.” Based on the locations of the first potential well site  308  and second potential well site  310 , and the results of the test, a geologist or well driller may estimate that the second potential well site  310  is more likely to be a productive location to place a well because it resides in a region that is likely to be coupled to the formation between the second well  304  and the third well  306 . 
     Further, as with the test processes described above, the time delay between seeing the pressure change and the change in fluid level may indicate the degree to which the second well  304  and third well  306  are coupled via the formation  301  and may be used to estimate the permeability, porosity, volume of fluid, and other formation properties of the portion of the formation  301  between the second well  304  and third well  306 . 
     A more complex field pattern is shown in  FIG. 9 , which illustrates a 1×4 field configuration having a positively pressurized well  410  and wellbore  420  for pressurizing a formation  406 , and four producing wells including a first producing well  412  and wellbore  422 , a second producing well  414  and wellbore  424 , a third producing well  416  and wellbore  426 , and a fourth producing well  418  and wellbore  428 . The field  400  overlies a first formation  406  and second formation  408 . As with the test process described above with regard to  FIGS. 7 and 8 , an operator may alter the pressure in, for example, the positive pressure well  410  and wellbore  418  and derive an estimation or determination that producing wells  412 ,  414 , and  416  are coupled via the first formation  406 , and that the fourth producing well  418  is not coupled to the first formation  406  but instead produces fluids from a second formation  408  that is isolated from the first formation  406 . In addition, as shown in the graphs of  FIG. 10 , multiple tests may be run at the same time using the methodology described below. 
     Running multiple tests at the same time, however, may render it difficult or confusing to determine how the application of the test process in each of the wells  410 ,  412 ,  414 ,  416  and  418  affects the other wells  410 ,  412 ,  414 ,  416  and  418 . Such confusion may arise from an operator not being able to determine which well pressure is affecting the other wells if multiple well pressures are changed at the same time. To overcome such confusion, the pump rate may be varied in each well according to a different timescale or over different time intervals or time slots, effectively multiplexing the pressure variations so that multiple wells can be tested at the same time while minimizing confusion as to which, and the extent to which, each well test affects nearby wells. For example, as shown in  FIG. 10 , pressure changes or pump rate changes may be applied for a first time period T 1  at the positively pressurized well  410 , a second time period T 2  at the second producing well  414 , a third time period T 3  at the third producing well  416 , and a fourth time period at the fourth producing well  418 , with each such time period being different. Such varying timescales may be regular and periodic, or randomized but known by an operator or controller so that the effects of the pressure variations that are actively applied to each well will be properly attributed to that well when the effects of such variations are experienced at a test well. 
     In an embodiment, this staggering of the test time periods to effectively vary the pressure in each well during different time slots enables a test operator to discern or disambiguate the pressure-related system responses due to the pressure changes as experienced at the first producing well  412  attributable to each of the wells  410 ,  414 ,  416 , and  418  from which the pressure or pump rate variances are applied. This concept is analogous to time division multiplexing. As indicated above with regard to  FIGS. 7 and 8 , the test results may be used to estimate formation properties between the wells  410 ,  412 ,  414 ,  416 ,  418 , and to identify potential future well sites that are likely to be productive in the case of potential producing wells or enhance productivity of nearby wells in the case of potential positive pressurization wells. The multiple well testing results may enable the operator to estimate the extent of formation coupling or cross-well communication, by examining the cross-correlation between fluid level and pressure measurements versus the pressure variations generated at the other wells. An operator may look at the amplitude and phase of the cross-correlation to conduct such an analysis. In addition, the operator may determine the extent to which wells are connected by applying a transfer function, a statistical regression, a simple correlation, a multiple regression numerical analysis, or any other suitable method, as described above. 
       FIG. 11  shows a representative process  500  for applying the testing process described above in a single well implementation. The process  500  involves deploying one or more pumps, or other pressurization devices, to one or more zones in a wellbore  502 . The deployment of the pumps, for the purposes of testing, may be only to zones that are to be tested. Each such zone may correspond to a portion of the formation surrounding the formation so that an operator may determine the properties of the formation at each zone. The process  500  also includes operating the pump or pumps at a first pump rate for a first time period  504 , operating the pump or pumps at a second pump rate for a second time period  506 , and monitoring the system response, or rate of change of the fluid level, and analyzing the system response of the well to estimate formation properties  508 . By operating a first pump in a first zone of a wellbore, a second pump in a second zone of the wellbore, a third pump in a third zone of the wellbore, and so on, the operator may determine the extent to which each zone is coupled via the surrounding formation and the properties of the wellbore surrounding each zone. This concept may also be applied to identify additional zones for production by identifying productive zones and extrapolating that additional zones between the productive zones may also be productive, applying a similar methodology to the process for identifying potentially productive well sites described with regard to  FIG. 7 . 
     Similarly,  FIG. 12  shows a representative process  600  for applying the testing process described above in a multiple well implementation. The process  600  involves deploying one or more pumps or other pressurization devices to a plurality of wells  602 . The process also involves operating the first, second, third, . . . , and nth wells at a first pump rate for a first time period  604  that corresponds to a first set of distinct and different time slots, and then operating the first, second, third, . . . , and nth wells at a second pump rate for a second time period  606  that corresponds to a second set of distinct and different time slots, and monitoring and analyzing the system responses of the wells. In addition, the process  600  involves determining the system responses in the first, second, third, . . . , and nth wells to the changes in the pump rates in the other wells to estimate the properties of the formations surrounding each well, and the extent to which each well is cross-connected. 
     The illustrative systems, methods, and devices described herein may also be described by the following examples: 
     EXAMPLE 1 
     A method for estimating the properties of a geological formation near a wellbore, the method comprising:
         operating an artificial lift system within a wellbore at a first rate for a first time period;   operating the artificial lift system at a second rate for a second time period;   monitoring the change of a fluid level in the wellbore over the second time period to estimate a property of the geological formation.       

     EXAMPLE 2 
     The method of example 1, wherein monitoring the change of a fluid level in the wellbore over the second time period to estimate a property of the wellbore comprises estimating the porosity of the geological formation. 
     EXAMPLE 3 
     The method of example 1, wherein monitoring the change of a fluid level in the wellbore over the second time period to estimate a property of the wellbore comprises estimating the pressure of a fluid flowing through the geological formation. 
     EXAMPLE 4 
     The method of example 1, wherein monitoring the change of a fluid level in the wellbore over the second time period to estimate a property of the wellbore comprises estimating the resistivity to flow of the geological formation. 
     EXAMPLE 5 
     The method of example 1, wherein monitoring the change of a fluid level in the wellbore over the second time period to estimate a property of the wellbore comprises estimating a property selected from the group consisting of formation pressure, permeability, and recoverable reserve. 
     EXAMPLE 6 
     The method of example 1, further comprising operating the artificial lift system at a third rate during a third time period following the second time period and monitoring the change of a fluid level in the wellbore to estimate a second property of the geological formation. 
     EXAMPLE 7 
     The method of example 1 wherein monitoring the change in fluid level is comprises measuring the fluid height or the measuring pressure of the fluid head. 
     EXAMPLE 8 
     A method for estimating the properties of a geological formation near a wellbore, the method comprising:
         changing the pressure in the wellbore from a first pressure to a second pressure at a first time, the second pressure being greater than the first pressure ;   monitoring a change of a fluid level in the wellbore from the first time to estimate a property of the formation.       

     EXAMPLE 9 
     The method of example 8, wherein monitoring the change of a fluid level comprises measuring the level of fluid in the wellbore using a contact sensor. 
     EXAMPLE 10 
     The method of example 8, wherein monitoring the change of a fluid level comprises measuring the level of fluid in the wellbore using a non-contact sensor. 
     EXAMPLE 11 
     The method of example 8 or 9, wherein monitoring a change of a fluid level in the wellbore from the first time to estimate a property of the formation comprises estimating a property selected from the group consisting of the density of a fluid from the formation, resistivity to flow, formation pressure, permeability, porosity and recoverable reserve. 
     EXAMPLE 12 
     The method of example 8 or 9, further comprising operating an artificial lift system at a third rate from a third time to a fourth time, and monitoring the system response from the third time to determine a second property of the wellbore. 
     EXAMPLE 13 
     The method of example 8 or 9, further comprising comparing an estimated property of the formation estimated at the second time to the estimated property of the formation estimated at a third time to verify the estimation. 
     EXAMPLE 14 
     A method for estimating the properties of a geological formation near a first wellbore, the method comprising:
         operating an artificial lift system within a second wellbore for a first time period at a first pressure;   altering the pressure of the second wellbore for a second time period;   monitoring and analyzing a change of a fluid level in the first wellbore during the second time period to estimate a property of the formation.       

     EXAMPLE 15 
     The method of example 14, wherein altering the pressure of the second wellbore for a second time period comprises increasing the static pressure in the second wellbore using a pressure regulator. 
     EXAMPLE 16 
     The method of example 14, wherein altering the pressure of the second wellbore for a second time period comprises increasing the pump rate of a submersible pump in the second wellbore. 
     EXAMPLE 17 
     The method of example 14, wherein monitoring and analyzing a change of the fluid level in the first wellbore during the second time period to estimate a property of the formation comprises estimating a property selected from the group consisting of the porosity of the formation, the density of a fluid from the formation, the resistivity to flow of the formation, formation permeability, and the recoverable reserve of the formation. 
     EXAMPLE 18 
     The method of example 14, wherein monitoring and analyzing a change of the fluid level in the first wellbore during the second time period to estimate a property of the formation comprises estimating the extent to the first wellbore and second wellbore are fluidly coupled to the same geological formation. 
     EXAMPLE 19 
     The method of example 14, further comprising monitoring and analyzing a second change of fluid in a third wellbore during the second time period to determine a property of the formation. 
     EXAMPLE 20 
     The method of example 19, further comprising estimating the extent to which the first wellbore, second wellbore, and third wellbore are coupled through the formation. 
     EXAMPLE 21 
     The method of example 19, further comprising:
         varying the pressure in third wellbore from a third period to a fourth time period;   varying the pressure in a fourth wellbore from a fifth time period to a sixth time period analyzing the second change of the fluid level in the third wellbore over the second time period in response to the change in pressure in the first wellbore;   analyzing the third change of the fluid level in the second wellbore over the third time period and fourth time period;   analyzing a fourth change of a fluid level in the fourth wellbore over the second time period and third time period; and   estimating the extent to which the first wellbore, second wellbore, third wellbore, and fourth wellbore are coupled through the formation based on analyzing the change of fluid level in the first wellbore, the second change of fluid level in the third wellbore, the third change of the fluid level in the second wellbore, and the fourth change of the fluid level in the fourth wellbore.       

     EXAMPLE 22 
     A system for mapping the properties of a geological formation, the system comprising:
         a pressure adjustment device for deployment in a first wellbore;   a sensor for monitoring the fluid level in a second wellbore;   a control system that is operable to communicate with the pressure adjustment device and the sensor, the controller including a memory having instructions for:
           varying the pressure in the first wellbore from a first time period to a second time period;   analyzing the change of a fluid level in the second wellbore over the second time period in response to the change in pressure in the first wellbore; and   estimating a property of a geological formation between the first wellbore and second wellbore based on said analyzing.   
               

     EXAMPLE 23 
     The system of example 22, wherein the sensor is a contact sensor. 
     EXAMPLE 24 
     The system of example 23, wherein the contact sensor is a hydrophone. 
     EXAMPLE 25 
     The system of example 22, wherein the sensor is a non-contact sensor. 
     EXAMPLE 26 
     The system of example 25, wherein the non-contact sensor is an echo-meter. 
     EXAMPLE 27 
     The system of example 22, wherein the pressure adjustment device comprises a submersible pump and wherein varying the pressure comprises changing the pump rate of the submersible pump. 
     EXAMPLE 28 
     The system of example 27, wherein changing the pump rate of the submersible pump comprises stopping the pump. 
     EXAMPLE 29 
     The system of example 22 or 23, wherein estimating a property of the geological formation comprises estimating a property selected from the group consisting of the porosity of the formation, the density of a fluid extracted from the formation, the resistivity to flow of the formation, the formation pressure, the formation permeability, and the formation&#39;s recoverable reserve. 
     EXAMPLE 30 
     The system of example 22 or 23, wherein estimating a property of the geological formation comprises determining the extent to which the first wellbore and second wellbore are fluidly coupled to the same geological formation. 
     EXAMPLE 31 
     The system of example 22 or 23 further comprising a second sensor deployable in a third wellbore and operable to monitor the fluid level in the third wellbore, and a second pressure adjustment device operable to adjust the pressure in the third wellbore, wherein the memory further comprises instructions for:
         varying the pressure in third wellbore from a third period to a fourth time period;   analyzing the change of a fluid level in the third wellbore over the second time period in response to the change in pressure in the first wellbore;   analyzing the change of a fluid level in the second wellbore over the fourth time period in response to the change in pressure in the third wellbore; and   estimating a property of a geological formation between the first wellbore and third wellbore and between the second wellbore and third wellbore based on said analyzing.       

     EXAMPLE 32 
     The system of example 31, wherein the memory further comprises instructions for selecting a location for a fourth wellbore based on the estimated property of the formation between the first well bore and third wellbore and between the second wellbore and third wellbore. 
     It should be apparent from the foregoing that an invention having significant advantages has been provided. While the invention is shown in only a few of its forms, it is not limited to only these embodiments but is susceptible to various changes and modifications without departing from the spirit thereof.