WO2015053784A1

WO2015053784A1 - Estimation of formation properties by analyzing response to pressure changes in a wellbore

Info

Publication number: WO2015053784A1
Application number: PCT/US2013/064582
Authority: WO
Inventors: Michael Linley Fripp; Jason Dykstra; Fanping Bu
Original assignee: Halliburton Energy Services, Inc.
Priority date: 2013-10-11
Filing date: 2013-10-11
Publication date: 2015-04-16
Also published as: US20160237814A1

Abstract

A system and method for estimating properties of a hydrocarbon-producing formation includes varying the pressure in one or more first wellbores and analyzing the effect of the pressure variations in one or more second wellbores. The analysis may be accomplished by applying the pressure variations at varying timescales to enable the testing of multiple paths through the formation at the same time. The analysis may be used to estimate properties of the formation and a field that includes multiple well sites or potential well sites. The analysis may be used to enhance the operation of one or more of the wells and to identify potential future well sites.

Description

ESTIMATION OF FORMATION PROPERTIES BY ANALYZING RESPONSE TO PRESSURE CHANGES IN A WELLBORE

1. 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.

2. 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'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'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 1 16 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 1 16, 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 1 11. The production tool string 1 12 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 1 16 may also include a motorized winch 130 and other equipment for extending the tool string 112 into the wellbore 108, retrieving the tool string 1 12 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 1 16 for raising, lowering and setting the tool string 1 12, 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 1 12. 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 1 18 between the wellbore casing 1 14 and production tool string 112. Within each zone, a submersible pump 102 may decrease pressure in the annulus 1 18 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 1 12 is deployed, it may be difficult, expensive, and time consuming to extract the production tool string 1 12 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 1 12 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 1 12. 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, Jan-Feb 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 (P₀), 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:

where:

t = total flowing time, and

At = time since shut-in started (time since deactivation of the pump or lift system). Further, when ressure is known, this equation can be solved for permeability as follows:

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 x 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 Tl at the positively pressurized well 410, a second time period T2 at the second producing well 414, a third time period T3 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. 1 1 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'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:

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.

Claims

CLAIMS We claim:

Claim 1. A method for estimating the properties of a geological formation near a wellbore, the method comprising:

operating an artificial lift system at a first rate for a first time period to apply a reduced pressure to the wellbore;

operating the artificial lift system at a second rate for a second time period;

Claim 2. The method of claim 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.

Claim 3. The method of claim 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.

Claim 4. The method of claim 1 wherein monitoring the change in fluid level is comprises measuring the fluid height or the measuring pressure of the fluid in the wellbore.

Claim 5. The method of claim 1, wherein monitoring the change of a fluid level comprises measuring the level of fluid in the wellbore using a contact sensor.

Claim 6. The method of claim 1, wherein monitoring the change of a fluid level comprises measuring the level of fluid in the wellbore using a non-contact sensor.

Claim 7. The method of claim 1, further comprising operating an artificial lift system at a third rate from a third time to a fourth time, and monitoring the change in fluid level from the third time to the fourth time to determine a second property of the wellbore.

Claim 8. The method of claim 1, 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.

Claim 9. A method for estimating the properties of a geological formation near a first wellbore, the method comprising:

operating an artificial lift system in a second wellbore for a first time period at a first pressure;

altering the pressure of the second wellbore for a second time period;

Claim 10. The method of claim 9, 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.

Claim 11. The method of claim 9, 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.

Claim 12. The method of claim 9, 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.

Claim 13. The method of claim 11, 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.

Claim 14. The method of claim 11, 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.

Claim 15. The method of claim 14, further comprising estimating the extent to which the first wellbore, second wellbore, and third wellbore are coupled through the formation.

Claim 16. A system for mapping the properties of a geological formation, the system

comprising:

a first wellbore having a pressure adjustment device deployable in a first wellbore; a sensor for monitoring the fluid level in a second wellbore;

a controller that is operable to communicate with the pressure adjustment device and the sensor, the controller including a memory having instructions for:

Claim 17. The system of claim 16, wherein the pressure adjustment device comprises a submersible pump and wherein varying the pressure comprises changing the pump rate of the submersible pump.

Claim 18. The system of claim 17, wherein changing the pump rate of the submersible pump comprises stopping the pump.

Claim 19. The system of claim 16, 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's recoverable reserve.

Claim 20. The system of claim 16 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 for varying the pressure in the third wellbore, wherein the memory further comprises instructions for:

varying the pressure in third wellbore using the second pressure adjustment device from a third period to a fourth time period;