WO2013032445A1

WO2013032445A1 - Methods and systems for evaluating environmental impact of drilling operations

Info

Publication number: WO2013032445A1
Application number: PCT/US2011/049710
Authority: WO
Inventors: Loyd Eddie EAST, Jr.; Daniel GUALTIERI
Original assignee: Halliburton Energy Services, Inc.
Priority date: 2011-08-30
Filing date: 2011-08-30
Publication date: 2013-03-07

Abstract

A method of monitoring subterranean operations is disclosed. A first well bore (165) is drilled in a subterranean formation and a fluid is directed into the first well bore. The fluid comprises a tracer (302). At least one sensor (310) is positioned in a second well bore (304) located proximate to the first well bore and the tracer is detectable by the at least one sensor. The presence of the tracer in the second well bore is then detected using the at least one sensor.

Description

METHODS AND SYSTEMS FOR EVALUATING ENVIRONMENTAL IMPACT OF

DRILLING OPERATIONS

Background

To produce hydrocarbons (e.g., oil, gas, etc.) from a subterranean formation, well bores may be drilled that penetrate hydrocarbon-containing portions of the subterranean formation. The portion of the subterranean formation from which hydrocarbons may be produced is commonly referred to as a "production zone." In some instances, a subterranean formation penetrated by the well bore may have multiple production zones at various locations along the well bore.

Hydrocarbons such as oil and gas are commonly used in a number of applications and industries. Subterranean operations are performed throughout the world to meet the increasing demand for hydrocarbons. However, subterranean operations may have an adverse impact on the environment, necessitating a balanced approach that minimizes the impact on the environment while maintaining the efficiency of subterranean operations.

One of the steps in performing subterranean operations involves drilling a well bore in a desired hydrocarbon bearing formation. During drilling operations, a drill string including a drill bit may be directed downhole. The drill bit may be rotated and penetrates the formation forming a well bore therein. In some applications, as the well bore extends through the formation, a casing may be disposed therein. The drilling operations continue until the well bore reaches a desired depth.

However, hydrocarbon bearing formations are often located adjacent to or otherwise near sources of ground water. Accordingly, there is a risk that when drilling a well bore or during subsequent subterranean operations, materials such as, for example, hydrocarbon gasses and benzene may leak from the well bore and contaminate the sources of ground water nearby. It is therefore desirable to develop methods and systems to monitor a well bore and detect well bore leaks.

Brief Description of the Drawings Figure 1 shows an illustrative system for performing drilling operations; Figure 2 depicts a simplified illustration of drilling operations performed utilizing the system of Figure 1 ;

Figure 3 depicts a simplified illustration of drilling operations in accordance with an exemplary embodiment of the present invention; and Figure 4 depicts a simplified illustration of drilling operations in accordance with another exemplary embodiment of the present invention.

While embodiments of this disclosure have been depicted and described and are defined by reference to exemplary embodiments of the disclosure, such references do not imply a limitation on the disclosure, and no such limitation is to be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those skilled in the pertinent art and having the benefit of this disclosure. The depicted and described embodiments of this disclosure are examples only, and not exhaustive of the scope of the disclosure.

Detailed Description

For purposes of this disclosure, an information handling system may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system may also include one or more buses operable to transmit communications between the various hardware components. For the purposes of this disclosure, computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Computer-readable media may include, for example, without limitation, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such as wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.

Illustrative embodiments of the present invention are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the specific implementation goals, which may vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.

To facilitate a better understanding of the present invention, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear well bores in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells. Embodiments may be implemented using a tool that is made suitable for testing, retrieval and sampling along sections of the formation. Embodiments may be implemented with tools that, for example, may be conveyed through a flow passage in tubular string or using a wireline, slickline, coiled tubing, downhole robot or the like. Devices and methods in accordance with certain embodiments may be used in one or more of wireline, measurement- while-drilling (MWD) and logging-while-drilling (LWD) operations. "Measurement-while-drilling" is the term generally used for measuring conditions downhole concerning the movement and location of the drilling assembly while the drilling continues. "Logging-while-drilling" is the term generally used for similar techniques that concentrate more on formation parameter measurement.

The terms "couple" or "couples," as used herein are intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical connection via other devices and connections. The term "upstream" as used herein means along a flow path towards the source of the flow, and the term "downstream" as used herein means along a flow path away from the source of the flow. The term "uphole" as used herein means along the drillstring or the hole from the distal end towards the surface, and "downhole" as used herein means along the drillstring or the hole from the surface towards the distal end.

It will be understood that the term "oil well drilling equipment" or "oil well drilling system" is not intended to limit the use of the equipment and processes described with those terms to drilling an oil well. The terms also encompass drilling natural gas wells or hydrocarbon wells in general. Further, such wells can be used for production, monitoring, or injection in relation to the recovery of hydrocarbons or other materials from the subsurface.

The present application relates generally to well drilling and completion operations and, more particularly, to methods and systems for monitoring and evaluating the environmental impact of drilling operations. Although the present application is discussed in the context of oil well drilling equipment for illustrative purposes, it may be applicable to drilling operations in other applications.

When performing subterranean operations, a well bore is typically drilled in a subterranean formation. As shown in Fig. 1, oil well drilling equipment 100 (simplified for ease of understanding) may include a derrick 105, derrick floor 110, draw works 115 (schematically represented by the drilling line and the traveling block), hook 120, swivel 125, kelly joint 130, rotary table 135, drillpipe 140, one or more drill collars 145, one or more MWD/LWD tools 150, one or more subs 155, and drill bit 160. Drilling fluid is injected by a mud pump 190 into the swivel 125 by a drilling fluid supply line 195, which may include a standpipe 196 and kelly hose 197. The drilling fluid travels through the kelly joint 130, drillpipe 140, drill collars 145, and subs 155, and exits through jets or nozzles in the drill bit 160. The drilling fluid then flows up the annulus between the drillpipe 140 and the wall of the borehole 165. One or more portions of borehole 165 may comprise open hole and one or more portions of borehole 165 may be cased. The drillpipe 140 may be comprised of multiple drillpipe joints. The drillpipe 140 may be of a single nominal diameter and weight (i.e., pounds per foot) or may comprise intervals of joints of two or more different nominal diameters and weights. For example, an interval of heavy-weight drillpipe joints may be used above an interval of lesser weight drillpipe joints for horizontal drilling or other applications. The drillpipe 140 may optionally include one or more subs 155 distributed among the drillpipe joints. If one or more subs 155 are included, one or more of the subs 155 may include sensing equipment (e.g., sensors), communications equipment, data- processing equipment, or other equipment. The drillpipe joints may be of any suitable dimensions (e.g., 30 foot length). A drilling fluid return line 170 returns drilling fluid from the borehole 165 and circulates it to a drilling fluid pit (not shown) and then the drilling fluid is ultimately recirculated via the mud pump 190 back to the drilling fluid supply line 195. The combination of the drill collar 145, Measurement While Drilling ("MWD")/Logging While Drilling ("LWD") tools 150, and drill bit 160 is known as a bottomhole assembly (or "BHA"). The BHA may further include a bit sub, a mud motor (discussed below), stabilizers, jarring devices and crossovers for various threadforms. The mud motor operates as a rotating device used to rotate the drill bit 160. The different components of the BHA may be coupled in a manner known to those of ordinary skill in the art, such as, for example, by joints. The combination of the BHA, the drillpipe 140, and any included subs 155, is known as the drillstring. In rotary drilling the rotary table 135 may rotate the drillstring, or alternatively the drillstring may be rotated via a top drive assembly.

One or more force sensors 175 may be distributed along the drillpipe, with the distribution depending on the needs of the system. In general, the force sensors 175 may include one or more sensor devices to produce an output signal responsive to a physical force, strain or stress in a material. The sensor devices may comprise strain gauge devices, semiconductor devices, photonic devices, quartz crystal devices, or other devices to convert a physical force, strain, or stress on or in a material into an electrical or photonic signal. In certain embodiments, the force measurements may be directly obtained from the output of the one or more sensor devices in the force sensors 175. In other embodiments, force measurements may be obtained based on the output of the one or more sensor devices in conjunction with other data. For example, the measured force may be determined based on material properties or dimensions, additional sensor data (e.g., one or more temperature or pressure sensors), analysis, or calibration.

One or more force sensors 175 may measure one or more force components, such as axial tension or compression, or torque, along the drillpipe. One or more force sensors 175 may be used to measure one or more force components reacted to by or consumed by the borehole, such as borehole-drag or borehole-torque, along the drillpipe. One or more force sensors 175 may be used to measure one or more other force components such as pressure-induced forces, bending forces, or other forces. One or more force sensors 175 may be used to measure combinations of forces or force components. In certain implementations, the drillstring may incorporate one or more sensors to measure parameters other than force, such as temperature, pressure, or acceleration.

In one example implementation, one or more force sensors 175 are located on or within the drillpipe 140. Other force sensors 175 may be on or within one or more drill collars 145 or the one or more MWD/LWD tools 150. Still other force sensors 175 may be in built into, or otherwise coupled to, the bit 160. Still other force sensors 175 may be disposed on or within one or more subs 155. One or more force sensors 175 may provide one or more force or torque components experienced by the drillstring at surface. In one example implementation, one or more force sensors 175 may be incorporated into the draw works 1 15, hook 120, swivel 125, or otherwise employed at surface to measure the one or more force or torque components experienced by the drillstring at the surface.

The one or more force sensors 175 may be coupled to portions of the drillstring by adhesion or bonding. This adhesion or bonding may be accomplished using bonding agents such as epoxy or fasteners. The one or more force sensors 175 may experience a force, strain, or stress field related to the force, strain, or stress field experienced proximately by the drillstring component that is coupled with the force sensor 175.

Other force sensors 175 may be coupled to experience all, or a portion of, the force, strain, or stress field experienced by the drillstring component coupled proximate to the force sensor 175. Force sensors 175 coupled in this manner may, instead, experience other ambient conditions, such as one or more of temperature or pressure. These force sensors 175 may be used for signal conditioning, compensation, or calibration.

The force sensors 175 may be coupled to one or more of: interior surfaces of drillstring components (e.g., bores), exterior surfaces of drillstring components (e.g., outer diameter), recesses between an inner and outer surface of drillstring components. The force sensors 175 may be coupled to one or more faces or other structures that are orthogonal to the axes of the diameters of drillstring components. The force sensors 175 may be coupled to drillstring components in one or more directions or orientations relative to the directions or orientations of particular force components or combinations of force components to be measured.

In certain implementations, force sensors 175 may be coupled in sets to drillstring components. In other implementations, force sensors 175 may comprise sets of sensor devices. When sets of force sensors 175 or sets of sensor devices are employed, the elements of the sets may be coupled in the same, or different ways. For example, the elements in a set of force sensors 175 or sensor devices may have different directions or orientations relative to each other. In a set of force sensors 175 or a set of sensor devices, one or more elements of the set may be bonded to experience a strain field of interest and one or more other elements of the set (i.e., "dummies") may be bonded to not experience the same strain field. The dummies may, however, still experience one or more ambient conditions. Elements in a set of force sensors 175 or sensor devices may be symmetrically coupled to a drillstring component. For example three, four, or more elements of a set of sensor devices or a set of force sensors 175 may be spaced substantially equally around the circumference of a drillstring component. Sets of force sensor sl75 or sensor devices may be used to: measure multiple force (e.g., directional) components, separate multiple force components, remove one or more force components from a measurement, or compensate for factors such as pressure or temperature. Certain example force sensors 175 may include sensor devices that are primarily unidirectional. Force sensors 175 may employ commercially available sensor device sets, such as bridges or rosettes. Figure 2 depicts a simplified illustration of drilling operations performed utilizing the system of Figure 1. Specifically, a drilling fluid may be pumped down hole through the drillpipe 140 and returned to the surface through the annulus formed between the drillpipe 140 and the wall of the borehole 165 in the well bore 320. In an exemplary embodiment, casing (not shown) may be inserted into the borehole and the annulus may be formed between the drillpipe 140 and the casing. A drilling fluid or "mud" is a specially designed fluid that is circulated in a well bore or borehole as the well bore is being drilled in a subterranean formation to facilitate the drilling operation. The various functions of a drilling fluid include, but are not limited to, removing drill cuttings from the well bore, cooling and lubricating the drill bit, aiding in support of the drill pipe and drill bit, and providing a hydrostatic head to maintain the integrity of the well bore walls and prevent well blowouts. Specific drilling fluid systems are selected to optimize a drilling operation in accordance with the characteristics of a particular geological formation. During subterranean operations, opening or cracks may be present in the wall of the borehole 165 or the casing which may extend into the formation. Such cracks facilitate the movement of materials, such as, for example, the drilling fluid, through the geological formation and may release these materials into an adjacent source or stream of ground water.

Figure 3 depicts a simplified illustration of drilling operations in accordance with an exemplary embodiment of the present invention. As shown in Figure 3, a tracer 302 may be mixed with the drilling fluid as the drilling fluid is pumped downhole or it may be pre -mixed with the drilling fluid before the mixture is pumped downhole. The tracer 302 may be comprised of any one, or a combination of suitable materials. In one exemplary embodiment, the tracer 302 may be a material that is soluble in the drilling fluid, is noncarconigenic, has a low concentration in nature and/or is easily detectable. Additionally, in one exemplary embodiment, the tracer 302 may have a long half life so that it is not easily diluted. In one embodiment, the tracer 302 may include Krypton which may be detectable at concentrations as low as 10 parts per billion. As would be appreciated by those of ordinary skill in the art, with the benefit of this disclosure, any other suitable materials may be used as the tracer 302, such as, for example, methyl, ethyl, and propyl esters of formic or acetic acid. Accordingly, in the event of a leak from the well bore through the wall of the borehole 165 or through the casing (not shown), the tracer 302 will flow as shown by arrows 306 out of the well bore along with the drilling fluid and/or any other contaminants through opening in the formation 308.

In one embodiment, a well such as a water well 304 may be located proximate to the well bore 320. Although a water well 304 is depicted for illustrative purposes, the methods and systems disclosed herein may be used in conjunction with a water reservoir or with any other mineral resources where it is desirable to detect contamination from an adjacent well bore. One or more sensors 310 may be positioned at desired locations along the water well 304. For instance one or more sensors may be located downhole and/or at or near the surface of the water well 304. In one embodiment, a plurality of sensors may be distributed at different positions along the water well 304. In one exemplary embodiment, one or more sensors 310 may be spectrometers and/or flame ionizing detectors that can detect the tracer 302. As the water stream 312 flows through the water well 304, the sensors 310 may analyze the water for tracer 302. Accordingly, the water well 304 may be monitored and any contamination from the well bore 320 may be immediately detected by identifying the presence of the tracer 302 in the water stream 312 using the sensors 310.

In one exemplary embodiment, the information from the sensors 310 may be directed to an information handling system (not shown) where it may be stored in computer-readable media and/or displayed in real-time. As would be appreciated by those of ordinary skill in the art, with the benefit of this disclosure, the sensors 310 may be communicatively coupled to the information handling system through a wired or wireless communication system. The use of such systems is well known to those of ordinary skill in the art and will therefore not be discussed in detail herein. In one exemplary embodiment, the sensors 310 may notify an operator once the amount of tracer 302 detected exceeds a predetermined threshold value. This notification may take the form of one or more of a transmitted message to the operator at a remote location through the information handling system, generation of a siren and/or a warning light. Figure 4 depicts a system in accordance with another exemplary embodiment of the present invention, where the methods and systems disclosed herein may be utilized to determine which of a plurality of hydrocarbon well bores near a source of ground water is causing contamination of the water source. In the exemplary embodiment of Figure 4, a second hydrocarbon well bore 404 is provided adjacent the water well 304. In accordance with an embodiment of the present invention, a different tracer 402 may be added to the drilling fluid utilized in the second hydrocarbon well bore 404. Accordingly, as the drilling fluid is pumped down through the drill pipe 440 and returned through the annulus between the drillpipe 440 and the wall of the borehole 465, any leakage of contaminants from the second hydrocarbon well bore 404 will also carry the second tracer 404. Accordingly, the sensors 310 in the water well 304 may distinguish between the tracers 302, 402 and identify which of the two well bores 320, 404 adjacent to the water well 304 is causing the contamination of the water source.

Although two well bores are depicted in Figure 4 for illustrative purposes, as would be apparent to those of ordinary skill in the art, with the benefit of this disclosure, a plurality of different tracers may be injected into a plurality of hydrocarbon wells and the detection of a particular tracer by the sensors 310 may be used to identify the particular hydrocarbon well that is causing the contamination of the water well 304 and the operator may be notified accordingly.

In another exemplary embodiment, the same tracer may be used to identify which of a plurality of adjacent wells is contaminating the water well 304. In this embodiment, the tracer 302 may be injected one at a time into the different adjacent hydrocarbon wells (e.g., 320, 404). The injection of the tracer 302 into the different wells may be staggered to permit the tracer 302 to be recirculated out of each hydrocarbon well before it is injected into the next hydrocarbon well. Once the injection of the tracer 302 into a particular hydrocarbon well triggers the sensors 310, that hydrocarbon well may be identified as the leaking well and the operator may be notified accordingly. In one exemplary embodiment, the methods and systems disclosed herein may be utilized to identify the location of the crack(s) along the well bore wall (and/or the casing) through which the contaminants are leaking. In this embodiment, sensors 310 may be located at different locations along the water well 304 as shown in Figure 3. With the sensors located at different depths along the water well 304, the sensors 310 that are located downhole from the location of the leak may not detect the tracer 302 while the sensors 310 that are located uphole from the location of the leak may detect it, as the water flow 312 moves the tracer 302 up through the water well 304 once the tracer 302 and the contaminants pass through the opening 308 in the formation. An analysis of which sensors detect the tracer and which do not may be used to approximate the depth at which the leak has occurred. In another exemplary embodiment with multiple sensors 310 in the water well 304, once it is determined which of the plurality of sensors 310 was first to detect the tracer, the depth at which the leak has occurred may be approximated. In one exemplary embodiment, once the data from the sensor 310 is transmitted to the information handling system (not shown), the information handling system may process the data received in accordance with the methods disclosed herein to approximate the location of the leak along the wall of the borehole 165 or the casing and may notify the operator accordingly.

The methods and systems disclosed herein simplify monitoring of the environmental impact of a hydrocarbon well and permit an operator to efficiently respond to potential failures in the integrity of the well bore.

The present invention is therefore well-adapted to carry out the objects and attain the ends mentioned, as well as those that are inherent therein. While the invention has been depicted, described and is defined by references to examples of the invention, such a reference does not imply a limitation on the invention, and no such limitation is to be inferred. The invention is capable of considerable modification, alteration and equivalents in form and function, as will occur to those ordinarily skilled in the art having the benefit of this disclosure. The depicted and described examples are not exhaustive of the invention. Consequently, the invention is intended to be limited only by the spirit and scope of the appended claims, giving full cognizance to equivalents in all respects.

Claims

CLAIMS What is claimed is:

1. A method of monitoring subterranean operations comprising:

drilling a first well bore in a subterranean formation;

directing a fluid into the first well bore;

wherein the fluid comprises a tracer;

positioning at least one sensor in a second well bore located proximate to the first well bore;

wherein the tracer is detectable by the at least one sensor; and

detecting presence of the tracer in the second well bore using the at least one sensor.

2. The method of claim 1 , wherein the first well bore is a hydrocarbon well bore.

3. The method of claim 1, wherein the fluid is a drilling fluid.

4. The method of claim 1, wherein the tracer at least one of is soluble in the fluid, is noncarconigenic, and is easily detectable.

5. The method of claim 1, wherein the tracer comprises at least one of Krypton, methyl, ethyl, and propyl esters.

6. The method of claim 1, wherein the at least one sensor is selected from a group consisting of a spectrometer and a flame ionizing detector.

7. The method of claim 1, wherein the at least one sensor is communicatively coupled to an information handling system.

8. The method of claim 1, further comprising notifying an operator when presence of the tracer in the second well bore is detected by the at least one sensor.

9. The method of claim 1 , wherein the second well bore is a water well.

10. The method of claim 1, wherein positioning at least one sensor in the second well bore comprises positioning a plurality of sensors along the second well bore.

11. The method of claim 10, wherein the fluid flows from the first well bore to the second well bore through one or more cracks along a wall of the first well bore, further comprising using data from the plurality of sensors along the second well bore to approximate location of the one or more cracks along the wall of the first well bore.

12. A method of identifying a leaking well comprising:

directing a first fluid into a first well bore in a subterranean formation;

wherein the first fluid comprises a first tracer;

directing a second fluid into a second well bore in the subterranean formation; wherein the second fluid comprises a second tracer;

positioning at least one sensor in a third well bore located proximate to the first well bore and the second well bore;

wherein the first tracer and the second tracer are detectable by the at least one sensor;

detecting presence of at least one of the first tracer and the second tracer in the third well bore using the at least one sensor; and

determining which of the first well bore and the second well bore is contaminating the third well bore.

13. The method of claim 12, wherein at least one of the first well bore and the second well bore is a hydrocarbon well bore.

14. The method of claim 12, wherein the third well bore is a water well.

15. The method of claim 12, wherein at least one of the first tracer and the second tracer at least one of is soluble in the fluid, is noncarconigenic, and is easily detectable.

16. The method of claim 12, wherein the at least one sensor is communicatively coupled to an information handling system.

17. The method of claim 12, further comprising notifying an operator when the presence of at least one of the first tracer and the second tracer in the third well bore is detected by the at least one sensor.

18. A method of identifying a leaking well comprising:

directing a first fluid into a first well bore;

wherein the first fluid comprises a first tracer;

positioning one or more sensors in a second well bore located proximate to the first well bore;

wherein the first tracer is detectable by at least one of the one or more sensors in the second well bore;

determining if the first tracer is detected in the second well bore using the at least one of the one or more sensors in the second well bore;

directing a second fluid into a third well bore located proximate to the second well bore after the first tracer is circulated out of the first well bore;

wherein the second fluid comprises a second tracer, wherein the second tracer is detectable by at least one of the one or more sensors in the second well bore;

detecting presence of the second tracer in the second well bore using the at least one of the one or more sensors in the second well bore; and

identifying which of the first well bore and the third well bore is contaminating the second well bore depending on which of the first tracer and the second tracer is detected in the second well bore.

19. The method of claim 18, wherein the first tracer is the same as the second tracer.

20. The method of claim 18, wherein the second well bore is a water well.