Patent Application
20100193187
Wells are generally drilled into the ground or ocean bed to recover natural deposits of oil and gas, as well as other desirable materials that are trapped in geological formations in the Earth's crust. A well is typically drilled using a drill bit attached to the lower end of a drill string. Drilling fluid, or “mud,” is typically pumped down through the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit, and it carries drill cuttings back to the surface in the annulus between the drill string and the wellbore wall.
For successful oil and gas exploration, it is necessary to have information about the subsurface formations that are penetrated by a wellbore. For example, one aspect of standard formation evaluation relates to the measurements of the formation pressure and formation permeability. These measurements are essential to predicting the production capacity and production lifetime of a subsurface formation.
One technique for measuring formation and reservoir fluid properties includes lowering a wireline tool into the well to measure formation properties. A wireline tool is a measurement tool that is suspended from a wireline in electrical communication with a control system disposed on the surface. The tool is lowered into a well so that it can measure formation properties at desired depths. A typical wireline tool may include a probe that may be pressed against the wellbore wall to establish fluid communication with the formation. This type of wireline tool is often called a formation tester. Using the probe, a formation tester measures the pressure of the formation fluids, which is used to determine the formation permeability. The formation tester tool also typically withdraws a sample of the formation fluid that is either subsequently transported to the surface for analysis or analyzed downhole.
In order to use any wireline tool, whether the tool be a resistivity, porosity or formation testing tool, the drill string must be removed from the well so that the tool can be lowered into the well. This is called a trip uphole. Further, the wireline tools must be lowered to the zone of interest, commonly at or near the bottom of the wellbore. A combination of removing the drill string and lowering the wireline tools downhole are time-consuming measures and can take up to several hours, depending upon the depth of the wellbore. Because of the great expense and rig time required to “trip” the drill pipe and lower the wireline tools down the wellbore, wireline tools are generally used only when the information is absolutely needed or when the drill string is tripped for another reason, such as changing the drill bit. Examples of wireline formation testers are described, for example, in U.S. Pat. Nos. 3,934,468; 4,860,581; 4,893,505; 4,936,139; and 5,622,223.
To avoid or minimize the downtime associated with tripping the drill string, another technique for measuring formation properties has been developed in which tools and devices are positioned near the drill bit in a drilling system. Thus, formation measurements are made during the drilling process and the terminology generally used in the art is “MWD” (measurement-while-drilling) and “LWD” (logging-while-drilling).
MWD typically refers to measuring the drill bit trajectory as well as wellbore temperature and pressure, while LWD refers to measuring formation parameters or properties, such as resistivity, porosity, permeability, and sonic velocity, among others. Real-time data, such as the formation pressure, facilitates making decisions about drilling mud weight and composition, as well as decisions about drilling rate and weight-on-bit, during the drilling process. While LWD and MWD have different meanings to those of ordinary skill in the art, that distinction is not germane to this disclosure, and therefore this disclosure does not distinguish between the two terms.
Formation evaluation, whether during a wireline operation or while drilling, often requires that fluid from the formation be drawn into a downhole tool for testing and/or sampling. Various sampling devices, typically referred to as probes, are extended from the downhole tool to establish fluid communication with the formation surrounding the wellbore and to draw fluid into the downhole tool. A typical probe is a circular element extended from the downhole tool and positioned against the sidewall of the wellbore. A rubber packer at the end of the probe is used to create a seal with the wellbore sidewall. Another device used to form a seal with the wellbore sidewall is referred to as a dual packer. With a dual packer, two elastomeric rings expand radially about the tool to isolate a portion of the wellbore therebetween. The rings form a seal with the wellbore wall and permit fluid to be drawn into the isolated portion of the wellbore and into an inlet in the downhole tool.
The mudcake lining the wellbore is often useful in assisting the probe and/or dual packers in making the seal with the wellbore wall. Once the seal is made, fluid from the formation is drawn into the downhole tool through an inlet by lowering the pressure in the downhole tool. Examples of probes and/or packers used in downhole tools are described in U.S. Pat. Nos. 6,301,959; 4,860,581; 4,936,139; 6,585,045; 6,609,568, and 6,964,301.
Reservoir evaluation can be performed on fluids drawn into the downhole tool while the tool remains downhole. Techniques currently exist for performing various measurements, pretests and/or sample collection of fluids that enter the downhole tool. However, it has been discovered that when the formation fluid passes into the downhole tool, various contaminants, such as wellbore fluids and/or drilling mud primarily in the form of mud filtrate from the “invaded zone” of the formation, may enter the tool with the formation fluids. The invaded zone is the portion of the formation radially beyond the mudcake layer lining the wellbore where mud filtrate has penetrated the formation leaving the mudcake layer behind. These mud filtrate contaminates may affect the quality of measurements and/or samples of the formation fluids. Moreover, contamination may cause costly delays in the wellbore operations by requiring additional time for obtaining test results and/or samples representative of the formation fluid. Additionally, such problems may yield false results that are erroneous and/or unusable. Thus, it is desirable that the formation fluid entering into the downhole tool be sufficiently “clean” or “virgin” for valid testing. In other words, the formation fluid should have little or no contamination.
Attempts have been made to eliminate contaminates from entering the downhole tool with the formation fluid. For example, as depicted in U.S. Pat. No. 4,951,749, filters have been positioned in probes to block contaminates from entering the downhole tool with the formation fluid. As shown in U.S. Pat. No. 6,301,959, a probe is provided with a guard ring to divert contaminated fluids away from clean fluid as it enters the probe. More recently, U.S. Pat. No. 7,178,591 discloses a central sample probe with an annular “guard” probe extending about an outer periphery of the sample probe, in an effort to divert contaminated fluids away from the sample probe.
Traditional techniques do not efficiently or effectively address contamination for various subterranean formation types. A common technique to address high contamination, e.g., sand, within the flow line in the tool is to provide a sacrificial sample bottle. For example, a sample bottle that preferably would be utilized for storing a fluid sample is adapted to filter the fluid sample as it is routed through the tool. In some techniques the sacrificial sample bottle may include a screen or other media and/or separation techniques to reduce the contamination in the fluid sample. One of the drawbacks of these systems is the loss of valuable space in the tool as well as that the sacrificial technique merely buys some time for use of the tool downhole. For example, the sacrificial sample chamber will eventually clog, eliminating utilization of the tool.
Despite the existence of techniques for performing formation evaluation and for attempting to deal with contamination, there remains a need to manipulate the flow of fluids through the downhole tool to reduce contamination as the fluid sample passes through the downhole tool. It is desirable that such techniques are capable of diverting contaminants away from contaminant sensitive devices, such as, and without limitation, sensors and pumps. It is also desirable that such techniques be available at one or more positions in a sample tool flow line.
The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion.
It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.
A drill string 4 is suspended within the wellbore 2 and has a bottomhole assembly 6 which includes a drill bit 11 at its lower end. The surface system includes a deployment assembly 6, such as a platform, derrick, rig, and the like, positioned over wellbore 2. In the embodiment of
In the example of this embodiment, the surface system further includes drilling fluid or mud 12 stored in a pit 13 or tank at the well site. A pump 14 delivers drilling fluid 12 to the interior of drill string 4 via a port in swivel 5, causing the drilling fluid to flow downwardly through drill string 4 as indicated by the directional arrow 1a. The drilling fluid exits drill string 4 via ports in the drill bit 11, and then circulates upwardly through the annulus region between the outside of the drill string and the wall of the wellbore, as indicated by the directional arrows 1b. In this well known manner, the drilling fluid lubricates drill bit 11 and carries formation cuttings up to the surface as it is returned to pit 13 for recirculation.
Bottomhole assembly (“BHA”) 10 of the illustrated embodiment includes a logging-while-drilling (“LWD”) module 15, a measuring-while-drilling (“MWD”) module 16, a roto-steerable system and motor 17, and drill bit 11. LWD module 15 is housed in a special type of drill collar, as is known in the art, and can contain one or a plurality of known types of logging tools. It will also be understood that more than one LWD and/or MWD module can be employed, e.g. as represented generally at 15A. References, throughout, to a module at the position of 15 can alternatively mean a module at the position of 15A as well. LWD module includes capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment.
MWD module 16 is also housed in a special type of drill collar, as is known in the art, and can contain one or more devices for measuring characteristics of the drill string and drill bit. BHA 10 may further include an apparatus (not shown) for generating electrical power to the downhole system. This may typically include a mud turbine generator powered by the flow of the drilling fluid, it being understood that other power and/or battery systems may be employed. In the present embodiment, the MWD module includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, and an inclination measuring device.
In this embodiment, BHA 10 includes a subsurface/local communications module or package generally denoted as 18. Communications module 18 can provide a communications link between a controller 19, the downhole tools, sensors and the like. In the illustrated embodiment, controller 19 is an electronics and processing package that can be disposed at the surface. Electronic package and processors for storing, receiving, sending, and/or analyzing data and signals may be provided at one or more of the modules as well.
Controller 19 can be a computer-based system having a central processing unit (“CPU”). The CPU is a microprocessor based CPU operatively coupled to a memory, as well as an input device and an output device. The input device may comprise a variety of devices, such as a keyboard, mouse, voice-recognition unit, touch screen, other input devices, or combinations of such devices. The output device may comprise a visual and/or audio output device, such as a monitor having a graphical user interface. Additionally, the processing may be done on a single device or multiple devices. Controller 19 may further include transmitting and receiving capabilities for inputting or outputting signals. Electronic communications may be provided between various points and devices by various means and methods including without limitation, cables, fiber optics, mud pulse telemetry, and wired pipe.
A particularly advantageous use of the system hereof may be in conjunction with controlled steering or “directional drilling.” In this embodiment, a roto-steerable subsystem 17 (
In the embodiment illustrated in
In the embodiment of
Tool 20 may be configured to seal off or isolate one or more portions of a wall of wellbore 2 to fluidly couple to the adjacent formation F and/or to draw fluid samples 30. In the illustrated embodiment, tool 20 includes one or more probe modules 26 that can include an inlet 28, illustrated as a probe in this embodiment, for drawing a fluid sample such as formation fluid 30 into tool 20. Sampling tool 20 may include various other components such as a hydraulic power module 32 to provide hydraulic power to the various modules as required; fluid sample containers 34, 36 that can be connected directly to sampling inlet 26 or via a sample flow line 44; and a pumpout module 38 that can be utilized to purge unwanted fluid and/or to convey fluid through tool 20. Examples of some components and configurations are described in U.S. Pat. No. 7,155,967, which is incorporated herein by reference. In the illustrated example, controller 19 and/or downhole electronics 18 are configured to control operations of sampling tool 20 and/or the drawing of a fluid sample from formation F.
Sampling tool 20 includes a filter system 40 illustrated as a module in the exemplary embodiment of
One or more aspects of the present disclosure are directed towards filtering being performed downhole. The filter system 40 may also be placed in locations within the tool 20 other than in the location shown in the exemplary embodiment depicted in
Referring to
Active filter 42 further includes one or more valves, illustrated in this embodiment as bypass valves 46a, 46b and purge valves 48a, 48b, in fluid communication with sample flow line 44. The valves facilitate routing the fluid sample though filter 50 via filter flow route 52 or a bypass flow route 54.
In some embodiments, such as illustrated in
Downhole electronics 18 can provide the active sequencing performed via software and/or communicated signals. It is recognized that downhole electronics 18 may be comprised in an omnibus module for the tool or comprise a system dedicated to filtering system 40. In the illustrated embodiment of
As will be described further below, active filter 42 provides for cleaning of filter 50. In some embodiments, cleaning may be provided in part by a hydraulic driven device 58, e.g., a piston. In some embodiments, operation of device 58 may be provided by hydraulic power source 32 (
Sensors may be provided in fluid communication with one or more flow lines. In the illustrated example, in situ port 60 is illustrated for providing communication with one or more sensors and sample flow line 44. The sensors may facilitate measuring and/or identifying, for example and without limitation, hydrogen sulfide, carbon dioxide, density, viscosity and resistivity. The sensors may comprise any combination of conventional and/or future-developed sensors within the scope of the present disclosure.
An exemplary embodiment of a method of operating active filter 42 is provided with specific reference to
Referring first to
Flow of fluid 30 is provided from sample flow line 44 through either bypass flow route 54 (e.g., a conduit) or filter path 52 of sample flow line 44. Although fluid flow is illustrated in one direction, the direction of the fluid flow can be reversed and/or alternated in various embodiments. For example,
In
In
In
Refer now to
Active filter 42 is shown in the filtering position in
One example of purging and/or cleaning filter 50 is now described with reference to
In view of all of the above and the Figures, those skilled in the art should readily recognize that the present disclosure introduces an apparatus for testing a subterranean formation penetrated by a wellbore, comprising a tool having a sample flow line probe means disposed with the tool for establishing fluid communication between the formation and the sample flow line to draw a fluid sample into the sample flow line, and an active filter positioned in the sample flow line, the active filter providing a filter flow route and a bypass flow route in the sample flow line.
The present disclosure also introduces a module connectable within a formation testing tool that has a sample flow line extending from a fluid sampling inlet to draw a fluid sample from a wellbore and/or subterranean formation into the sample flow line, the module comprising: a body forming a filter flow route and a bypass flow route in the sample flow line when connected within the tool; a filter connected within the filter flow route; a bypass valve in fluid connection with the filter flow route and the bypass flow route, wherein the bypass valve is operable between a filter position routing the fluid sample through the filter flow route and a bypass position routing the fluid sample through the bypass flow route; a purge valve in fluid connection with the filter flow route, the purge valve operable between an open position providing fluid communication between the filter flow route and exterior of the body and a closed position blocking the fluid communication; and a device moveably disposed with the filter, the device expelling the fluid sample from the filter when moved toward the purge valve in the open position.
The present disclosure also introduces a method for testing a subterranean formation, the method comprising: providing a tool having a sample flow line; providing a filter module in the tool, the filter module having a filter flow route and a bypass flow route in fluid communication with the sample flow line, the filter flow route including a filter; deploying the tool in the wellbore; drawing a fluid sample into the sample flow line; filtering the fluid sample by routing the fluid sample through the filter flow route; bypassing the filter by routing the fluid sample through the bypass flow route; and purging the filter to the wellbore.
The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the present disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.
