Instrumentation for a downhole deployment valve

The present generally relates to apparatus and methods for instrumentation associated with a downhole deployment valve or a separate instrumentation sub. In one aspect, a DDV in a casing string is closed in order to isolate an upper section of a wellbore from a lower section. Thereafter, a pressure differential above and below the closed valve is measured by downhole instrumentation to facilitate the opening of the valve. In another aspect, the instrumentation in the DDV includes sensors placed above and below a flapper portion of the valve. The pressure differential is communicated to the surface of the well for use in determining what amount of pressurization is needed in the upper portion to safely and effectively open the valve. Additionally, instrumentation associated with the DDV can include pressure, temperature, and proximity sensors to facilitate the use of not only the DDV but also telemetry tools.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention generally relates to methods and apparatus for use in oil and gas wellbores. More particularly, the invention relates to methods and apparatus for controlling the use of valves and other automated downhole tools through the use of instrumentation that can additionally be used as a relay to the surface. More particularly still, the invention relates to the use of deployment valves in wellbores in order to temporarily isolate an upper portion of the wellbore from a lower portion thereof.

2. Description of the Related Art

Oil and gas wells typically begin by drilling a borehole in the earth to some predetermined depth adjacent a hydrocarbon-bearing formation. After the borehole is drilled to a certain depth, steel tubing or casing is typically inserted in the borehole to form a wellbore and an annular area between the tubing and the earth is filed with cement. The tubing strengthens the borehole and the cement helps to isolate areas of the wellbore during hydrocarbon production.

Historically, wells are drilled in an “overbalanced” condition wherein the wellbore is filled with fluid or mud in order to prevent the inflow of hydrocarbons until the well is completed. The overbalanced condition prevents blow outs and keeps the well controlled. While drilling with weighted fluid provides a safe way to operate, there are disadvantages, like the expense of the mud and the damage to formations if the column of mud becomes so heavy that the mud enters the formations adjacent the wellbore. In order to avoid these problems and to encourage the inflow of hydrocarbons into the wellbore, underbalanced or near underbalanced drilling has become popular in certain instances. Underbalanced drilling involves the formation of a wellbore in a state wherein any wellbore fluid provides a pressure lower than the natural pressure of formation fluids. In these instances, the fluid is typically a gas, like nitrogen and its purpose is limited to carrying out drilling chips produced by a rotating drill bit. Since underbalanced well conditions can cause a blow out, they must be drilled through some type of pressure device like a rotating drilling head at the surface of the well to permit a tubular drill string to be rotated and lowered therethrough while retaining a pressure seal around the drill string. Even in overbalanced wells there is a need to prevent blow outs. In most every instance, wells are drilled through blow out preventers in case of a pressure surge.

As the formation and completion of an underbalanced or near underbalanced well continues, it is often necessary to insert a string of tools into the wellbore that cannot be inserted through a rotating drilling head or blow out preventer due to their shape and relatively large outer diameter. In these instances, a lubricator that consists of a tubular housing tall enough to hold the string of tools is installed in a vertical orientation at the top of a wellhead to provide a pressurizable temporary housing that avoids downhole pressures. By manipulating valves at the upper and lower end of the lubricator, the string of tools can be lowered into a live well while keeping the pressure within the well localized. Even a well in an overbalanced condition can benefit from the use of a lubricator when the string of tools will not fit though a blow out preventer. The use of lubricators is well known in the art and the forgoing method is more fully explained in U.S. patent application Ser. No. 09/536,937, filed Mar. 27, 2000, and that published application is incorporated by reference herein in its entirety.

While lubricators are effective in controlling pressure, some strings of tools are too long for use with a lubricator. For example, the vertical distance from a rig floor to the rig draw works is typically about ninety feet or is limited to that length of tubular string that is typically inserted into the well. If a string of tools is longer than ninety feet, there is not room between the rig floor and the draw works to accommodate a lubricator. In these instances, a down hole deployment valve or DDV can be used to create a pressurized housing for the string of tools. Downhole deployment valves are well known in the art and one such valve is described in U.S. Pat. No. 6,209,663, which is incorporated by reference herein in its entirety. Basically, a DDV is run into a well as part of a string of casing. The valve is initially in an open position with a flapper member in a position whereby the full bore of the casing is open to the flow of fluid and the passage of tubular strings and tools into and out of the wellbore. In the valve taught in the '663 patent, the valve includes an axially moveable sleeve that interferes with and retains the flapper in the open position. Additionally, a series of slots and pins permits the valve to be openable or closable with pressure but to then remain in that position without pressure continuously applied thereto. A control line runs from the DDV to the surface of the well and is typically hydraulically controlled. With the application of fluid pressure through the control line, the DDV can be made to close so that its flapper seats in a circular seat formed in the bore of the casing and blocks the flow of fluid through the casing. In this manner, a portion of the casing above the DDV is isolated from a lower portion of the casing below the DDV.

The DDV is used to install a string of tools in a wellbore as follows: When an operator wants to install the tool string, the DDV is closed via the control line by using hydraulic pressure to close the mechanical valve. Thereafter, with an upper portion of the wellbore isolated, a pressure in the upper portion is bled off to bring the pressure in the upper portion to a level approximately equal to one atmosphere. With the upper portion depressurized, the wellhead can be opened and the string of tools run into the upper portion from a surface of the well, typically on a string of tubulars. A rotating drilling head or other stripper like device is then sealed around the tubular string or movement through a blowout preventer can be re-established. In order to reopen the DDV, the upper portion of the wellbore must be repressurized in order to permit the downwardly opening flapper member to operate against the pressure therebelow. After the upper portion is pressurized to a predetermined level, the flapper can be opened and locked in place. Now the tool string is located in the pressurized wellbore.

Presently there is no instrumentation to know a pressure differential across the flapper when it is in the closed position. This information is vital for opening the flapper without applying excessive force. A rough estimate of pressure differential is obtained by calculating fluid pressure below the flapper from wellhead pressure and hydrostatic head of fluid above the flapper. Similarly when the hydraulic pressure is applied to the mandrel to move it one way or the other, there is no way to know the position of the mandrel at any time during that operation. Only when the mandrel reaches dead stop, its position is determined by rough measurement of the fluid emanating from the return line. This also indicates that the flapper is either fully opened or fully closed. The invention described here is intended to take out the uncertainty associated with the above measurements.

In addition to problems associated with the operation of DDVs, many prior art downhole measurement systems lack reliable data communication to and from control units located on a surface. For example, conventional measurement while drilling (MWD) tools utilize mud pulse, which works fine with incompressible drilling fluids such as a water-based or an oil-based mud, but they do not work when gasified fluids or gases are used in underbalanced drilling. An alternative to this is electromagnetic (EM) telemetry where communication between the MWD tool and the surface monitoring device is established via electromagnetic waves traveling through the formations surrounding the well. However, EM telemetry suffers from signal attenuation as it travels through layers of different types of formations. Any formation that produces more than minimal loss serves as an EM barrier. In particular salt domes tend to completely moderate the signal. Some of the techniques employed to alleviate this problem include running an electric wire inside the drill string from the EM tool up to a predetermined depth from where the signal can come to the surface via EM waves and placing multiple receivers and transmitters in the drill string to provide boost to the signal at frequent intervals. However, both of these techniques have their own problems and complexities. Currently, there is no available means to cost efficiently relay signals from a point within the well to the surface through a traditional control line.

Expandable Sand Screens (ESS) consist of a slotted steel tube, around which overlapping layers of filter membrane are attached. The membranes are protected with a pre-slotted steel shroud forming the outer wall. When deployed in the well, ESS looks like a three-layered pipe. Once it is situated in the well, it is expanded with a special tool to come in contact with the wellbore wall. The expander tool includes a body having at least two radially extending members, each of which has a roller that when coming into contact with an inner wall of the ESS, can expand the wall past its elastic limit. The expander tool operates with pressurized fluid delivered in a string of tubulars and is more completely disclosed in U.S. Pat. No. 6,425,444 and that patent is incorporated in its entirety herein by reference. In this manner ESS supports the wall against collapsing into the well, provides a large wellbore size for greater productivity, and allows free flow of hydrocarbons into the well while filtering out sand. The expansion tool contains rollers supported on pressure-actuated pistons. Fluid pressure in the tool determines how far the ESS is expanded. While too much expansion is bad for both the ESS and the well, too little expansion does not provide support to the wellbore wall. Therefore, monitoring and controlling fluid pressure in the expansion tool is very important. Presently fluid pressure is measured with a memory gage, which of course provides information after the job has been completed. A real time measurement is desirable so that fluid pressure can be adjusted during the operation of the tool if necessary.

There is a need therefore, for a downhole system of instrumentation and monitoring that can facilitate the operation of downhole tools. There is a further need for a system of instrumentation that can facilitate the operation of downhole deployment valves. There is yet a further need for downhole instrumentation apparatus and methods that include sensors to measure downhole conditions like pressure, temperature, and proximity in order to facilitate the efficient operation of the downhole tools. Finally, there exists a need for downhole instrumentation and circuitry to improve communication with existing expansion tools used with expandable sand screens and downhole measurement devices such as MWD and pressure while drilling (PWD) tools.

SUMMARY OF THE INVENTION

The present invention generally relates to methods and apparatus for instrumentation associated with a downhole deployment valve (DDV). In one aspect, a DDV in a casing string is closed in order to isolate an upper section of a wellbore from a lower section. Thereafter, a pressure differential above and below the closed valve is measured by downhole instrumentation to facilitate the opening of the valve. In another aspect, the instrumentation in the DDV includes different kinds of sensors placed in the DDV housing for measuring all important parameters for safe operation of the DDV, a circuitry for local processing of signal received from the sensors, and a transmitter for transmitting the data to a surface control unit.

In yet another aspect, the design of circuitry, selection of sensors, and data communication is not limited to use with and within downhole deployment valves. All aspects of downhole instrumentation can be varied and tailored for others applications such as improving communication between surface units and measurement while drilling (MWD) tools, pressure while drilling (PWD) tools, and expandable sand screens (ESS).

DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT

FIG. 1is a section view of a wellbore100with a casing string102disposed therein and held in pace by cement104. The casing string102extends from a surface of the wellbore100where a wellhead106would typically be located along with some type of valve assembly108which controls the flow of fluid from the wellbore100and is schematically shown. Disposed within the casing string102is a downhole deployment valve (DDV)110that includes a housing112, a flapper230having a hinge232at one end, and a valve seat242in an inner diameter of the housing112adjacent the flapper230. Alternatively, the flapper230may be replaced by a ball (not shown). As stated herein, the DDV110is an integral part of the casing string102and is run into the wellbore100along with the casing string102prior to cementing. The housing112protects the components of the DDV110from damage during run in and cementing. Arrangement of the flapper230allows it to close in an upward fashion wherein pressure in a lower portion120of the wellbore will act to keep the flapper230in a closed position. The DDV110also includes a surface monitoring and control unit (SMCU)800to permit the flapper230to be opened and closed remotely from the surface of the well. As schematically illustrated inFIG. 1, the attachments connected to the SMCU800include some mechanical-type actuator124and a control line126that can carry hydraulic fluid and/or electrical currents. Clamps (not shown) can hold the control line126next to the casing string102at regular intervals to protect the control line126.

Also shown schematically inFIG. 1is an upper sensor128placed in an upper portion130of the wellbore and a lower sensor129placed in the lower portion120of the wellbore. The upper sensor128and the lower sensor129can determine a fluid pressure within an upper portion130and a lower portion120of the wellbore, respectively. Similar to the upper and lower sensors128,129shown, additional sensors (not shown) can be located in the housing112of the DDV110to measure any wellbore condition or parameter such as a position of the sleeve226, the presence or absence of a drill string, and wellbore temperature. The additional sensors can determine a fluid composition such as an oil to water ratio, an oil to gas ratio, or a gas to liquid ratio. Furthermore, the additional sensors can detect and measure a seismic pressure wave from a source located within the wellbore, within an adjacent wellbore, or at the surface. Therefore, the additional sensors can provide real time seismic information.

FIG. 2is an enlarged view of a portion of the DDV110showing the flapper230and a sleeve226that keeps it in an open position. In the embodiment shown, the flapper230is initially held in an open position by the sleeve226that extends downward to cover the flapper230and to ensure a substantially unobstructed bore through the DDV110. A sensor131detects an axial position of the sleeve226as shown inFIG. 2and sends a signal through the control line126to the SMCU800that the flapper230is completely open. All sensors such as the sensors128,129,131shown inFIG. 2connect by a cable125to circuit boards132located downhole in the housing112of the DDV110. Power supply to the circuit boards132and data transfer from the circuit boards132to the SMCU800is achieved via an electric conductor in the control line126. Circuit boards132have free channels for adding new sensors depending on the need.

FIG. 3is a section view showing the DDV110in a closed position. A flapper engaging end240of a valve seat242in the housing112receives the flapper230as it closes. Once the sleeve226axially moves out of the way of the flapper230and the flapper engaging end240of the valve seat242, a biasing member234biases the flapper230against the flapper engaging end240of the valve seat242. In the embodiment shown, the biasing member234is a spring that moves the flapper230along an axis of a hinge232to the closed position. Common known methods of axially moving the sleeve226include hydraulic pistons (not shown) that are operated by pressure supplied from the control line126and interactions with the drill string based on rotational or axially movements of the drill string. The sensor131detects the axial position of the sleeve226as it is being moved axially within the DDV110and sends signals through the control line126to the SMCU800. Therefore, the SMCU800reports on a display a percentage representing a partially opened or closed position of the flapper230based upon the position of the sleeve226.

FIG. 4is a section view showing the wellbore100with the DDV110in the closed position. In this position the upper portion130of the wellbore100is isolated from the lower portion120and any pressure remaining in the upper portion130can be bled out through the valve assembly108at the surface of the well as shown by arrows. With the upper portion130of the wellbore free of pressure the wellhead106can be opened for safely performing operations such as inserting or removing a string of tools.

FIG. 5is a section view showing the wellbore100with the wellhead106opened and a string of tools500having been instated into the upper portion130of the wellbore. The string of tools500can include apparatus such as bits, mud motors, measurement while drilling devices, rotary steering devices, perforating systems, screens, and/or slotted liner systems. These are only some examples of tools that can be disposed on a string and instated into a well using the method and apparatus of the present invention. Because the height of the upper portion130is greater than the length of the string of tools500, the string of tools500can be completely contained in the upper portion130while the upper portion130is isolated from the lower portion120by the DDV110in the closed position. Finally,FIG. 6is an additional view of the wellbore100showing the DDV110in the open position and the string of tools500extending from the upper portion130to the lower portion120of the wellbore. In the illustration shown, a device (not shown) such as a stripper or rotating head at the wellhead106maintains pressure around the tool string500as it enters the wellbore100.

Prior to opening the DDV110, fluid pressures in the upper portion130and the lower portion120of the wellbore100at the flapper230in the DDV110must be equalized or nearly equalized to effectively and safely open the flapper230. Since the upper portion130is opened at the surface in order to insert the tool string500, it will be at or near atmospheric pressure while the lower portion120will be at well pressure. Using means well known in the art, air or fluid in the top portion130is pressurized mechanically to a level at or near the level of the lower portion120. Based on data obtained from sensors128and129and the SMCU800, the pressure conditions and differentials in the upper portion130and lower portion120of the wellbore100can be accurately equalized prior to opening the DDV110.

While the instrumentation such as sensors, receivers, and circuits is shown as an integral part of the housing112of the DDV110(SeeFIG. 2) in the examples, it will be understood that the instrumentation could be located in a separate “instrumentation sub” located in the casing string. The instrumentation sub can be hard wired to a SMCU in a manner similar to running a hydraulic dual line control (HDLC) cable from the instrumentation of the DDV110(seeFIG. 8). Therefore, the instrumentation sub utilizes sensors, receivers, and circuits as described herein without utilizing the other components of the DDV110such as a flapper and a valve seat.

FIG. 8is a schematic diagram of a control system and its relationship to a well having a DDV or an instrumentation sub that is wired with sensors.

The figure shows the wellbore having the DDV110disposed therein with the electronics necessary to operate the sensors discussed above (seeFIG. 1). A conductor embedded in a control line which is shown inFIG. 8as a hydraulic dual line control (HDLC) cable126provides communication between downhole sensors and/or receivers835and a surface monitoring and control unit (SMCU)800. The HDLC cable126extends from the DDV110outside of the casing string containing the DDV to an interface unit of the SMCU800. The SMCU800can include a hydraulic pump815and a series of valves utilized in operating the DDV110by fluid communication through the HDLC126and in establishing a pressure above the DDV110substantially equivalent to the pressure below the DDV110. In addition, the SMCU800can include a programmable logic controller (PLC)820based system for monitoring and controlling each valve and other parameters, circuitry805for interfacing with downhole electronics, an onboard display825, and standard RS-232 interfaces (not shown) for connecting external devices. In this arrangement, the SMCU800outputs information obtained by the sensors and/or receivers835in the wellbore to the display825. Using the arrangement illustrated, the pressure differential between the upper portion and the lower portion of the wellbore can be monitored and adjusted to an optimum level for opening the valve. In addition to pressure information near the DDV110, the system can also include proximity sensors that describe the position of the sleeve in the valve that is responsible for retaining the valve in the open position. By ensuring that the sleeve is entirely in the open or the closed position, the valve can be operated more effectively. A separate computing device such as a laptop840can optionally be connected to the SMCU800.

FIG. 7is a section view of a wellbore100with a string of tools700that includes a telemetry tool702inserted in the wellbore100. The telemetry tool702transmits the readings of instruments to a remote location by means of radio waves or other means. In the embodiment shown inFIG. 7, the telemetry tool702uses electromagnetic (EM) waves704to transmit downhole information to a remote location, in this case a receiver706located in or near a housing of a DDV110instead of at a surface of the wellbore. Alternatively, the DDV110can be an instrumentation sub that comprises sensors, receivers, and circuits, but does not include the other components of the DDV110such as a valve. The EM wave704can be any form of electromagnetic radiation such as radio waves, gamma rays, or x-rays. The telemetry tool702disposed in the tubular string700near the bit707transmits data related to the location and face angle of the bit707, hole inclination, downhole pressure, and other variables. The receiver706converts the EM waves704that it receives from the telemetry tool702to an electric signal, which is fed into a circuit in the DDV110via a short cable710. The signal travels to the SMCU via a conductor in a control line126. Similarly, an electric signal from the SMCU can be sent to the DDV110that can then send an EM signal to the telemetry tool702in order to provide two way communication. By using the telemetry tool702in connection with the DDV110and its preexisting control line126that connects it to the SMCU800at the surface, the reliability and performance of the telemetry tool702is increased since the EM waves704need not be transmitted through formations as far. Therefore, embodiments of this invention provide communication with downhole devices such as telemetry tool702that are located below formations containing an EM barrier. Examples of downhole tools used with the telemetry tool702include a measurement while drilling (MWD) tool or a pressure while drilling (PWD) tool.

Still another use of the apparatus and methods of the present invention relate to the use of an expandable sand screen or ESS and real time measurement of pressure required for expanding the ESS. Using the apparatus and methods of the current invention with sensors incorporated in an expansion tool and data transmitted to a SMCU (seeFIG. 8) via a control line connected to a DDV or instrumentation sub having circuit boards, sensors, and receivers within, pressure in and around the expansion tool can be monitored and adjusted from a surface of a wellbore. In operation, the DDV or instrumentation sub receives a signal similar to the signal described inFIG. 7from the sensors incorporated in the expansion tool, processes the signal with the circuit boards, and sends data relating to pressure in and around the expansion tool to the surface through the control line. Based on the data received at the surface, an operator can adjust a pressure applied to the ESS by changing a fluid pressure supplied to the expansion tool.