NO336704B1 - method and apparatus for measuring borehole or formation parameters, method and apparatus for determining flow characteristics of a fluid flowing through a casing string. - Google Patents

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of a pending US patent application serial number 10/288,229, filed November 5, 2002, which is incorporated herein by reference in its entirety.

This application is related to a patent-pending US patent application serial number 10/676,376 having legal summary number WEAT/0438, filed on the same date as the current application, entitled "Permanent Well Deployment of Optical Sensors" which is incorporated herein by reference in its entirety.

BACKGROUND OF THE INVENTION

Scope of the invention

The current invention is generally related to methods and apparatus for use in oil and gas wells. More particularly, the invention relates to the use of instrumentation to monitor wellbore conditions within boreholes. Even more particularly, the invention relates to methods and apparatus for controlling the use of valves and other automatic downhole tools by means of instrumentation which can additionally be used as a relay to the surface. More particularly, the invention is related to the use of deployment valves in boreholes to be able to temporarily isolate an upper part of the borehole from a lower part thereof.

Description of the present invention

Oil and gas wells usually begin with the drilling of a borehole in the earth to a predetermined depth near a hydrocarbon-bearing formation. After the borehole is drilled to a certain depth, steel pipe or casing is usually added into the borehole to form a borehole and an annular area between the pipe and the soil is filled with cement. The pipe strengthens the borehole and the cement helps to isolate areas of the borehole during hydrocarbon production.

Historically, wells have been drilled in an "overbalanced" condition in which the borehole is filled with fluid or mud to prevent the flow of hydrocarbons until the well is completed. The overbalanced condition prevents uncontrolled blowout and keeps the well under control. While drilling with heavy fluid provides a safe way to operate, there are disadvantages, such as the expense of mud and the damage to the formations if the column of mud becomes so heavy that the mud enters the formations near the borehole. To be able to avoid these problems and to stimulate the inflow of hydrocarbons to the borehole has underbalances! or near unbalanced drilling has become popular in special cases. Underbalance! drilling involves the formation of a borehole in a condition where any borehole fluid produces a lower pressure than the natural pressure of the formation fluids. In these cases, the fluid is usually a gas such as nitrogen, and its purpose is limited to removing cuttings produced by a rotating drill bit. Since underbalanced well conditions can cause a blowout, they must be drilled through some type of pressure device, such as a rotary drill head at the surface of the well, so that a tubular drill string can be rotated and lowered through it while maintaining the pressure seal around the drill string. Even in overbalanced wells, there is a need to prevent blowout. In almost all cases, wells are drilled through blowout safeguards in the event of a well kick.

As the formation and completion of an underbalanced or close to underbalanced! well continues, it is often necessary to add a string of downhole tools that cannot be added through a rotary drill head or blowout preventer due to their shape and relatively large outer diameter. In these cases, a cable run sluice consisting of a tubular enclosure is high enough to hold the string of tools installer! in a vertical position at the top of the wellhead to provide a pressurized, temporary enclosure that avoids pressure in the wellbore. By manipulating valves at the upper and lower ends of the cable run lock, the string of tools can be lowered into a free-flowing well while keeping the pressure within the well localized. Even a well in an overbalanced condition can benefit from the use of a cable run sluice when the string of tools will not fit through a blowout preventer. The use of cable run sluices is well known in the art and the foregoing method is fully explained in US Patent Application No. 09/536,937, filed March 27, 2000, the published application of which is incorporated herein by reference in its entirety.

While cable run sluices are effective in contracting pressure, some strings of tools are too long to be used with a cable run sluice. For example, the vertical distance from a drill deck to drilling machines is usually about ninety feet or is limited to the length of tubular string that is usually added to the well. If a tool string is longer than ninety feet, there is no space between the drill deck and the drills to accommodate a cable run sluice. In these cases, a downhole deployment valve or DDV can be used to create a pressurized casing for the tool strings. Deployment valves in wellbore are well known in the art and such a valve is described in US patent number 6,209,663 which is incorporated herein by reference in its entirety. Basically, a DDV is driven into a well as part of a casing string. The valve is initially in an open position with a flap joint in a position whereby the entire inner diameter of the casing is open to fluid flow and the passage of the tubular strings and tools into and out of the borehole. In the valve disclosed in the '663 patent, the valve includes an axially movable sleeve which engages and holds the valve in the open position. In addition, a series of slots and pins will allow the valve to open or close with pressure, but then remain in that position without pressure being continuously applied. A control line is run from the DDV to the surface of the well and is usually hydraulically controlled. With the application of fluid pressure through the control line, the DDV can be made so that when closed, its flap can seat into a circular seat formed in the inner diameter of the casing and block fluid flow through the casing. In this way, a part of the casing above the DV is isolated from a lower part of the casing below the DDV.

The DDV is used to install tool strings in a borehole as follows: When an operator wants to install the tool string, the DDV is closed via a control line using hydraulic pressure to close the mechanical valve. With an upper portion of the borehole isolated, a pressure in the upper portion will then be released to bring the pressure in the upper portion to a level approximately equivalent to one atomic sphere. When the upper part is depressurised, the wellhead can be opened and the tool string driven into the upper part from a surface of the well, usually on a pipe string. A rotary drill head or other mud scraper-like device is then sealed around the tubing string, or it may re-establish movement through a blowout preventer. To be able to open the DDV again, the upper part of the borehole must be pressurized to allow the downward flap valve to operate against the pressure below. After the upper part is pressurized to a predefined level, the flap can be opened and locked in place. Now the tool string is placed in the pressurized borehole.

Currently there is no instrumentation to sense a pressure differential along the flap when it is in the closed position. This information is important for opening the flap without applying excessive pressure. A rough estimate of the pressure differential is obtained by calculating the fluid pressure below the flap from wellhead pressure and hydrostatic head for fluid above the flap. Once the hydraulic pressure is applied to the stem to move it one way or another, there is no way of knowing the position of the stem at any point during that operation. Only when the stem reaches a full stop can the position be determined by a rough estimate of the liquid flowing out from the return line. The invention described here aims to remove the uncertainty associated with the above measurements.

In addition to monitoring the pressure differential along the flap and the position of the flap

in a DDV, it is sometimes desirable to monitor well conditions on site. The technology has recently enabled operators to monitor conditions within a borehole by installing monitoring systems in the wellbore. The monitoring system allows the operator to monitor multiphase fluid flow as well as pressure, seismic conditions, downhole component vibrations and temperature during the production of hydrocarbon fluids. Downhole measurements of pressure, temperature, seismic conditions, vibration of wellbore components and fluid flow play an important role in the treatment of oil and gas or other underground storage containers.

Historically, monitoring systems have used electronic components to provide information on pressure, temperature, flow rate, water fraction and other formation and wellbore parameters on a real-time basis during production operations. These monitoring systems use temperature gauges, pressure gauges, acoustic sensors, seismic sensors, electromagnetic sensors, and other instruments or "probes," including those that provide core measurements, located within the borehole. Such instruments are either battery operated or are operated using electrical cables deployed from the surface. Monitoring systems have historically been configured to provide an electrical line that allows measuring instruments or sensors to transmit measurements to the surface.

Recently, optical sensors have been developed that communicate readings from the borehole to optical signal processing equipment located at the surface. Optical sensors have been proposed to be used after the well has been drilled to detect real-time seismic information below the surface that can be processed into useful information. Optical sensors can be arranged along tubing strings such as a production tube inserted into an inner diameter of a casing string within a drilled borehole by adding to production tubing with optical sensors placed thereon. The production pipe is inserted through the inner diameter of the casing strings already arranged within the borehole after the drilling operation. In either case, an optical wire or cable is run from the surface to the optical sensor in the wellbore. The optical sensor can be a pressure gauge, temperature gauge, acoustic sensor, seismic sensor or another probe. The optical line transmits optical signals to the optical signal processor at the surface.

The optical signal processing equipment includes a magnetizing light source. Magnetizing light can be supplied by a broadband light source such as a light emitting diode (LED) located within the optical signal processing equipment. The optical signal processing equipment also includes appropriate equipment for delivering signal light to the sensor(s), such as Bragg gratings or lasers and couplers that split the signal light into more than one branch line to deliver to more than one sensor. In addition, the optical signal processing equipment includes suitable optical signal analysis equipment for analyzing return signals from the Bragg grating.

The optical wire is usually designed to deliver pulses or continuous signals of optical energy from the light source to the optical sensor(s). The optical cable is also often designed to withstand the high temperatures and pressures prevalent within a hydrocarbon wellbore. Preferably, the optical cable includes an internal optical fiber that is protected from mechanical and environmental damage by a surrounding tubular tube. The hair tubular tube is made of a highly resistant, rigid-walled, erosion-resistant material such as stainless steel. The tube is connected to the sensor using suitable methods, such as threads, a weld joint or other suitable methods. The optical fiber contains a light-conducting core that guides the light along the fiber. The core preferably uses one or more Bragg gratings to act as an optical resonator and also to interact with the probe.

Optical sensors, in addition to monitoring conditions within a drilled well or part of a well during production operations, can also be used to obtain seismic information from within the formation prior to drilling a well. Initial seismic data is generally obtained by performing a seismic survey. A seismic survey maps the soil formation underground by sending sound energy or acoustic waves down into the formation from a seismic source and by recording "echoes" that return from the rock layers below. The source of downward sound energy can come from explosions, seismic vibrations on land or air guns in marine environments. During the course of a seismic measurement, the energy source is moved to several pre-planned locations on the surface of the Earth above the geological structure of interest. Each time the source is activated, it produces a seismic signal that travels down through the earth, is reflected, and on its return, documented at many locations on the surface. Multiple energy activation/documentation combinations are then combined to create a near uninterrupted profile underground that can be extended over several miles. In a two-dimensional (2-D) seismic measurement, the documentation location units are generally located along a single straight line, while in a three-dimensional (3-D) measurement, the documentation location units are distributed along the surface in a raster field. Quite simply, a 2-D seismic line can be thought of as providing a cross-sectional image (vertical slice) of the soil layers since they exist directly below the documented locations. A 3-D measurement produces a data "cube" or volume which is, at least in principle, a 3-D image of the underground that lies below the measurement area. A 4-D measurement produces a 3-D image of the underground with respect to time, time being the fourth dimension.

After the measurement has been carried out, the data from the measurement is processed to remove noise or other unwanted information. During the processing of seismic data, subsurface velocity estimates are routinely produced and near-surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly calculate rock properties (including permeability and elastic parameters), water saturation and hydrocarbon content. Less clearly, seismic waveform attributes such as phase, peak amplitude, peak-to-bottom ratio, and a number of others can often be in empirical agreement with known hydrocarbon occurrences and that this correlation can be applied against seismic data collected over new research targets.

The procedure for seismic monitoring with optical sensors after the well has been drilled is the same as described above in relation to obtaining the initial seismic measurement, except that more locations are available for locating the seismic source and seismic sensor, and the optical information must be transferred to the surface for treatment. To monitor seismic conditions within the formation, a seismic source transmits a signal into the formation and then the signal is reflected from the formation to the seismic sensor. The seismic source can be at the surface of the borehole, in a nearby borehole or within the well. The seismic sensor will then transmit the optical information regarding the seismic conditions through an optical cable to the surface for processing by a central processing unit or other processing device. The processing takes place as described above in relation to the initial seismic measurement. In addition to the seismic source being reflected from the formation to the seismic sensor, a signal can be transmitted directly from the seismic source to the seismic sensor.

Seismic sensors must detect seismic conditions within the formation with some level of accuracy to be useful; therefore, seismic sensors placed on production tubing have typically been placed in close contact with the interior of the casing strings to couple the seismic sensor to the formation, thereby reducing fluid attenuation or disturbance of the signal and increasing the accuracy of the readings. The connection of the seismic sensor to the formation from the production pipe includes distance and therefore requires complicated maneuvers and equipment to carry out the task.

Although placing the seismic sensor in direct contact with the inside of the casing string allows for more accurate readings than current alternatives due to its coupling to the formation, it is desirable to further increase the accuracy of the seismic readings by placing the seismic sensors closer to the formation where the measurement takes place from. The closer the seismic sensor is to the formation, the more accurate the signal will be. A vibrating sensor for example, such as an accelerometer or geophone, must be placed in direct contact with the formation to obtain accurate readings. It is further desirable to reduce the complexity of the maneuvers and equipment required to connect the seismic sensor to the formation. Therefore, it is desirable to place the seismic sensor as close to the formation as possible.

While the current methods of measuring wellbore and formation parameters using optical sensors allow temporary measurement of the parameters before the drilling and completion operations of the wellbore at the surface, and during production operations on production tubing or other production equipment, there is a need to permanently monitor wellbore and formation conditions and parameters during all wellbore operations, including during wellbore drilling and completion operations. It is thus desirable to obtain accurate real-time readings of seismic conditions while drilling into the formation. It is also desirable to permanently monitor wellbore conditions before and after production pipe is inserted into the borehole.

In addition to the problems associated with the operation of DDV, many previous downhole measurement systems lack reliable data communication to and from surface control units. For example: conventional measurement-while-drilling (MWD) tools use mud pulses which work well with non-compressible drilling fluids such as a water-based or oil-based mud, but they do not work when aerated fluids or gases are used in underbalances! drilling. An alternative to this is electromagnetic (EM) telemetry, where the communication between the MWD tool and the monitoring device at the surface is established via electromagnetic waves that move through the formation surrounding the well. However, EM telemetry suffers from signal attenuation as it travels through layers of different types of formations. Any formation that deals more than minimal loss acts as an EM barrier. Salt domes in particular tend to completely weaken or modify the signal. Some of the techniques used to alleviate this problem include running an electrical wire inside the drill string from the EM tool up to a predetermined depth from where the signal can reach the surface via EM waves and placing multiple receivers and transmitters in the drill string to to supply additional voltage to the signal at frequent intervals. However, both of these techniques have their own problems and complications.

Currently, there is no means available to cost-effectively transmit signals from a point within the well to the surface through a traditional control line.

Expandable sand filter pipes (ESS) consist of a slotted steel pipe around which an overlapping layer of filter membrane is connected. The membranes are protected with a pre-slotted steel plate which forms the outer wall. When deployed in the well, the ESS looks like a three-layer pipe. As soon as it is placed in the well, it is expanded with a special tool to make contact with the wellbore wall. The expansion tool includes a body having at least two radially extended links each having a roller capable of expanding the wall beyond its elastic limit when contacting an inner wall of the ESS. The expansion tool operates with pressurized fluids delivered in a string of tubing and is fully disclosed in US Patent Number 6,425,444 and that patent is incorporated herein in its entirety by reference. In this way, the ESS supports the wall against collapse in the well which provides a large wellbore size for better productivity and allows free flow of hydrocarbons into the well while filtering out sand. The expansion tool contains rollers that are supported on pressure-activated pistons. Fluid pressure in the tool determines how far the ESS is extended. While too much expansion is not good, both for the ESS and the well, too little expansion will give too little support to the wellbore wall. Monitoring and control of fluid pressure in the expansion tool is therefore very important. Currently, fluid pressure is measured with a memory gauge that provides information after the job is completed. A real-time measurement is desirable, so that fluid pressure can be adjusted during operation of the tool if necessary.

Publication GB 2394974 A describes a wellbore deployment valve with sensors. The publication US 6157893 A describes an apparatus and method for obtaining samples of original formation or formation fluid. The publication US 6531694 B describes boreholes that use fiber optic based sensors and operating devices.

There is therefore a need for a downhole system for instrumentation and monitoring that can simplify the operation of downhole tools. There is a further need for a system of instrumentation that can simplify the operation of downhole deployment valves. There is still a need for downhole instrumentation devices and methods that include sensors to measure downhole conditions such as pressure, temperature, seismic conditions, flow rate, differential pressure, distributed temperature and proximity to facilitate the efficient operation of downhole tools. A further need exists for downhole instrumentation and circuitry to improve communication with existing expansion tools used in conjunction with expandable sand screen tubes and downhole measurement devices such as MWD and pressure-while-drilling (PWD) tools. There is a need for downhole instrumentation that requires less equipment to connect to the formation to obtain accurate readings of the borehole and formation parameters. Finally, there is a need to have the ability to measure with substantial accuracy borehole and formation conditions during drilling in the formation, as well as a need for the ability to consequently permanently monitor and measure wellbore conditions after the borehole is drilled.

SUMMARY OF THE INVENTION

The present invention relates to a method for measuring borehole or formation parameters,

characterized by the fact that it includes:

- placing a wellbore tool within a borehole, where the wellbore tool comprises: - a casing string, where at least part of the casing string comprises a wellbore deployment valve; and -an optical sensor arranged on the casing string;

- cementing the casing string within the borehole; and

- to lower a drill string into the borehole while borehole or formation parameters are sensed with the optical sensor.

The present invention also relates to an apparatus for monitoring the conditions in a borehole or a formation,

characterized by the fact that it includes:

-a casing string cemented in the borehole, where at least part of the casing string comprises a wellbore deployment valve for selectively preventing a fluid path through the casing string; and -at least one optical sensor arranged on the casing string for tracking one or more parameters within the borehole or formation; and -a control line substantially parallel to an optical line connecting a surface monitoring and control unit to the wellbore deployment valve, wherein at least a portion of the control line and the optical line are protected by at least one casing disposed around the casing string.

The present invention also relates to a method for permanent monitoring of at least one borehole or formation parameter,

characterized by the fact that it includes the steps:

- placing a casing string in a borehole, where at least part of the casing string comprises a wellbore deployment valve with at least one optical sensor arranged therein, wherein the wellbore deployment valve is an integral part of the casing string; - cementing the casing string in the borehole; -controlling the deployment valve between closed and open positions, wherein the closed position essentially prevents a bore in the casing string and the open position provides a passage for a tool to be passed through the bore; and sensing at least one borehole or formation parameter using the optical sensor.

The present invention also relates to a method for determining flow properties for a fluid flowing through a casing string,

characterized by the fact that it includes the steps:

- providing a casing string cemented within a wellbore, wherein the casing string comprises a wellbore deployment valve and at least one optical sensor coupled thereto, wherein the wellbore deployment valve is an integral part of the casing string: - measuring properties of fluids flowing through the casing string by means of the at least one optical sensor; and determining at least one of the fluid's volumetric phase fraction or the fluid's flow rate on the basis of the measured fluid properties.

The present invention also relates to an apparatus for determining the flow characteristics of a fluid flowing through a casing string in a borehole,

characterized by the fact that it includes:

-a casing string cemented in the borehole, the casing string comprising a wellbore deployment valve, wherein the wellbore deployment valve is an integral part of the casing string; and -at least one optical sensor connected to the casing string for sensing at least one of the fluid's volumetric phase fraction or the fluid's flow rate through the casing string.

Further embodiments of the methods and devices according to the invention appear from the independent patent claims.

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

In another aspect, the instrumentation associated with the DDV includes an optical sensor located in the DDV casing on the casing string for measuring wellbore conditions before, during, and after drilling into the formation. A method for measuring wellbore or formation parameters is described which comprises placing a wellbore tool within a borehole, where the wellbore tool comprises a casing string, and where at least part of the casing string comprises a deployment valve and an optical sensor arranged on the casing string, and lowering a drill string into in the borehole while the optical sensor receives borehole or formation parameters. Also described is an apparatus for monitoring conditions within a borehole or a formation, which comprises a casing string, where at least part of the casing string comprises a deployment valve to selectively prevent a fluid path through the casing string, and at least one optical sensor arranged on the casing string for tracking a or more parameters within the borehole or formation. It is further described a method for permanent monitoring of at least one borehole or formation parameter, which comprises placement of a casing string within a borehole, at least part of the casing string comprises a deployment valve with at least one optical sensor arranged therein, and sensing of at least one borehole or formation parameter with the optical sensor.

It is further described in another aspect a method for determining flow characteristics of a fluid flowing through a casing string, which comprises supplying a casing string within a borehole comprising a deployment valve and at least one optical sensor connected thereto, measuring characteristics of fluid flowing through the casing string using at least one optical sensor, and determining at least one volumetric phase fraction for the liquid or flow rate for the liquid based on the properties of the measured liquid. An apparatus is further described for determining the flow characteristics of a liquid flowing through a casing string in a borehole, which comprises a casing string comprising a deployment valve; and at least one optical sensor coupled to the casing string for sensing at least a volumetric phase fraction of the fluid or a flow rate of the fluid through the casing string.

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

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is a sectional view of a wellbore having a casing string therein, the casing string including a wellbore deployment valve (DDV).

Figure 2A is an enlarged overview showing the DDV in more detail.

Figure 2B is an enlarged overview showing the DDV in a closed position.

Figure 3 is a sectional view of the borehole showing the DDV in a closed position. Figure 4 is a sectional view of the borehole showing tool strings inserted into an upper part of the borehole with the DDV in a closed position. Figure 5 is a sectional view of the borehole with tool strings inserted and DDV opened. Figure 6 is a schematic diagram of a control system and its relationship to a well having a DDV or an instrumentation transition connected to sensors. Figure 7 is a sectional view of a borehole showing the DDV of the present invention in use with a telemetry tool. Figure 8 is a sectional view of a wellbore having a casing string therein, the casing string including a wellbore deployment valve (DDV) in an open position with a seismic sensor disposed on the outside of the casing string. Figure 9 is a sectional view of the borehole showing a drill string inserted into an upper part of the borehole with the DDV in a closed position. Figure 10 is a sectional overview of the borehole with the drill string inserted and the DDV opened. A seismic source is located at a surface of the borehole. Figure 11 is a sectional view of the borehole with the drill string inserted and the DDV opened. A seismic source is located at a surface of the borehole. Figure 12 is a sectional view of the borehole with the drill string inserted and the DDV opened. A seismic source is located in a nearby borehole. Figure 13 is a cross-sectional overview of the DDV in Figures 1-6 with a flow meter arranged in the casing string.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Placing one or more seismic sensors outside of a casing string reduces the inherent fluid and casing string interference with signals that occur when the seismic sensors are present within the casing strings of the formation, thus allowing more accurate signals and the simplification of the connections of the seismic sensors to the formation. Quite accurate real-time measurements of seismic conditions and other parameters are thus possible during all borehole operations with the present invention. With the current invention, permanent seismic monitoring when placing the casing string within the borehole provides accurate measurements of seismic conditions before and after the production pipe is inserted into the borehole.

Sensors with deployment valves in wellbore

Figure 1 is a sectional view of a wellbore 100 with a casing string 102 disposed therein and held in place by cement 104. The casing string 102 extends from a surface of the wellbore 100 where a wellhead 106 will typically be located along some type of valve assembly 108 that controls fluid flow from the borehole 100 and is schematically shown. Disposed within the casing string 102 is a downhole deployment valve (DDV) 110 that includes a casing 112, a flap 230 having a joint 232 at one end, and a valve seat 242 in an inner diameter of the casing 112 proximate the flap 230. As described herein, DDV 110 is an important part of the casing string 102 and is driven into the borehole 100 along the casing string 102 before cementing. The cabinet 112 protects the components of the DDV 110 from being damaged during drive-in and cementing. The location of the flap 230 allows it to close upward wherein the pressure in a lower portion 120 of the borehole helps to hold the flap 230 in a closed position. DDV 110 also includes surface monitoring and control unit (SMCU) 107 to allow valve 230 to be opened and closed remotely from the surface of the well. As schematically illustrated in Figure 1, the accessories connected to the SMCU 107 include a mechanical type actuator 124 and a control line 126 that can carry hydraulic fluid and/or electrical voltage. Clamps (not shown) may hold the control line 126 adjacent to the casing string 102 at regular intervals to protect the control line 126.

Also shown schematically in Figure 1, an upper sensor 128 is placed in an upper part 130 of the borehole and a lower sensor 129 is placed in the lower part 120 of the borehole. The upper sensor 128 and the lower sensor 129 can determine a fluid pressure within an upper portion 130 and a lower portion 120 of the borehole, respectively. Similar to the upper and lower sensors 128, 129 shown, additional sensors (not shown) may be located in the housing 112 of the DDV 110 to measure any downhole condition or parameter such as a position of the casing 226, the presence or absence of a drill string, and borehole temperature. The additional sensors can determine a liquid composition such as the ratio of oil to water, oil to gas or gas to liquid. Furthermore, additional sensors can detect and measure a seismic pressure wave from a source located within the borehole, within a nearby borehole, or at the surface. Therefore, additional sensors can supply seismic information in real time. Figure 2A is an enlarged view of a portion of the DDV 110 showing the flap 230 and a sleeve 226 holding it in an open position. In one embodiment shown, flap 230 is initially held in an open position by sleeve 226 which extends downwardly to cover flap 230 and to ensure a substantially unobstructed inner diameter through DDV 110. A sensor 131 detects an axial position of sleeve 226 as shown in FIG. 2A and sends a signal through control line 126 to SMCU 107 that flap 230 is fully open. All sensors, such as the sensors 128,129,131 shown in Figure 2A, are connected by a cable 125 to the circuit panel 133 which is placed in the well in the cabinet 112 of the DDV 100. The power supply to the circuit panel and data transfer from the circuit panels 133 to the SMCU 107 is achieved via an electrical conductor in the control line 126. The circuit panels 133 have free channels to be able to add new sensors if necessary. The sensors 128, 129 and 131 may be optical sensors, as described below. Figure 2B is a sectional view showing the DDV 110 in a closed position. A flap engaging end 240 of a valve seat 242 in the housing 112 receives the flap 230 as it closes. As soon as the sleeve 226 is axially moved away from the valve 230 and the valve engaging end 240 of the valve seat 242, a biasing link 234 biases the flap 230 against the flap engaging end 240 of the valve seat 242. In the embodiment shown, the biasing link 234 is a spring that moves the flap 230 along an axis of a link 232 to the closed position. Common known methods of axially moving the casing 226 include hydraulic rams (not shown) operated by pressure supplied from the control line 126 and interactions with the drill string based on rotary or axial movements of the drill string. The sensor 131 detects the axial position of the sleeve 226 as it is moved axially within the DDV 110 and sends signals through the control line 126 to the SMCU 107. Therefore, the SMCU 107 reports on a display a percentage representing a partially opened or closed position of the flap 230 based on the position of the sleeve 226. Figure 3 is a sectional view showing the borehole 100 with the DDV 110 in the closed position. In this position, the upper portion 130 of the borehole 100 is isolated from the lower portion 120 and any pressure remaining in the upper portion 130 can be vented through the valve assembly 108 at the surface of the well as shown by the arrows. With the upper part 130 of the borehole free of pressure, the wellhead 106 can be opened for the safe performance of operations such as the addition or removal of tool strings. Figure 4 is a sectional view showing the borehole 100 with the wellhead 106 opened and a tool string 500 which has been inserted into the upper part 130 of the borehole. The tool string 500 may include devices, such as drill bits, drill bit motor, devices for measuring while drilling, rotary control devices, perforating systems, screen tubes and/or slotted screen tube systems. These are only a few examples of tools that can be arranged on a string and inserted into a well using the methods and apparatus of the present invention. Because the height of the upper part 130 is greater than the length of the tool string 500, the tool string 500 can be fully connected in the upper part 130 while the upper part 130 is isolated from the lower part 120 of the DDV 110 in the closed position. Finally, Figure 5 is a further overview of the borehole 100 showing the DDV 110 in the open position and the tool string 500 extended from the upper part 130 to the lower part 120 of

the borehole. In the illustration shown, a device (not shown), such as a mud scraper or rotary head at the wellhead 106, maintains pressure around the tool string 500 as it enters the borehole 100.

Before opening the DDV 110, fluid pressure in the upper part 130 and the lower part 120 of the borehole 100 at the flap 230 in the DDV 110 must be equalized or close to equalizing in order to effectively and safely open the flap 230. Since the upper part 130 is opened at the surface to able to insert the tool string 500 it will be at or near atmospheric pressure, while the lower part 120 will be at well pressure. Using means well known in the art, air or liquid in the upper portion 130 is mechanically pressurized to a level at or near the lower portion 120. Based on data from the sensors 128 and 129 and the SMCU 107, the pressure conditions and differentials in the upper portion 130 and the lower part 120 of the borehole 100 is precisely leveled before opening the DDV 110.

While the instrumentation, such as sensors, receivers and circuitry, is shown as an integral part of the housing 112 of the DDV 110 (See Figure 2A) in the examples, it will be understood that the instrumentation may be located in a separate "instrumentation transition" located in the casing string. As shown in Figure 6, the instrumentation transition can be hardwired to an SMCU 107 in a manner similar to running a dual hydraulic line control (HDLC) cable 126 from the instrumentation on the DDV 110. Therefore, the instrumentation transition utilizes sensors, receivers, and circuitry as described herein without using other components of the DDV 110, such as a flap and a valve seat.

Figure 6 is a schematic diagram of a control system and its relationship to a well having a DDV 110 or an instrumentation transition attached with sensors (also indicated by 110) as disclosed herein. Shown in Figure 1, the borehole that has the DDV 110 is arranged therein with the necessary electronics to operate the sensors discussed above (See Figure 1).

A conductor encased in a control line shown in Figure 6 as the dual hydraulic line control (HDLC) cable 126 provides communication between downhole sensors and/or receivers and a surface monitor and control unit (SMCU) 107. The HDLC cable 126 is extended from the DDV 110 on the outside of the casing string 102 (See Figure 1) containing the DDV 110, to an interface unit 180 of the SMCU 107. The SMCU 107 may include a hydraulic pump 185 and a series of valves used in the operation of the DDV 110 in fluid transfer through the HDLC 126, and to establish a pressure above the DDV 110 that is substantially equal to the pressure below the DDV 110. In addition, the SMCU 107 may include a programmable logic controller (PLC) system 181 for monitoring and controlling each valve and other parameters, circuitry for interfacing with downhole electronics, a card display 186, and standard RS-232 interface (not shown) for connecting external devices. In this arrangement, the SMCU 107 outputs information received from the sensors and/or receivers 182 in the borehole 100 to the display 186 or to the controls 183. Using the arrangement illustrated, the pressure differential between the upper part and the lower part of the borehole can 100 is monitored and adjusted to an optimal level for opening the valve. In addition to pressure information close to the DDV 110, the system may also include proximity sensors that describe the position of the sleeve 226 in the valve which is responsible for holding the valve in the open position. By ensuring that sleeve 226 is fully in the open or closed position, the valve can be operated more efficiently. The SMCU 107 may further include a power supply 184 for supplying power to operate the SMCU 107. A separate computing device such as a laptop PC 187 may also be connected to the SMCU 107.

Figure 7 is a sectional view of a borehole 100 with tool strings 700 that includes a telemetry tool 702 employed in the borehole 100. The telemetry tool 702 transmits the readings of the instruments to a remote location using radio waves or other means. In an embodiment shown in Figure 7, the telemetry tool 702 uses electromagnetic (EM) waves 704 to transmit wellbore information to a remote location, in this case a receiver 706 located in or near an enclosure of a DDV 110 rather than at a surface of the borehole. Alternatively, the DDV 110 may be an instrumentation transition that includes sensors, receivers, and circuitry but does not include other components of the DDV 110 such as a valve. The EM wave 704 can be any form of electromagnetic radiation, such as radio waves, gamma rays, or X-rays. The telemetry tool 702 arranged in the pipe string,

700 near the drill bit 707, transmits data related to the location and face angle of the drill bit 707, hole inclination, wellbore pressure or other variables. The receiver 706 converts the EM waves 704 that it receives from the telemetry tool 702 into an electrical signal that is fed to a circuitry in the DDV 110 via a short cable 710. The signal goes to the SMCU via a conductor in a control line 126. Similarly, an electrical signal from the SMCU is sent to the DDV 110 which can then send an EM signal to the telemetry tool 702 to provide two-way communication. Using the telemetry tool 702 in conjunction with the DDV 110 and its existing control line 126 connecting it to the SMCU at the surface increases the reliability and performance of the telemetry tool 702 since the EM waves 704 do not need to be transmitted as far through formations. Therefore, embodiments of this invention will provide for communication with downhole devices, such as a telemetry tool 702, which is located below the formations containing an EM barrier. Examples of downhole tools used in conjunction with the telemetry tool 702 include a measurement-while-drilling (MWD) tool or a pressure-while-drilling (PWD) tool.

Expandable sand sieve tubes

Yet another area of application of the apparatus and methods of the present invention relates to the use of an expandable sand screen tube or ESS and the real-time measurement of pressure required for expansion of the ESS. Using the apparatus or methods of the present invention with sensors incorporated in an extension tool and data transmitted to an SMCU 107 (See Figure 6) via a control line connected to a DVV or instrumentation junction having circuit panels, sensors, and receivers therein, press and around the expansion tool, can be monitored and adjusted from one surface of a borehole. In use, the DDV or instrumentation transition receives a signal similar to the signal described in Figure 7 from the sensors incorporated in the expansion tool, processes the signal with the circuit boards, and sends data related to pressure in and around the expansion tool to the surface through the control line. Based on 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.

Optical sensors with wellbore deployment valves

Figure 8 shows an alternative embodiment of the present invention which presents a sectional overview of the casing string 102 arranged within the borehole 100 and employed therein by cement 104. As in Figure 1, the casing string 102 is extended from the surface of the borehole 100 from within the wellhead 106 with the valve assembly 108 for controlling the flow of fluid from the wellbore 100. A downhole deployment valve (DDV) 310 is disposed within the casing string 102 and is an integral part of the casing string 102. The DDV 310 includes a casing 312, a flap 430 having a joint 432 at one end, and a valve seat 442 formed within the inner diameter of housing 312 adjacent flap 430. Flap 430, joint 432, and valve seat 442 operate in the same manner and have the same characteristics as flap 230, joint 232, and valve seat 242 of Figures 1-6, so that the above descriptions of the operation and the characteristics of the components apply equally to the embodiments in Figures 8-12.

In particular, the flap 430 is used to separate the upper part of the borehole 130 from the lower part of the borehole 120 at various stages of the operation. A sleeve 226 (See Figure 2A) is used to hold flap 430 in an open position by extending downwardly to cover flap 230 and ensure a substantially unobstructed inner diameter through DDV 310.

Located within the housing 312 of the DDV 310 is an optical sensor 362 for measuring conditions or parameters within a formation 248 or the wellbore, such as temperature, pressure, seismic conditions, acoustic conditions, and/or fluid composition in the formation 248, including the oil to water ratio , oil to gas, or gas to liquid. The optical sensor 362 may include any suitable type of optical sensing elements such as those described in U.S. Patent No. 6,422,084, which is incorporated herein by reference in its entirety. For example, the optical sensor 362 may comprise an optical fiber having the reflective element encapsulated therein; and a tube having the optical fiber and the reflective element clad therein along a longitudinal axis of the tube, the tube being fused to at least a portion of the fiber. Alternatively, the optical sensor 362 may comprise a large diameter optical waveguide having an outer sheath and an inner core disposed therein.

The optical sensor 362 may include a pressure sensor, temperature sensor, acoustic sensor, seismic sensor, or other probes or sensors that take temperature or pressure measurements. In one embodiment, the optical sensor 362 is a seismic sensor. The seismic sensor 362 detects and measures seismic pressure-acoustic waves 401, 411, 403, 501, 511, 503, 601, 611, 603 in Figures 10-12) emitted from a seismic source 371, 471, 571 located within the borehole 100 at a location such as a drill string 305 (See Figure 10) at the surface of the borehole 100 (See Figure 11) or in a nearby borehole 700 (See Figure 12). The operation and construction of a Bragg grating sensor that can be used with the present invention is described in jointly owned U.S. Patent No. 6,072,567 entitled "Vertical Seismic Profiling System Having Vertical Seismic Profiling Optical Signal Processing Equipment and Fiber Bragg Grating Optical Sensors" published June 6, 2000 , which is incorporated herein by reference in its entirety.

The construction and operation of optical sensors suitable for use with the present invention, in the embodiment of an FBG sensor, is described in U.S. Patent No. 6,597,711 published July 22, 2003 entitled "Bragg Bending Grating-Based Laser" which is incorporated herein by reference in its entirety. Each Bragg grating is designed to reflect a particular wavelength or frequency of light that propagates along the core, back in the direction of the light source from which it came. In particular, the wavelength of the Bragg grating is shifted to feed the sensor.

Another suitable type of optical sensor for use with the present invention is an FBG-based inferometric sensor. One embodiment of an FBG-based inferometric sensor that can be used as the optical sensor 362 of the present invention is described in US Patent No. 6,175,108, published January 16, 2001, entitled "Accelerometer Having Fiber Optic Bragg Grating Sensor to Provide Multiplex, Multi-Axis Acceleration Sensing." which is incorporated herein by reference in its entirety. The inferometric sensor includes two FBG wavelengths separated by a length of fiber. When the length of fiber changes between the two wavelengths, a change in the arrival time of the light reflected from one wavelength to the other wavelength is measured. The change in arrival time indicates the borehole or formation parameter.

The DDV 310 also includes a surface monitoring and control unit (SMCU) 251 to allow the flap 430 to be opened and closed remotely from the well surface. The SMCU 251 includes accessories of a mechanical-like actuator 324 and a control line 326 to transmit hydraulic fluid and/or electrical voltages. The SMCU 251 processes and reports seismic information collected by the seismic sensor 362 on a display.

An optical line 327 is connected to one end of the optical sensor 362 and the other end to the SMCU 251 and may include a processing unit for converting the signal transmitted through the optical line 327 into meaningful data. The optical line 327 is in optical communication with the optical sensor 362 as well as the SMCU 251 having optical signal processing equipment. One or more control line protectors 361 are positioned on the casing string 102 to house and protect the control line 326 as well as the optical line 327 .

Any number of additional seismic sensors 352 (or other types of optical sensors such as a pressure sensor, temperature sensor, acoustic sensor, etc.) may be located on the casing string 102 at intervals above the seismic sensor 362 to provide additional locations such as the seismic source 371, 471 , 571 can transmit acoustic waves (not shown). When using additional seismic sensors 352, 356, the optical line 327 is run into the seismic sensors 352, 356 on its way from the seismic sensor 362 to the SMCU 251. Seismic sensor carriers 353, 357 (for example, metal pipes) may be arranged around the seismic the sensors 352, 356 to protect the seismic sensors 353, 356 as well as the control line 326 and the optical line 327.

Measurement during drilling

Figure 9 shows the valve 430 in the closed position, the wellhead 106 open, and a drill string 305 employed in the borehole 100. The drill string 305 is pipe strings or tool strings with a soil removal joint 306 operatively connected to its lower end. A flap engaging end 240 (See Figure 2A) of a valve seat 442 in the housing 312 is located on the opposite side of the flap 430.1 the position of the flap 430 depicted in Figure 9 a biasing link 234 (See Figure 2A) biases the flap 430 against the valve seat 442.1 an embodiment shown in Figure 2A, the bias link 234 is a spring. Figures 10-12 show the DDV 310 in an open position and the drill string 305 extended from the upper portion 130 to the lower portion 120 of the borehole 100. Figure 10 shows a seismic source 371 located within the drill string 305, with acoustic waves 401 and 411 emitted from the seismic source 371 into the formation 248, and then reflected or partially reflected from the formation 248 into the seismic sensor 362. In a similar manner, Figure 11 shows a seismic source 471 located at the surface of the borehole 100, with acoustic waves 501 and 511 emitted from the seismic source 471 into the formation 248, and then reflected or partially reflected from the formation 248 into the seismic sensor 362. Figure 12 shows a seismic source 571 that is located in a nearby borehole 700, with acoustic waves 601 and 611 also emitted from the seismic source 571 into the formation 248, and then reflected or partially reflected from the formation 248 into the seismic sensor 362. In an al Alternatively, the vibration of the drill string 305 itself or another downhole tool may act as the seismic source when it vibrates against the borehole or the casing in the borehole. The seismic sources 371, 471 and 571 in Figures 10-12 all transmit an acoustic wave 403, 503 or 603 directly to the seismic sensor 362 for calibration purposes.

In use, the casing string 102 with DDV 310 is arranged thereon, lowered into the drilled borehole 100 through the open wellhead 106 and cemented therein with cement 104. Initially, the flap 430 is held in the open position by the sleeve 226 (See Figure 2A) to ensure an unobstructed borehole 100 for fluid circulation during run-in of the casing string 102. Figure 8 shows the casing string 102 and DDV 310 cemented within the borehole 100 with the flap 430 in the open position.

When it is desired to drive the drill string 305 into the borehole 100 to drill to a further depth within the formation 248, the flap 430 is closed. The drill string 305 is employed in the wellhead 106. Figure 9 shows the flap valve 430 closed and the drill string 305 is employed in the borehole 100.

The wellhead 106 is then closed to atmospheric pressure from the surface. The DDV 310 flap 430 is opened. The drill string 305 is then lowered into the lower portion 120 of the borehole 100 and then further lowered to drill into the formation 248. Figures 10-12 depict three different configurations for transferring formation conditions to the surface while the drill string 305 is drilled into the formation 248. Formation conditions can also be transmitted to the SMCU 251 before or after the drill string 305 has been drilled into the formation.

In Figure 10, while the drill string 305 is drilled into the formation 248, the seismic source 371 transmits acoustic waves 401, which return from location 400 in the formation 248 to the seismic sensor 362. Alternatively, the seismic source can be activated when the drill string 305 is stationary (not drills), for example by forcing fluid through the drill string through a transducer that emits acoustic energy. The seismic source 371 also transmits acoustic waves 411 returning from location 410 in the formation 248 to the seismic sensor 362. The seismic source 371 also transmits acoustic waves 403, which return directly to the seismic sensor 362. The direct transmission of acoustic waves 403 is necessary to process the aggregated information and interpret the final image by deriving the distance between the drill bit and the seismic sensor 362 plus the travel time to calibrate the acoustic waves 401 and 411. Because the acoustic waves 401 and 411 must travel to the formation 248 and then to the seismic sensor 362, a time delay exists. To equalize the acoustic waves 401 and 411 with the time delay, the direct acoustic wave 403 can be measured without the time delay caused by the reflection of the formation 248. The additional seismic sensors 352 and 356 on the outside of the casing string 102 can also receive acoustic waves (not shown) coming back from formation 248 at various locations. Any number of acoustic waves may be emitted by each seismic source 371, 352, 356 at any angle with respect to the formation 248 and at any location within the formation 248. Additional acoustic waves are shown emitted from the seismic source 371 at varying angles to varying locations.

After the acoustic waves 401, 411 and 403 (and any acoustic waves from the additional seismic sensors 352 and 356) are transmitted into the formation 248 to the seismic source 371 and then reflected or partially reflected to the seismic sensor 362, the aggregate information is transmitted through an optical cable 327 to the SMCU 251. The SMCU 251 processes the information received through the optical cable 327. The operator can read the information produced by the SMCU 251 and adjust the position and drilling direction or path of the drill string 305, the composition of the drilling fluid introduced through the drill string 305 and other parameters during drilling. An alternative could be for data to be interpreted at an off-site data processing centre.

Figure 11 shows an alternative embodiment of the current invention. In this embodiment, vertical seismic profiling in front of the soil removal joint 306 of the drill string 305 is performed by a seismic source 471 emitted from the surface of the borehole 100, rather than from the soil removal joint 306. The seismic source 471 emits acoustic waves 501 that return from the formation 248 at location 500 to the seismic sensor 362. Seismic source 471 also emits acoustic waves 511, which return from formation 248 at location 510 to seismic sensor 362. Seismic source 471 emits acoustic waves 503, which travel through a direct path to seismic sensor 362 without to return from the formation 248. Acoustic wave 503 is used for calibration purposes as described above in relation to acoustic waves 403 of Figure 10. The additional seismic sensors 352 and 356 on the outside of the casing string 102 may also receive acoustic waves (not shown) which are returned from formation 248 at various locations. Any number of acoustic waves may be emitted by each seismic source 471, 352, 356 at any angle with respect to the formation 248 and at any location within the formation 248 and transmitted to the seismic sensor 362. The information collected by the seismic sensor 362 is transmitted to the SMCU 251 through the optical cable 327, and the rest of the operation is the same as the operation described in relation to Figure 10.

Figure 12 shows a further alternative embodiment of the current invention. Here, the seismic source 571 is emitted from a nearby borehole 700. The borehole 700 is shown with casing 602 cemented therein with cement 604. The seismic source 571 is shown located in the annular area between the casing 602 and the borehole 700, but may be located anywhere preferably within the adjacent borehole 700 for use in relation to the present invention. Specifically, the seismic source 571 may, among other possibilities, be disposed on a tubing string (not shown) within the adjacent wellbore 700. Similar to the operation of the embodiment of Figures 10-11, the seismic source 571 emits acoustic waves 601 into the location 600. in the formation 248, which returns from the formation 248 to the seismic sensor 362. The seismic source 571 emits acoustic waves 611 into the location 610 in the formation 248, and the acoustic wave 611 returns from the formation 248 to the seismic sensor 362. The acoustic the wave 603 is transmitted directly from the seismic source 571 to the seismic sensor 362 for calibration purposes as described above in relation to Figures 10-11. The additional seismic sensors 352 and 356 on the exterior of the casing string 102 may also receive acoustic waves (not shown) returning from the formation 248 at various locations. Any number of acoustic waves may be emitted by each seismic source 371, 352, 356 at any angle with respect to the formation 248 and at any location within the formation 248 for reception by the seismic sensor 362. The information collected by the seismic sensor 362 is transmitted to the SMCU 251 through an optical cable 327, and the rest of the operation is the same as the operation described in relation to figure 10.

In another aspect of the present invention, optical sensors may be used in embodiments of the DDV, shown in Figures 1-6, to measure the differential pressure across the deployment valve in the wellbore. An optical sensor can also be used to measure the position of the flap valve of the deployment valve in the wellbore. An FBG can be connected to the flap via a voltage-inducing link, so that the movement of the flap valve induces a voltage on the FBG. The voltage on the FBG can result in a change in the FBR wavelength indicating the position of the flap valve. The optical-seismic, pressure, temperature, or acoustic sensors shown and described in relation to Figures 8-12 can also be used in combination with the optical sensors used in Figures 1-6 to measure differential pressure along the DDV.

Although the above descriptions of Figures 8-12 were planned with the use of a seismic sensor 362 within the DDV 310, an optical pressure sensor (not

shown) or temperature sensor (not shown) is also used with the DDV 310 of the above figures to measure temperature or pressure within the formation 248 or the borehole 100. The present invention can be used in seismic profiling of vertical or cross-wells in 2D, 3D or 4D or continuous seismic monitoring, such as microseismic monitoring. VSP can be obtained when the seismic source is located at the surface by moving the seismic source to accumulate the entire image of the formation. Crosswell seismic profiling can be achieved when the seismic source is located in a nearby borehole by moving the seismic source to accumulate a complete image of the formation.

The embodiments depicted in Figures 8-12 may also be useful for calibrating surface seismic data after the casing string has been placed at a known depth within the borehole. Furthermore, as described above, the present invention provides real-time seismic data while drilling into the formation, including imaging ahead of the drill string and predicting pore pressure. The measurements from the acoustic waves sent to the SMCU can be used in geomanaging to align the seismic image and update seismic data first obtained by seismic measurement of current conditions while drilling into the formation. Geosteering allows the operator to decide in which direction to steer the string to drill to that particular part of the formation. The information gathered by the seismic sensor can be placed into models to determine formation conditions in real time.

The above embodiments are also useful in performing acoustic monitoring while drilling into the formation, including monitoring the vibration of the drill string and/or soil removal joint against the casing in the borehole, along with monitoring the vibration of other tools and downhole components against the casing within the borehole, monitoring acoustics of drilling fluids introduced in the drill string into the formation, and monitoring acoustics within a nearby borehole.

Embodiments of the present invention are useful not only for obtaining real-time seismic data, but also for providing monitoring of seismic conditions after the well has been drilled, including, but not limited to, microseismic monitoring and other acoustic monitoring during the production of hydrocarbons within the well. Microseismic monitoring allows the operator to detect, evaluate and locate small fracturing events related to production operations, such as those caused by the movement of hydrocarbon fluids or by the subsidence or compaction of the formation. After the well has been drilled, the current invention can also be used to obtain seismic information from a nearby borehole.

Flow meter

Other parameters can be measured using optical sensors according to the present invention. A flow meter 875 may be included as part of the casing string 102 to measure volumetric fraction of individual phases of a multiphase mixture flowing through the casing string 102, as well as to measure flow rates of components of the multiphase mixture. Obtaining these measurements allows monitoring of the substances removed from the borehole while drilling, as described below.

In particular, when using optical sensors such as the upper and lower sensors 128 and 129 and additional sensors (not shown) to measure the position of the casing 226 or other wellbore parameters as described in relation to Figures 1-6, a flow meter may be provided within the casing string 102 above or below the DDV 110. In figure 13, the flow meter 875 is shown above the DDV 110. The DDV 110 has the same components and operates in the same way as described above in relation to figures 1-6, so that like components are marked with like numbers in figures 1 -6. The casing string 102, which has an inner surface 806, and an outer surface 807, is shown installed within a borehole 100 drilled out of a formation 815. The casing pipe string 102 is installed within the borehole 100 using cement 104.

The wellhead 106 with the valve assembly 108 can be positioned at the surface 865 of the borehole 100. Various tools, including a drill string 880 can be lowered through the wellhead 106. The drill string 880 includes a pipe 882 having a soil removal joint 881 connected to its lower end. The soil removal joint 881 has passages 883 and 884 therethrough for use in circulating drilling fluid F1 while drilling into the formation 815 (See below).

An SMCU 860 which is the same as SMCU 251 in Figures 8-12 as well as SMCU 107 in Figures 1-7 is also present at surface 565. SMCU 860 may include a light source, delivery equipment and a logic control unit, including optical signal processing as described above. An optical cable 855 which is substantially the same as the optical line 327 in Figures 8-12 is connected to one end of the SMCU 860.

The flowmeter 875 may be substantially the same as the flowmeter described in a pending U.S. patent application serial number 10/348,040 entitled “Non-Intrusive Flowmeter” and filed January 21, 2003, which is incorporated herein by reference in its entirety. Other flow meters may also be useful in conjunction with the present invention. The flowmeter 875 allows volumetric fractions of individual phases of a multiphase mixture flowing through the casing string 102 to be found, as well as flow rates of individual phases of the multiphase mixture. The volumetric fractions are determined using a mixture density and sound speed of the mixture. The mixture density can be determined by direct measurement from a density meter or based on a measured pressure differential between two vertically offset measurement points (shown as P1 and P2) and a measured mass velocity of the mixture as described in the patent application incorporated above for reference. Various equations are used to calculate the flow rate and/or component fractions of the fluid flowing through the casing string 102 using the above parameters, as disclosed and described in the application incorporated above.

In one embodiment, the flow meter 875 may include a velocity sensor 891 and sound velocity sensor 892 for measuring volume velocity and sound velocity of the fluid, respectively, up through the inner surface 806 of the casing string 102. These parameters are used in equations to calculate the flow rate and/or phase fractions of the fluid. . As illustrated, sensors 891 and 892 may be integrated into single flow sensor assembly (FSA) 893. Alternatively, sensors 891 and 892 may be separate sensors. The velocity sensor 891 and sound velocity sensor 892 of the FSA 893 may be similar to those described in jointly owned U.S. Patent No. 6,354,147, entitled "Fluid Parameter Measurement in Pipes Using Acoustic Pressures", issued March 12, 2002 and incorporated herein by reference.

The flow meter 875 may also include combined pressure and temperature (P/T) sensors 814 and 816 around the outer surface 807 of the casing string 102, where the sensors 814 and 816 are similar to those described in detail in jointly owned US Patent No. 5,892,860 entitled “Multi-Parameter fiber optic sensor for use in harsh environments" issued April 6, 1999 and is incorporated herein by reference. As an alternative, the pressure and temperature sensors can be separate from each other. Furthermore, for some embodiments, the flow meter 875 may use an optical differential pressure sensor (not shown). The sensors 891, 892, 814 and/or 816 can be connected to the casing string 102 using methods and devices described in relation to connecting the sensors 30, 130, 230, 330, 430 to the casing strings 5, 105, 205, 305, 405 in the figures 1-5 of patent pending US patent application serial number 10/676,376 having legal summary number WEAT/0438 entitled “Permanent Deployment of Optical Sensors in a Wellbore” filed on the same date as the current application, which is incorporated herein by reference in its entirety.

The optical cable 855, as described above in relation to Figures 8-12, may include one or more optical fibers to communicate with the sensors 891, 892, 814, 816. Depending on a particular arrangement, the optical sensors 891, 892, 814 may , 816 is distributed on a common fiber or distributed among several fibers. The fibers can be connected to other sensors (eg, further down the wellbore), disconnected, or connected back to the SMCU 860. The flow meter 875 can also include any suitable combination of peripheral elements (eg, optical cable connectors, splitters, etc.) well known in the art for connecting fibres. Furthermore, the fibers can be covered with protective coatings and can be deployed in fiber delivery equipment which is also well known in the art.

The embodiments of the flow meter 875 may include various arrangements of pressure sensors, temperature sensors, velocity sensors, and sound speed sensors. Thus, the flowmeter 875 may include any suitable array of sensors to measure differential pressure, temperature, volume velocity of the mixture, and speed of sound in the mixture. The methods and apparatus described herein can be used to measure individual component fractions and flow rates of a wide variety of liquid mixtures in various applications. Multiple flow meters 875 may be used with the casing string 102 to measure the flow rate and/or phase fractions of various locations along the casing string 102 .

For some embodiments, a conventional densitometer (such as a nuclear liquid densitometer) may be used to measure the density of the mixture illustrated in

Figure 2B of the above application which is incorporated (Serial number 10/348,040) and described therein. However, in different embodiments, the density of the mixture can be determined, based on a measured differential pressure between two vertically displaced measurement points and a volume velocity of the liquid mixture, also described in the above-incorporated application (Serial No. 10/348,040).

In use, the flow meter 875 is placed within the casing string 102, for example by means of a threaded connection to other casing parts. The borehole 100 is drilled to a first depth with a drill string (not shown). The drill string is then removed. The casing string 102 is then lowered into the drilled borehole 100. Cement 104 is sent into the inner diameter of the casing string 102, which then flows out through the lower end of the casing string 102 and up through the annular space between the outer surface 807 of the casing- the string 102 and the inner diameter of the borehole 100. The cement 104 is cured under hydrostatic conditions to permanently set the casing string 102 within the borehole 100.

Henceforth, the flowmeter 875 is permanently installed within the wellbore 100 within the casing string 102 and is capable of measuring fluid flow and component fractions present in the fluid flowing through the inner diameter of the casing string 102 during wellbore operations. At the same time, the DDV 110 operates as described above to open and close when the drill string 880 functions as the tool 500 (See Figures 1-6) inserted into the wellbore 100, and the optical sensors 128, 129, 131 can sense the wellbore and formation conditions as well as the position of sleeve 226, as described above in relation to Figures 1-6.

Often the borehole 100 is drilled to a second depth within the formation 815. As described above in relation to Figure 5, the drill string 880 of Figure 13 is inserted into the casing string 102 and is used to drill into the formation 815 to a second depth. During the drilling process, it is customary to introduce drilling fluid F1 into the drill string 880. The drilling fluid F1 flows down through the drill string 880 as indicated by the arrows marked F1, and then out through the passages 883 and 884. After exiting the passages 883, 884, the drilling fluid is mixed F1 with the particulates, including drilling cuttings produced from the borehole in the soil formation 815, which then carries the particulates, including the drilling cuttings, to the surface 865 using the fluid mixture F2, which includes the drilling fluid F1 and the particulates. The fluid mixture F2 flows to the surface 865 through an annulus between the outer diameter of the drill string 880 and the inner surface 806 of the casing string 102, as indicated by the marked arrows F2. The drilling fluid F1 is usually introduced to be able to clean the borehole 100 of the drill cuttings and to facilitate the path of the drill string 880 through the formation 815 during the drilling process.

As the fluid mixture F2 circulates up through the annulus between the drill string 880 and the casing string 102, the flow meter 875 can be used to measure the flow rate of the fluid mixture F2 in real time. Furthermore, the flow meter 875 can be used to measure in real time the component fractions of oil, water, sludge and/or particulate matter, including drilling cuttings, which flow up through the annulus in the liquid mixture F2. Specifically, the optical sensors 891, 892, 814, and 816 transmit the measured borehole parameters up through the optical cable 855 to the SMCU 860. The optical signal processing portion of the SMCU 860 calculates the flow rate and component fractions of the fluid mixture F2, as described in the above incorporated application (Serial No. 10/348,040) using equations and algorithms published in the above application. This process is repeated for additional drill strings and casing strings.

By using the flow meter 875 to obtain real-time measurements during drilling, the composition of the drilling fluid F1 can be changed to optimize drilling conditions and the flow rate of the drilling fluid F1 can be adjusted to provide the desired composition and/or flow rate of the fluid mixture F2. In addition, real-time measurements during drilling may prove useful in indicating the amount of cuttings coming to the surface 865 of the borehole 100, particularly by measuring the amount of cuttings present in the fluid mixture F2 as it flows up through the annulus using the flow meter 875, and then measure the amount of cuttings present in the fluid exiting to the surface 865. The composition and/or flow rate of the drilling fluid F1 can then be adjusted during the drilling process to ensure, for example, that the cuttings do not accumulate within the borehole 100 and obstruct the path of the drill string 880 through the formation 815.

While the sensors 891, 892, 814, 816 are preferably disposed around the outer surface 807 of the casing string 102 it is within the scope of the invention for one or more of the sensors 891, 892, 814, 816 to be placed around the inner surface of the casing string 102 or encapsulated within the casing string 102. In one application of the present invention, temperature, pressure and flow rate measurements obtained by the above embodiments can be used to determine when an underbalance! conditions are achieved within borehole 100.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of this invention may be contemplated without departing from its basic scope and the scope thereof is determined by the patent claims as follows:

Claims (10)

1. Method for measuring borehole or formation parameters, characterized in that it comprises: - placing a wellbore tool within a borehole (100), where the wellbore tool comprises: - a casing string (102), where at least part of the casing string comprises a wellbore deployment valve (310); and - an optical sensor (362) arranged on the casing string; - cementing the casing string within the borehole; and - lowering a drill string (305) into the borehole while borehole or formation parameters are sensed with the optical sensor. 2. Method according to claim 1, further comprising adjusting a path for the drill string while lowering the drill string into the drill hole. 3. Method according to claim 1, further comprising adjusting a composition or amount of drilling fluid while lowering the drill string into the borehole. 4. Apparatus for monitoring the conditions in a borehole or a formation, characterized in that it comprises: - a casing string cemented in the borehole, where at least part of the casing string comprises a wellbore deployment valve for selective prevention of a fluid path through the casing string; and -at least one optical sensor arranged on the casing string for tracking one or more parameters within the borehole or formation; and -a control line (326) substantially parallel to an optical line (327) connecting a surface monitoring and control unit (251) to the wellbore deployment valve, wherein at least a portion of the control line and the optical line are protected by at least one enclosure ( 312) placed around the casing string. 5. Apparatus according to claim 4, where the at least one optical sensor comprises a seismic sensor, acoustic sensor, pressure sensor or temperature sensor. 6. Procedure for permanent monitoring of at least one borehole or formation parameter, characterized in that it comprises the steps: - placing a casing string (102) in a borehole (100), where at least part of the casing string comprises a wellbore deployment valve (310) with at least one optical sensor (362) arranged therein, in which the wellbore deployment valve is an integral part of the casing string; - cementing the casing string in the borehole; -controlling the deployment valve between closed and open positions, wherein the closed position essentially prevents a bore in the casing string and the open position provides a passage for a tool to be passed through the bore; and sensing at least one borehole or formation parameter using the optical sensor. 7. Method according to claim 6, where the at least one optical sensor comprises a seismic sensor, acoustic sensor, pressure sensor or temperature sensor. 8. Method according to claim 6, where the casing string further comprises a flow meter (875) and where the flow meter senses a fluid flow rate or a composition of the fluid. 9. Procedure for determining flow characteristics for a fluid flowing through a casing string, characterized in that it comprises the steps of: - providing a casing string cemented within a wellbore, wherein the casing string comprises a wellbore deployment valve and at least one optical sensor coupled thereto, wherein the wellbore deployment valve is an integral part of the casing string: - measuring properties of fluids flowing through the casing string using the at least one optical sensor; and determining at least one of the fluid's volumetric phase fraction or the fluid's flow rate on the basis of the measured fluid properties. 10. Apparatus for determining the flow characteristics of a fluid flowing through a casing string in a borehole, characterized in that it comprises: - a casing string cemented in the borehole, where the casing string comprises a wellbore deployment valve, in which the wellbore deployment valve is an integral part of the casing string; and -at least one optical sensor connected to the casing string for sensing at least one of the fluid's volumetric phase fraction or the fluid's flow rate through the casing string.