Optical fiber's gigabit bandwidth, 200 km range attractive for subsea work

Fiber Optics encompasses the transmission of light through fibers or thin rods of glass or some other transparent material with a high refractive index. Light that enters one end of a fiber can travel through the fiber with very low loss, even if the fiber is curved. Images can be transmitted, as can data. The fiber optics itself can be used as a sensor for variations in environmental parameters such as temperature and pressure.

The Principle - Total Internal Reflection

Light traveling inside the fiber center (core) strikes the outside surface at an angle of incidence that is greater than the critical angle. Consequently, all this light is reflected toward the inside of the fiber without loss. Light can therefore be transmitted over long distances by being reflected inward thousands of times. In order to avoid losses through the scattering of light by impurities on the surface of the fiber, the optical fiber core is clad with a glass layer of much lower refractive index and the reflections occur at the interface of the glass fiber and the cladding. This avoids losses caused by scattering of light by impurities on the fiber surface.

Bundles of several thousand very thin fibers assembled precisely side by side and optically polished at their ends can be used to transmit images. Each point of the image projected on one face of the bundle is reproduced at the other end of the bundle, reconstituting the image, which can be observed through a magnifier. Image transmission by optical fibers is widely used in medical instruments for viewing inside the human body and for laser surgery, in facsimile systems, in phototypesetting, in computer graphics, and in many other applications.

Optical fibers are used in numerous sensing devices, ranging from thermometers to gyroscopes. The transmitted light is sensitive to environmental changes, including pressure, sound waves, and strain, as well as heat and motion. The fibers can be especially useful where electrical effects could make ordinary wiring useless, less accurate, or even hazardous. Fibers have also been developed to carry high-power laser beams for cutting and drilling. Petroleum applications include sensors.

In addition to sensing environmental variations, fiber optics can be used to transmit the measurements to the surface. Because the information-carrying capacity of a signal increases with frequency, the use of laser light offers many advantages. Fiber-optic laser systems are being used in communications networks. Long distances (100 km) can be achieved before signal repeaters are needed to regenerate signals.

History of Fiber Optics

While it may not be of critical need to you in your day-to-day operations, the following chronology is light and informative reading, documenting the exponentially accelerating technology.

· Alexander Graham Bell patented an optical telephone system, the Photophone, in 1880. Since then, technologies that would make optical transmission possible have developed.

· In the 1840s, Daniel Collodon and Jacques Babinet showed that light could be guided along jets of water for fountain displays.

· British physicist John Tyndall popularized light guiding in a demonstration he first used in 1854, guiding light in a jet of water flowing from a tank.

· By the 1900s, inventors realized that bent quartz rods could carry light, and patented them as dental illuminators

· During the 1920s, John Logie Baird in England and C.W. Hansell in the United States patented the idea of using arrays of hollow pipes or transparent rods to transmit images for television or facsimile systems.

· In a 1930 paper, Heinrich Lamm demonstrated image transmission through a bundle of optical fibers. He reported transmitting the image of a light bulb filament through a short bundle.

· In 1951, Holger Møller Hansen applied for a Danish patent on fiber-optic imaging. It was denied, citing the Baird and Hansell patents.

· In 1954, A. van Heel (Technical University of Delft) and H. H. Hopkins and N. Kapany (Imperial College) separately announced imaging bundles in Nature. These bundles could not carry light far. All earlier fibers were "bare," with total internal reflection at a glass-air interface. van Heel covered a bare fiber of glass or plastic with a transparent cladding of lower refractive index. This protected the total reflection surface from contamination, and greatly reduced crosstalk between fibers.

· L. Curtiss (University of Michigan) developed glass-clad fibers while working on an endoscope to examine the inside of the stomach (with physician B. Hirschowitz, and physicist C.W. Peters).

· W. Hicks, (American Optical Co.) made glass-clad fibers at about the same time, but his group lost a bitterly contested patent battle.

· By 1960, glass-clad fibers had attenuation of about one decibel per meter. This was adequate for medical imaging, but much too high for communications.

· Telecommunications engineers were seeking more transmission bandwidth (e.g., A. Reeves, at Britain's Standard Telecommunications Laboratories).

· Serious work on optical communications accelerated with introduction of the continuous wave helium-neon laser.

· By 1965, it was clear that major technical barriers remained for both millimeter-wave and laser telecommunications. Millimeter waveguides had low loss, although only if they were kept precisely straight; developers thought the biggest problem was the lack of adequate repeaters. Optical waveguides were proving to be a problem. S. Miller's group at Bell Telephone Laboratories was working on a system of gas lenses to focus laser beams along hollow waveguides for long-distance telecommunications.

· Optical fibers were shown to be analogous in theory to plastic dielectric waveguides that were used in certain microwave applications. In 1961, E. Snitzer (American Optical Co.) and W. Hicks (Mosaic Fabrications, now Galileo Electro-Optics) demonstrated the similarity by drawing fibers with cores so small that they carried light in only one waveguide mode.

· C.K. Kao (Standard Telecommunications Laboratories) evaluated fiber attenuation. He collected samples from fiber makers, and carefully investigated the properties of bulk glasses. His research convinced him that the high losses of early fibers were due to impurities, not to silica glass itself.

· Kao and G. Hockham conceived methods for long-distance communications over single-mode fibers (with fiber loss below 20 decibels per kilometer) - a glass core about three or four microns in diameter, clad with a coaxial layer of another glass having a refractive index about one percent smaller than that of the core. Total diameter of the waveguide is between 300 and 400 microns. Surface optical waves are propagated along the interface between the two types of glass – flexible but strong.

· F. F. Roberts, at the British Post Office Research Laboratory raised a new research fund of 12 million pounds to study ways to decrease fiber loss.

· At the Corning Glass Works (now Corning Inc.), R. Maurer, D. Keck and P. Schultz started with fused silica, a material that can be made extremely pure, but has a high melting point and a low refractive index. They made cylindrical preforms by depositing purified materials from the vapor phase, adding carefully controlled levels of dopants to make the refractive index of the core slightly higher than that of the cladding, without raising attenuation dramatically.

· In September 1970, they announced they had made single-mode fibers with attenuation at the 633-nanometer helium-neon line below 20 dB/km.

· In the same year, Bell Labs and a team at the Ioffe Physical Institute in Leningrad made the first semiconductor diode lasers able to emit continuous waves at room temperature. Over the next several years, fiber losses dropped dramatically, aided both by improved fabrication methods and by the shift to longer wavelengths where fibers have inherently lower attenuation.

· Early single-mode fibers had cores several micrometers in diameter, and in the early 1970s that bothered developers. They doubted that it would be possible to achieve the micrometer-scale tolerances needed to couple light efficiently into the tiny cores from light sources, or in splices or connectors. Not satisfied with the low bandwidth of step-index multimode fiber, they concentrated on multi-mode fibers with a refractive-index gradient between core and cladding, and core diameters of 50 or 62.5 micrometers. The first generation of telephone field trials in 1977 used such fibers to transmit light at 850 nanometers from gallium-aluminum-arsenide laser diodes.

· Those first-generation systems could transmit light several kilometers without repeaters, but were limited by loss of about 2 dB/km in the fiber. A second generation soon appeared, using new InGaAsP lasers which emitted at 1.3 micrometer, where fiber attenuation was as low as 0.5 dB/km, and pulse dispersion was somewhat lower than at 850 nm. Development of hardware for the first transatlantic fiber cable showed that single-mode systems were feasible, so when deregulation opened the long-distance phone market in the early 1980s, the carriers built national backbone systems of single-mode fiber with 1300-nm sources. That technology has spread into other telecommunication applications, and remains the standard for most fiber systems.

· However, a new generation of single-mode systems is now beginning to find applications in submarine cables and systems serving large numbers of subscribers. They operate at 1.55 micrometers, where fiber loss is 0.2 to 0.3 dB/km, allowing even longer repeater spacings. More important, erbium-doped optical fibers can serve as optical amplifiers at that wavelength, avoiding the need for electro-optic regenerators. Submarine cables with optical amplifiers can operate at speeds to 5 gigabits per second, and can be upgraded from lower speeds simply to changing terminal electronics. Optical amplifiers also are attractive for fiber systems delivering the same signals to many terminals, because the fiber amplifiers can compensate for losses in dividing the signals among many terminals.

Excerpted and modified from Fiber Optics Technician's Handbook, by Jim Hayes, Delmar Publishers, Albany, New York and Laser Focus World (November 1994). See also City of Light: The Story of Fiber Optics, Oxford University Press, New York, 1999. (ISBN 0-19-510818-3) and http://www.sff.net/people/Jeff.Hecht/history.html.

Petroleum Applications of Fiber Optics

(Excerpted from Wright, P.J., “Optical fiber's gigabit bandwidth, 200 km range attractive for subsea work.” Offshore Magazine (May 2000).

Up until now, optical fiber use in the petroleum industry has been somewhat limited to applications supporting technology that cannot function with "standard" electrical communication (to provide communication where high levels of electrical noise prevent the use of copper-based communication), for direct access to optical sensors (subsea and downhole) and for communication with sensor systems providing either continuous real-time data, or information at data rates higher than can be supported by existing electrical communication. Fiber optics continues to provide a flexible enabling technology for future subsea oilfield development

“The resulting growth in control systems functionality and update rates is pushing the need for increased communication bandwidth, and the need for more flexible and fault tolerant communication systems using bus architectures. The search for improved profitability is also driving the development of new and improved subsea and downhole sensors and sensor arrays.”

Until 1996, fiber optics were used offshore only for communication between adjacent platforms. The Dunbar Platform is operated from the North Alwyn Platform, 22 km away. The fiber optic link is provided by two continuous power umbilicals connecting the platforms. Nowhere in this system is there access to the fibers subsea.

The electrical noise environment around new subsea production techniques (e.g. subsea separation, multiphase pumping), and the power umbilicals that supply them, are problematic for conventional electrical communication and have driven the move to inherently noise immune, fiber optic communication configured for the modular offshore installation.

In the North ETAP development, Shell has permanently installed downhole, passive optical sensor heads that were tied back to their drive and diagnostics system located on the Marnock platform 25 km from the furthest well.

“Some recent deepwater development programs have realized significant financial advantages using optical fiber in place of copper. Studies have shown that the forecast umbilical construction and installation cost show significant CAPEX savings particularly for deepwater installation. Construction savings arise from the reduction in cross-section in the umbilical core that comes from removal of multiple copper communication lines, and their replacement by one or two fiber elements. This saving is then compounded by the reduced amount of armoring needed for the smaller core.

“Reduced installation costs come from the decreased cross-section and weight per unit length of the umbilical, and therefore the maximum length that can be installed in one piece. Where the increase in length results in the removal of, or reduction in, the number of umbilical mid-span joints, then the installation costs are reduced even further. With the umbilical costs being one of the main drivers in overall program am economics, the significant cost reductions that may be possible with a fiber optic option can result in the decision to develop a marginal field.”

Throughout these advanced programs, the critical technology was the development of the first low optical loss wet mate fiber optic connector. Without this, the modular installation of these and many other systems could not have moved ahead.

Historically, electrical communication for subsea control and data acquisition has been limited to 1,200 bit/sec, with anything up to 400 bit/sec being used for control system housekeeping functions. Consequently, the update rate for production related data has been slow by normal industrial standards, where typically Ethernet type systems are now being employed. This is particularly noticeable where a number of subsea control modules (SCM's) are interrogated sequentially through a topside control system that uses a single modem. By comparison, a single digital telephone conversation requires 64 Kbit/sec.

“Fault tolerant systems will feature heavily in the expansion into ultra-deepwater, as remotely operated vehicle (ROV) configurable and retrievable equipment become standard. This will include modular control systems, ROV installable valves and chokes, and the position sensors associated with them, as well as specialized sensors for fiscal metering and multi phase flow measurements, directly addressed through the optical fiber.”

“The Gulf of Mexico has just seen the installation of the first high bandwidth (2.5 Gbit) telecommunications cable solely for the use of offshore platforms. This "fiber web" link installed by PetroCom, for the first time provides the opportunity to directly control or monitor the performance of a subsea (or downhole) system from the office desk. This technology currently offers more reliable, versatile, and cost-effective, communication than the existing cellular and microwaves options. The Fiber Web system runs from Freeport, Texas via seven offshore platforms to Fourchon, Louisiana, and completes the ring on land through New Orleans and Houston.”

Multiphase pumps, and/or subsea separation systems, which themselves will benefit from a high bandwidth controls and condition monitoring system, and where high power electrical motors are included, the noise immune performance of optical fiber simplifies the prevention of data corruption on the communication lines.

Norsk Hydro installed the Troll Pilot subsea separator system late last year. This system, built by ABB Offshore, includes a 2 MW pump to pressure boost the wastewater for re-injection. All communication on this system is by optical fiber.

Petrobras has developed a deepwater (1,000 meters water depth) compatible multiphase pump that communicates with the surface over a fiber optic link built into the power umbilical to the motor. A number of other separator and multiphase pump programs such as Total's Nautilus multiphase pump program, and the CoSWaSS (configurable subsea water separation system) joint industry project have also concluded that fiber optic communication is necessary for secure, error-free communication.

Technology to produce slim-line hydrocyclones, capable of installation in a wellbore, is under development. The pumps needed to dispose of wastewater through a lateral, or for production boost already exist. Control and monitoring technology for these systems will require environmentally robust, high bandwidth noise immune communication, using downhole fiber optic cables and connectors. The various produced fluids will need high bandwidth sensors such as photo acoustic oil-in-water sensor technology, which are already in development for oil-in-water measurement for production optimization. Effective equipment wear monitoring will be necessary to allow scheduled replacement, and minimize rig activation costs.

Optical fiber offers the next major step change in sensor technology for the subsea and downhole arenas. Optical fiber sensors can he used to measure effects such as:

Fiber will be used to provide high bandwidth, electrical noise immune, environmentally stable communication with multiplexed sophisticated subsea and downhole equipment. Optical fiber will also provide communication to a range of discrete passive optical sensor heads, measuring temperature, pressure, flow, and vibration.

The fiber itself can be used as a distributed sensor, using either the Brillouin or Raman scattering effects, inherent in all fiber. It is currently possible to measure temperature and strain over fiber lengths of up to 30 km. This technology, already in use to measure temperature distribution in land-based wells, can also be used to monitor continuous pipeline temperature from the well to the platform and provide early warning of waxing or hydrate formation, or monitoring of pipeline temperature change during a shut-in.

“Discrete multiplexed sensor elements can be written directly onto glass fiber using an intense UV light source. These are known as Fiber Bragg Gratings (FBG), and reflect only the frequency of light which matches the grating pitch, so any parameter need only cause a change in length of a fiber section containing a grating to cause a shift in the reflected wavelength.”

It is possible to construct networks of Bragg gratings to measure temperature, pressure, strain, vibration, and acoustic signals over a single fiber. The change in reflected wavelength, indicating the change in an environmental parameter, can be detected by coupling a "white" light source onto the fiber. The reflected signals are for any wavelength shift from a calibrated value.

The source and detection equipment can be located some distance from the well, and linked by optical fiber and fiber optic connectors. Temperature, pressure, and other parameters can be accurately recorded.

Optical fiber can also be used to sense passive, discrete sensor elements. These often include a cavity whose length is modified by the parameter of interest, which results in a change in the optical signal picked up by the optical fiber. Shell ETAP’s program uses this type of detection - FOWM (fiber optic well monitoring).

“The move into ultra-deepwater brings with it the need to implement structures using lightweight composite and smart materials. Many composite material manufacturers are experimenting with Bragg Grating encoded glass fiber bedded directly into the composite matrix, so that the gratings form a sensor net capable of measuring loading in any direction of interest. This "smart composite" material technology is being investigated by the offshore industry to support the construction of many lightweight structures.” Examples include drilling and production risers as well as composite tension legs and tethers.

In comparison to electrical equipment, survivability in the subsea and downhole environments, with contact with water is superior.

The glass fiber will tolerate temperatures above 1,000^oC. Polyamide coated cable assemblies will survive 600^oC. The fiber should be protected inside a hermetically welded, buffer gel filled tube. This tube can be housed within a second hermetically welded tube with support wires. The final tube diameter is ~1/4-in. in diameter, and this can be used with production tubing.

Currently, the cost of single mode fiber (about 5 cents/ft) and a twisted shielded pair copper (30 cents/ft for 18AWG twisted shielded pair cable) are cost comparable, and it should be expected that the pricing would be even more favorable.

Under tension optical fiber has strength equivalent to steel. There is little resistance to shear and careful handling is required when the fiber is not protected in a cable or jumper. As a cable element, the fiber element can be handled with the same equipment and techniques as any other element that is being built into an umbilical.

Hydrogen ions, naturally present at low partial pressures or from more corrosion, or a cathodic protection system, can be absorbed by glass fiber. This causes increased attenuation. This effect is only of interest where long lengths (kin) of fiber are involved.

Properly designed umbilicals keep out hydrogen since they are in hermetically welded steel or copper tube, filled with a buffer gel that has hydrogen adherence properties. Alternatively, the fiber can be run through a non-corrosive jumper, such as thermoplastic hose. Carbon coated fiber can also be used.

A reference is Lemaire, P.: “Reliability of Optical Fibers Exposed to Hydrogen: Prediction of Long-Term Loss Increases,” Optical Engineering 30(6) (June 1991) 780-789.

More on Optical Sensors

(Excerpted from Williams, G.: “Optical sensing coming of age in production monitoring.(Petroleum Production Engineering” Offshore Magazine (January, 1999).

Probably the first commercial fiber optic pressure sensor was developed through a joint industry program between Norsk Shell and Alcatel Kabel Norge with BP Norway and Norsk Hydro as co-sponsors to offer permanent downhole pressure and temperature measurement and to be capable of operating in HP/HT environments (120 to 150^oC).

It is a micro-machined silicon oscillator that is activated and read optically through a single fiber. The fiber's resonant frequency varies with the pressure and temperature downhole. It is practically insensitive to fluctuations in signal attenuation and can be operated remotely. Over five of these systems have so far been installed.

A system developed by Sensor Highway of Andover, UK deploys optical sensors using a conduit concept. This allows thin filament sensors to be placed in the well using fluid drag and has certain intrinsic advantages.

· Faulty sensors can be replaced or upgraded sensors can be installed during the life of the well

· Sensors can also be "buffered" using specially formulated fluids that are placed in the conduit.

The Distributed Temperature Sensor (DTS) was developed for short range (monitoring 1.5 km) to long-range implementations up to 30 km. Distributed temperature sensing can be used to provide a real-time thermal profile along the entire length of the well, enabling optimal inflow conformance through the detection of any thermal event. Temperature data are measured at every point along the line. Laser light pulses are generated by the DTS and launched into the optical fibre sensor. As the light pulse encounters temperature features along the fibre the pattern of back-scattered light returning to the DTS changes. Advanced signal processing within the DTS retrieves the temperature profile of the fibre from the backscatter signal. Unlike conventional instrumentation, the fibre optic system serves as both a sensor and the means of transmission. The Sensa distributed temperature system measures temperature along the whole length of an optical fibre in real time. With photons traveling at the speed of light through the fibre, measurements can be made along the complete well without an intervention.

A surface laser sends a light pulse down the fibre and a computer analyzes the back-scattered light from every meter interval of the fibre – from the surface to well bottom and back. Temperature is calculated for every meter along the fibre to an accuracy of 0.1°C and a resolution of 0.1°C.

Installation of Sensa’s fibre optic distributed temperature system takes place while the well is being completed using a special hydraulic installation technique licensed from British Telecommunications plc.

The temperature monitoring of complete well profiles in real time allows a thermal signature of the well to be determined. Subsequent changes in temperature can be used to identify and monitor:

These data can be correlated with information acquired on the surface - including flow rates and water cut - as well as from openhole logs and tester data - resulting in qualitative and quantitative information about the changes that are occurring downhole.

As indicated, distributed temperature is measured by sending a pulse of laser light down the optical fibre. Molecular vibration (which is directly related to temperature) creates weak reflected signals. The reflected signal is detected in the surface read-out unit and converted to values of temperature at 1-meter intervals along the fibre and well. The temperature data can be displayed on-site, stored for later analysis or transmitted in real-time via modem or scada/modbus links.

The distributed temperature system has two modes of operation, single ended (SE) and double ended (DE). Systems are designed and configured according to particular applications.

DTS with optical fibers is based on optical time-domain reflectometry. A pulsed laser is coupled to an optical fiber that is the sensing element. The light is backscattered as the pulse propagates through the fiber owing to density and composition as well as to molecular and bulk vibrations. A portion of the backscattered light is guided back to the light source and split off by a directional coupler to a receiver. Under ideal conditions the intensity of the backscattered light decays exponentially with time. As the speed of the light within the fiber is known, the distance that the light has passed through the fiber can be derived from the time along the decay curve. (See Figure 1).

The backscattered light includes different spectral components; Rayleigh, Brillouin and Raman bands. The Rayleigh component is independent of temperature but is useful in identifying breaks and inhomogeneities along the fiber. This is the main tool used by the telecommunications industry to check the condition of optical fiber communication links. The Raman spectral band is caused by thermally influenced molecular vibrations. These are naturally occurring phenomena in glass as well as in fluids, gases and solids. The Raman spectral band can be used to obtain information about distribution of temperature along the fiber. The Raman backscattered light has two components, Stokes and Anti-Stokes, one being only weakly dependent on temperature and the other being greatly influenced by temperature. The relative intensities between the Stokes and Anti-Stokes are a function of temperature at which the backscattering occurred. Therefore, temperature can be determined at a remote point in the optical fiber (wave form is inset in Figure 1).

Precautions

It is crucial to avoid excessive build up of either intrinsic or extrinsic energy losses in the optical fiber. Intrinsic energy losses arise from the scattering and absorption of the light in the optical fiber medium. Connectors generate extrinsic energy losses as do field splices, and fibers that have tight bends and excessive heat or mechanical damage. Excessive losses will lead to a gradual degradation in measurement range or complete loss of signal in the extreme case.

It has been recognized since 1982 that there are absorptive losses associated with hydrogen that is dissolved in silica glasses. Due to its small size, the H₂ molecule, which may be present around an optical fiber, can readily diffuse into the central light guiding region of the fiber. Early accelerated laboratory tests found that loss increases could occur due to hydrogen, which either originated from polymeric materials or from galvanic corrosion cells in subsea cables. Problems of this sort have been dealt with by:

(2) Redesigning the fiber cables to avoid the possibility of H₂ generation, and

(3) Using hermetic coatings to block the diffusion of any hydrogen that might be present in the cable.

However, even when the problems associated with large short term losses are solved, there still remains the issue that there might be small but significant long-term loss increases due to the trace levels of hydrogen that can remain in fiber cables. Laboratory experiments to date suggest that with a well-manufactured optical fiber and good hermetic coating, ingress of hydrogen into the optical fiber only occurs at temperatures greater than 572 °F (300°C). At temperatures below this value, existing coating technology is capable of limiting hydrogen ingress to a level that does not result in fiber degradation. Fiber degradation is evidenced by a significant increase in attenuation through wave-guide darkening.

The ingress of liquids into optical fibers can lead to both increases in fiber attenuation and eventual mechanical failure of the fibers. Fluids that pass into the fibers create absorptive losses in the wave guide and create mechanical stress in the fiber, which leads to micro-bending effects. Water is extremely damaging to optical fibers. Water ingress, if permitted will extend any surface cracks that may be naturally occurring in the fiber surface and these will be elongated by a stress cracking process. The diameter of the optical fiber will be reduced to the point where it cannot support its own weight and failure will occur. The use of hermetic coatings in situations where the optical fiber is likely to be exposed to water has been the traditional means of combating this problem.

Optical fibers also suffer increased extrinsic energy losses due to micro-bending effects. Large bends of cable and fiber are macro-bends and small-scale bends in the core-cladding interface are micro-bends. Macro-bends rarely create difficulties when optical fibers are deployed downhole. However, care is necessary to avoid forming micro-bends particularly at temperatures in the region of 482 °F (250°C). Micro-bending can occur when stresses are built up in the fiber coatings as either the fiber is heated or cooled. Probably, cyclical heating and cooling offers the greatest challenge for optical fibers in respect to micro-bending losses. Tests performed for Canadian huff and puff operations indicate that there is severe micro-bending when the fiber is returned to ambient reservoir conditions after being exposed to temperatures as high as 644 °F. Further optical fiber coating development will be required to take measurements accurately across the full range of 86° - 644 °F.

“Disadvantages of the fiber optic system when compared to the thermocouple bundle is the higher cost associated with the data acquisition system. System accuracy and resolution is a function of response time and several minutes are required to reach accuracy and resolution of 0.5 °F and 0.2 °F respectively. Finally, the relative fragility of the optical fiber can be a problem before it is placed in the control line.”

Installation

Installation of the Distributed Temperature Sensor is “simple” - the well is equipped with a 1/4 inch O.D. control line. This can be installed either outside or inside casing/liners or screens. Specially coated optical fibre is then pumped into the control line and connected to an opto-electronic surface read-out unit.

Standard oilfield procedures are used to equip the completion with the control line. This can be either part of a new well design or as part of a work-over schedule. Optical fibre is then placed into the conduit using a hydraulic system under license from British Telecommunications plc

The apparatus for installation of the optical fibers is protected by US Patents 5022634 and 5199689 (and corresponding foreign patents). It has been manufactured under license from British Telecommunications plc and is the property of Sensor Highway Ltd.

Installation of Sensa’s distributed temperature fibre takes place either while the well is being completed or once the completion is finished using a special hydraulic installation technique licensed from British Telecommunications plc.

Unlike permanently installed electrical sensors, the system has a high reliability under extreme conditions and unlike conventional logging methods, there is no risk to the well from the intervention or loss of production while the log is being run.

The optic fibre is pumped around a 1/4-inch control line that is installed during the well completion, or workover. Over 10,000 meters of fibre have been successfully installed in control line in a single well. The control line can be installed either as a single line, or as two lines with a Sensa designed Turn Around Sub at the bottom allowing both ends of the fibre to be connected to the surface electronics. Double ended mode will give a more accurate temperature measurement and is preferred if analysis of flow contribution over the reservoir is required.

Figure 2. Distributed Temperature Implementation

· Provides real-time TD-to-well head measurement of temperature at 1 meter intervals with one compact optical fibre cable.

· One sensor system provides information on in-flow characteristics, gas breakout, artificial lift equipment and mechanical integrity.

Completion Configuration

Areas that need to be considered for integration of the Sensa system with the completion include:

· Wellhead barriers provided by Sensa to suit different environments and legislative requirements.

· Wellhead modifications to facilitate passage of the control line through the wellhead.

· Tubing hanger modifications to facilitate passage of the control line through the tubing hanger.

· Clamps/straps are required to protect the control line. Equipment ranges from specialized clamps for protecting the control line on the outside of horizontal gravel-pack screens to simple stainless steel bands to anchor the control line to the outside of tubing or casing of shallow vertical wells.

· On-off disconnect unit is required if the completion is to be run in more than one trip. The on-off disconnect protects and orientates the two control lines in the upper and lower portions of the completion.

· Turnaround sub to allow smooth controlled turn of the control line at the bottom of the instrumented completion.

The distributed temperature system surface readout has been designed as a modular unit to provide up to 24 optical sensing channels. Each channel is dedicated to a particular temperature sensing optical fibre that can be up to 12 km in length. Typically one channel is dedicated to a single well however shallower vertical wells can be joined into one loop by running the fibers in series down each well until the total length limitation has been reached.

The distributed temperature data can be seamlessly integrated into existing DCS, PLC or SCADA type systems for production control and monitoring. Working with state of the art techniques including web-based delivery systems allows the information to be placed at the desks of the people who need to make the decisions.

Thermal simulation models are used to match measured profiles with production conditions and so provide valuable information on changing production conditions without having to run a production log. Reservoir

1. Osato, K., Takasugi, S., Osawa, S., Hashiba, K., and Perales, K.: “Temperature Profiling/Bottom Pressure Monitoring System Using Optical Fiber and Capillary Tube – Field Test in a Geothermal Well,” 1995 Annual Meeting Geothermal Research Society, Japan.

2. Orrell, P., and Harjes, B.: “Borehole Temperature Measurements using Distributed Fibre Optic Sensing,” International Institute for Geothermal Research (1993).

3. Karakan, S., Kutlik, R., and Kluth, E.: “Field Trial to Test Fiber Optic Sensors for Downhole Temperature and Pressure Measurements West Coalinga Field, California, SPE 35685 (1996).

Multi-point fiber optic pressure sensing can be used for permanent monitoring operations to discern reservoir pressure and zonal contributions. Some typical examples include evaluating fractured systems, measurement of drawdown, assessment of skin, reservoir heterogeneity, permeability, completion efficiency, drainage and front radius inferences, developing performance curves …

Pressure is measured using a self-referencing optical technique. The system detects small changes in distance that occur between two points in a ceramic pressure head when the pressure is varied. The micron (10^-6 m) scale gap in the sensor head is monitored using optical interference patterns to provide accurate pressure readings. The ceramic sensor is designed to be stable at elevated temperatures over extended time periods. Sensor temperature compensation is achieved by using concurrent Distributed Temperature measurement. The fiber optic pressure sensor is protected by US Patents 5446280, 5963321 and 6069686.

All of the necessary optical equipment sources and detectors are maintained at the surface away from the downhole environment. The Surface Readout Systems (SRO) is an opto-electronic assembly. It houses the light source and the photo-detectors, along with the ancillary couplers and filters. The unit has its own power supply, digital processor and data storage systems.

Laser light is transmitted to the sensor using a cable that can contain up to 12 optical fibers. This allows up to 11 pressure sensors and a Distributed Temperature measurement to be installed in a single well with one cable, if required. Figure 3 shows the accuracy of fiber optic pressure measurement.

Figure 3. Comparison of pressures measured using fiber optics methods with those determined from a digital quartz gauge.

In its simplest form the pressure sensor can be deployed like a conventional electronic gauge. Initial designs are suitable for installation outside 4 1 /2 " tubing located inside 7" casing. Several Sensa pressure sensors can be installed on the same completion and used to monitor the pressure in different producing zones or the pressure distribution along a horizontal section. A full range of accessories has been developed to allow the deployment of sensors in different well designs. These include wellhead adapters and penetrators, cables, packer penetrator kits and downhole connectors.

Armored cables can contain up to 18 individual optic fibers. These cables are rated up to 10,000 psi working pressure and 150^oC. Continuous lengths up to 10 km are available in various alloys to suit the environment.

The pressure sensor can be deployed like a conventional electronic pressure gauge. The system can be installed outside 4.5" tubing inside 7" casing. Several fibre optic pressure sensors can be installed on the same completion and can be used to monitor the pressure in different injection zones or the pressure distribution along a horizontal section.

The pressure gauge can be installed either above or below the packer and can be configured to measure either the tubing or annulus pressure, as required. Two pressure gauges mounted 10 meters apart can be used to monitor producing fluid density. Figure 5 shows a typical installation.

If required, several gauges can be installed in the same well using either a cable or control line implementation.

The pressure sensor has advantages for permanent well monitoring operations. For example:

· Downhole electronics are not required and reliability is high. There is high accuracy, resolution and stability for continuous monitoring and transient analysis.

· Up to 11 pressure and distributed temperature measurements can be configured on one multi-cable.

Acoustic Flow Sensor

Acoustics sensing measures flow, determines changes in fluid phase and detects sand production (Figure 6). Optical acoustic monitoring is a new tool for permanent monitoring. Cutting edge fibre optic technology monitors near-field acoustic noise and vibration, providing real time data on downhole flow and sand production. Applications could include measuring flow rate, discerning flow type/regime, monitoring pump condition, leak detection, and sand production monitoring …

Figure 6. Comparison of acoustic and vibration sensor response mounted on an ESP monitor.

The acoustic flow sensor is a permanent, fiber optic sensing system that can be installed at several points along the producing interval to give an inflow profile of single phase oil, water, gas and sand. Measurement of near-field acoustic noise and vibration is achieved using fibre optic time domain reflectrometric interferometry technology developed by Thompson Marconi Sonar Ltd. and available exclusively from Sensa Ltd. for use in the oil and gas industry.

The sensor consists of a wound length of fibre using patented techniques, encapsulated in a pressure housing which is acoustically mounted at customer defined locations on the completion (Figure 7). The chamber is acoustically coupled to the completion at a customer-defined location within the well. This can either be externally on tubing, measuring flow inside, or mounted on a “stinger” inside the producing zone measuring external flow. The sensors are interrogated with highly coherent pulses of laser light. The returned signals, containing the acoustic data, are demodulated in the Opto-Electronics surface unit and recorded. The data are then processed for significant events and stored for offline processing/ trending if required.

· Fibre optic sensors are immune to electromagnetic interference (EMI) and are thus unaffected by ESP motor electrical noise

· Sensor arrays can be run together with Sensa fibre optic pressure and distributed temperature systems using one fibre optic multi-cable.

Acoustic sensors can be mounted on an ESP pump or motor to monitor performance. They can also be installed at any point along the production tubing to monitor flow or sand production e.g. between producing zones. Mounting the Sensa Acoustic Sensor on an ESP pump or motor will allow the low frequency vibration spectrum to be monitored all the time. Increases in vibration will indicate deterioration in the efficiency of the pump or motor and allow appropriate decisions to be made about optimization or replacement.

McKinley and Bower (SPE 6784) demonstrated that acoustic signals in a borehole are proportional to the flow rate and pressure drop along the flowing section. Thus a permanently installed acoustic sensor can indicate flow rate changes in flow over time. Van der Spek (SPE 50640) demonstrated that acoustic measurements could also be used to successfully identify flow regime using neural net technology.

Sand production causes high frequency noise due to the sand particles impinging on the pipe walls. Conventionally, acoustic sand detectors are mounted on pipe bends at the surface. The Sensa Acoustic Sensor provides the opportunity to install a sensor device above each producing zone - thus identifying which is the source of sand production.

1. Van der Spek, A (1998) "Neural Net Identification Of Flow Regime Using Band Spectra Of Flow Generated Sound," SPE 50640,SPE, The Hague, The Netherlands.

2. Mckinley, R.M., Bower, F.M. & Rumble, R.C.: "The Structure And Interpretation Of Noise From Flow Behind Cemented Casing," SPE 6784, SPE-AIME San Antonio, Texas (1973).

Fiber optic-distributed temperature sensors installed using the Sensor Highway conduit can supercede coiled tubing-conveyed production logs. Two Wytch Farm wells (onshore/offshore development on the southern English coast) have been completed with fiber optic sensors. The purpose of the sensors is to monitor downhole electrical submersible pumps and well performance. One of the wells is a relatively simple vertical completion with an ESP, while the other is a more complex horizontal dual-purpose well.

The distributed temperature data from the simple ESP completion was effective in describing the operating condition of the ESP pump.

In the horizontal well's case, there are encouraging indications that inflow along the horizontal section is observed. This dual-purpose injector/producer has a crossflow sub to allow produced water reinjection below the oil/water boundary while crude is produced along a long horizontal section. Conventional PLTs cannot be run in this well because the ESP requires a shroud and there is no logging bypass. In addition, the cross-flow sub is not full bore.

The BP-Amoco Wytch Farm site uses ERD wells to reach the reservoir located under Poole Harbour and the English Channel. It was desirable to monitor the complete temperature profiles of the wells and in particular the producing zones - to determine which areas of the reservoir are producing and to identify any production problems, such as water breakthrough.

The Sherwood reservoir extends approximately 15 km under Poole Harbour and the English Channel. Some of the wells have been drilled out horizontally with a measured depth of over 10 km and a vertical depth of ~1600 meters. Artificial lift is used because of low reservoir pressure - generally by downhole electrical submersible pumps (ESPs).

Following a successful test to evaluate both ease of installation of the Sensa system in well K-7 in 1997, Sensa’s real-time, fiber optic distributed temperature monitoring systems were installed in extended reach development (ERD) wells – M-12 and M-17 in 1998 and 1999 respectively.

Producing 9,500 barrels per day, M-12 is a dual-purpose completion – where oil is produced and water is injected into lower zones to maintain reservoir pressure. While this type of completion cannot be logged using conventional production logging techniques the Sensa system proved to be relatively simple to integrate into the completion. The fibre optic control line was attached to the outside of the 4" production tubing, with a hydraulic ‘wet connect’ supplied by Baker Oil Tools to allow disconnection of the lower completion for ESP maintenance, if required. With a measured depth of 5,100 meters and a vertical depth of 1,500 meters, a total of 10,500 meters of optical fibre were installed in the well to provide temperature data points at one-meter intervals over the whole length of the well.

M-17 produces approximately 5,000 barrels a day by ESP pump and is not used for water injection. In this case, the fibre optic control line was installed across the reservoir attached to a 2 7/8” tubing ‘stinger’ below the ESP.

The relative proximity of the wellheads for both M12 and M17, meant that both wells could be monitored using a single multiplexed processor, located at a central location.

Following the installation of Sensa instrumentation in M-17, temperature profiles of both wells have been monitored with 100% reliability. For the first year following installation in M-12, the well was monitored during shut-ins or multi-rate well tests.

Ongoing reporting of real-time monitoring data from M-17 provided a continuous picture of the reservoir temperature changes with time. Recording a significant temperature drop at the toe of the well, the Sensa system identified a zone of cold injection water breakthrough, believed to be from a nearby seawater injector.

Analysis of M-17 data using a thermal wellbore simulator identified the majority of production was at the heel of the well, highlighting a possible fault. The simulator allows a variety of producing scenarios to be examined so the most likely solution – which fits both with the observed temperature response and other reservoir and production data – can be determined. By matching the thermal simulator model to the recorded temperature data, producing zones can be identified and production estimates obtained. Instant Information.

A key issue with M-12 was the ability of the Sensa system to quickly identify water production from behind the casing of a cemented off water zone. Conventional production logging techniques may have highlighted the problem if it had been possible to log this well. However, this information would have only been acquired after an expensive logging run had been completed and the results interpreted. Instant access to complete thermal well profiles allows for a more proactive approach to reservoir and production monitoring.

Data from both wells are recorded continuously 24 hours a day and downloaded once a week remotely by telephone line to the Sensa head office in Andover. Daily checks are made on the well profile and BP-Amoco is notified immediately if a significant change is observed. Detailed data interpretation is carried out by Sensa and discussed with Wytch Farm reservoir and production engineers on a monthly basis. Sensa uses Landmark Wellcat™ software to produce a thermal model of the well based on multi-zone flow. Comparing the thermal response of flowing and non-flowing zones to the measured data gives valuable information on interval production. Data is supplied to BP-Amoco both as DTS.bin files and summarized EXCEL™ spreadsheets.

Baker Hughes substantially provided a completion, - an evolution from the earlier Wytch Farm M10 well completion design – for a well with >6,000 meters md, producing oil over about 1,000 meters. It was desired to determine whether continuous distributed temperature measurements along the producing interval could be used to describe the production inflow response along the perforated section.

This was a one-trip completion using a hydraulic wet connect system (Baker Oil Tools) to permit installation of the sensors below the ESP. A Baker JMZX packer was used as the linear tieback packer. The large bore allowed running the dual 1/4-in. conduits and clamping them to the 4 1/2-in. tubing running along the producing interval and run to a turnaround sub that was set above the lower packer - a Baker SABL-3 Hydro set design. This installed the two 1/4-in steel conduits in the pre-perforated horizontal producing section.

The wet-connect tool was operated during the completion phase to enable the completion space-out to be performed. Fluid pressure in the 1/4-in, conduit was increased to allow the interlock function to be disabled and the tool was disconnected, parting the string below the shrouded ESP. After spaceout, the tool was reconnected and the conduit was successfully pressure tested.

A completed loop of 1/4-inch conduit, 10,000 meters long, was installed in a complex horizontal well, including a 1,000-meter horizontal section where the conduit was clamped to the outside of 4 1/2-in. tubing inside a 7-in. liner. The next step was to install 10,000 meters of optical fiber using fluid drag into the 1/4-in conduit loop!

Initially, the fiber wouldn’t deploy into the conduit. After the conduit was flushed with isopropanol (to remove hydraulic oil), the fiber went through without difficulty. Initially, a 6,000-meter-length fiber was installed to operate in single-ended mode. Later, this will be replaced by a 10,000-meter fiber loop.

Distributed temperature data is being gathered in a well from which real-time well performance data would otherwise have been unattainable. Early results suggest the temperature profile along the 1,000-meter horizontal section is not linear and that there are regions of greater or lesser temperatures.

Fiber optics can be used to manage intelligent well operations. Through controlling the channeling of hydraulics with fiber optic switches, it is possible to operate an array of tools located within the wellbore from the surface. Numerous fiber optic actuators are available that are capable of exerting large forces, with sufficient displacements ranging from several micrometers to a few millimeters.

Piezoelectric actuators have been adopted widely. Their main advantages are generation of large forces, high movement resolution, high dynamics and the potential for miniaturization. It should be possible to operate certain hydraulic devices (such as safety valves and sliding sleeves), to optimize gas lift valves and to set packers using these systems.

Vertical Well Single Injection/Production Zone

The temperature profile in a vertical (or deviated) well depends on the virgin geothermal gradient, the injected/produced/formation fluid, the thermal properties of the formation, the mass flow rate and the injection time. Characteristically the temperature profile above any producing/injecting interval becomes asymptotic to a line that is parallel to the geothermal gradient. This temperature profile changes with flow rate. This is shown schematically in Figure 8. Injection measurements for injection may be more subtle and the most diagnostic information may come from the nature of thermal recovery in the wellbore when the well is shut-in.

Thermal logging has been frequently used for modeling the vertical extent of hydraulic fractures that have been placed for stimulation purposes. Certain precautions are necessary. First, if the fracture deviates from the wellbore, even by a relatively small amount, the full vertical extent may not be evident. Often, temperature logging after hydraulic fracturing only shows the perforated interval. In addition, in hydraulic fracturing for stimulation dead fluid in the rat hole sometimes masks downward growth (may or may not be an issue for an injector).

Figure 8. This shows a single production zone in a vertical well and how the temperature profile deviates from the virgin temperature profile with an increased rate of production. It is more difficult to determine definitive inflow for injection situations because the wellbore temperature is dominated by the nominally constant injection fluid temperature. Excursions may be evident due to changes in formation temperature and the rate at which the temperature recovers if the well is shut-in (analogous to temperature logging for mapping hydraulic fracture extent).

In a production scenario, where flow is coming from more than one zone, additional production from a higher interval will enter the wellbore at a lower temperature. The contribution from each zone can be estimated from the drop in the overall fluid temperature as the two fluid streams combine. Again, flow distribution in injectors may be less apparent from thermal variations although the same concepts apply (Figure 9).

Figure 9. This shows two production zones in a vertical well and how the temperature profile deviates from the virgin temperature profile with an increased rate of production. It is more difficult to determine definitive inflow for injection situations because the wellbore temperature is dominated by the nominally constant injection fluid temperature. Excursions may be evident due to changes in formation temperature and the rate at which the temperature recovers if the well is shut-in (analogous to temperature logging for mapping hydraulic fracture extent).

During production, as oil flows along a horizontal well the pressure drop causes Joule-Thompson warming of the fluid. The reverse can be true for gas. This temperature is at least partially a function of the flow rate. Given sufficient flow, a temperature increase (or decrease depending on the fluid properties) of over one degree Centigrade may be generated along the horizontal section. This can readily be detected. You can imagine applying similar considerations (differential temperature along the length of the well depending on how the flow is partitioned into various zones) for injectors. Figure 10 is an example for a production scenario. If the rate is low, changes in temperature are smaller and passive thermal measurements may not be adequate. Sensor technology has overcome this (see low rate horizontal wells).

Figure 10. Inflow and outflow can be discerned by judicious monitoring of the temperature profile in high rate horizontal wells. Modest temperature variations can be discerned. If the rate is not high enough, it may be necessary to “help” the sensors (see low rate horizontal wells, below).

In low rate horizontal wells, the measured temperature will not vary adequately as a function of flow. To overcome this, Sensa has developed a method of creating short thermal transients in the flowing fluid using their patented Flo-Trak™ system. This enables the velocity of the flowing fluid to be measured at each Flo-Trak™ element location by tracking a slug of cooled fluid, created by the Flo-Trak™ system, with the distributed temperature system (refer to Figure 11).

Figure 11. For low rate wells, measurement is not strictly a passive activity. Thermal transients are induced and monitored.

The Flo-Trak™ Fluid Velocity Tracking System uses a pre-installed Sensa Distributed Temperature System and heating coils to accurately track the velocity of single-phase fluid at low flow rates at specified points downhole.

The Flo-Trak TM Fluid Velocity Tracking System* uses a pre-installed Sensa Distributed Temperature System and heating coils to accurately track the velocity of single phase fluid at low flow rates at specified points downhole. Measurement of fluid velocity is achieved by creating a transient temperature anomaly in the produced fluid with a heating coil and tracking this anomaly as it moves up the well using a sensitive fibre optic

This records the fluid temperature every meter along the fiber at sampling frequencies down to 1 Hz. Localized heating is achieved from the friction of high-pressure nitrogen gas being pumped through a small diameter coil acting as a counter-flow heat exchanger. Delivery of the gas to the coil is through a pre-installed control line allowing the coil to be actuated at any time from the surface. Distributed temperature is measured by sending a pulse of laser light down the pre-installed optical fibre. Molecular vibration, which is directly related to temperature, creates weak reflected signals. The reflected signal is detected in the surface read-out unit and is converted to values of temperature at 1-meter intervals along the fibre and well.

· Simple sensor design requires no downhole electronics -ensuring high reliability

· Can be installed on either side of laterals in multi-lateral completions to define lateral contribution

· Can be actuated at any time from the surface (with a DTS and Nitrogen unit) to monitor flow as required

The temperature anomaly produced by the heating coil is tracked up the well using the fibre optic Distributed Temperature System once the heating coil is switched off. The track of the anomaly with time versus depth gives the velocity of the fluid.

It has been manufactured under license from British Telecommunications plc and is the property of Sensor Highway Ltd. Sensor.

The distributed temperature system can be used to monitor the performance of the wells Gas Lift Mandrels (GLM's). The Joule Thompson cooling effect of gas blowing through the mandrel identifies its location and cools the producing fluid, giving a qualitative indication of the mandrels efficiency. A mandrel that is slugging gas, rather than operating normally, would be readily identified using time dependant thermal monitoring.

Artificial lift is used in many fields to overcome the effective hydrostatic head on the reservoir and so allow the oil to flow to surface. Artificial lift involves the input of energy through gas injection; electric power to ESPs or PCP's and improvements in the efficiency of these methods can readily improve incremental oil production. Sensa provides downhole sensors for performance monitoring of these systems.

Sensa’s distributed temperature system can be used to control injection pressures according to the lifting efficiency required.

Sensa reported that fibre optic real-time monitoring would be (if it has not already) installed to optimize inflow performance of Shell Expro's gas lifted oil wells in the North Sea.

Background

With the ultimate aim of improving both the management and performance of well inflow, Shell’s initial trial set out to assess Sensa’s fibre optic distributed temperature system for its suitability to North Sea operations. The first well to be monitored was a gas-lifted offshore well.

“Test results to date have substantiated the Sensa technology claims and now Shell Expro is planning to use the system to monitor inflow across the reservoir.”

Initial trials were carried out on Shell Expro’s Tern well TA-27, a 10,500 ft deep gas lift well - completed with 9 5 /8" casing and 5 1/2" inch tubing. Gas lift valves were set at 1,235, 2,190 and 2,825 meters. Monitoring gas lift valves has to date only been achievable in wells equipped with single point temperature probes set around the valve itself or by conventional logging methods. The distributed temperature system provided a complete thermal profile of the well and identifies the correct operation of the appropriate gas lift valve by monitoring the change in temperature of the produced fluid as it passes the gas lift valve.

The first stage of testing was to demonstrate the Sensa technique for pumping optical fiber into a hydraulic conduit (control line) to just above the packer. Serving as both a sensor and a transmission system, the fiber provides temperature readings at one-meter intervals from the surface to below the lowest gas lift mandrel. The temperature profiling system was able to monitor the well during critical operations such as start-up and unloading as well as monitoring the gas lifting system throughout its operation.

Tern well TA-27 was successfully installed with Sensa’s distributed temperature system and has been monitoring temperature on a continuous basis since 28 April 2000. The Sensa system can identify critical temperatures throughout the well. Analysis and interpretation of the continuously acquired data will allow completion design to be modified for future wells to be completed at lower costs and greater safety. For example, the continuous acquisition of temperature data will enable hydrate and wax formation to be proactively inhibited and so allow subsurface safety valves (SSSV) to be located as near to the surface as possible. This will translate into significant cost savings brought about by the reduction in casing sizes for the completion and possibly a simpler SSSV design.

Sensa’s temperature measurements also highlight the proximity of other wells and can indicate where interference from different wells is affecting production.

By pin-pointing well inflow rates, distributed temperature measurements can identify any early signs of scale build-up, enabling Shell Expro to put preventative maintenance in place to preempt problems such as blocked safety valves.

Distributed temperature data are recorded continuously on the Tern platform, 24 hours a day and distributed to Shell Expro and Sensa via an Internet link for storage and interpretation. Daily checks are made on the well profile by both companies – providing an immediate indication of any significant change in the well’s performance. Detailed data interpretations are produced and discussed on a monthly basis.

To verify the quality of Sensa’s data, Shell Expro has also carried out tests and comparisons with known geothermal temperatures – proving the reliability of the new technique. Comparing the thermal response of flowing and non-flowing zones to measured data provided by Sensa’s interpretation package – provided by Landmark Wellcat™ – gives relevant information on interval production.

Shell U.K. Exploration and Production (Shell Expro) operates in the U.K. sector of the North Sea on behalf of Shell, Esso and other co-venturers.

Distributed temperature monitoring allows identification of crossflowing zones (which have a similar thermal response to flow outside the casing) identifying which reservoir intervals have higher or lower pressures after periods of production.

A distributed temperature system can provide real-time information as a downhole permanent distributed temperature-monitoring system. Figure 5 shows one typical application for determination of crossflow.

Figure 5. Temperature monitoring along the completed length can provide indications of crossflow.

The different thermal properties of water, compared to oil, cause a shift towards the geothermal gradient when a zone flowing oil goes wet. If distributed temperature is being continuously monitored there will be a change in the thermal profile at the point of water entry which will correlate in time with the increase in water cut observed at the surface - and thus identify the location of the water entry.

When gas is produced, the pressure drop around the well bore will cause Joule Thompson cooling of the gas as it enters the wellbore. This can be identified from a distributed temperature profile.

In vertical wells multiple gas entries can be recognized from their cooling effect and the thermal response can be analyzed to give an indication of contribution by zone. Figure 6 is a schematic of this behavior.

Figure 6. You can use deviations from a baseline thermal profile to determine entrance of gas in one or more zones in a producer. Changes in the relative contribution of the produced fluids will be reflected in changes in the observed temperature profile.

When water is injected into a reservoir the thermal profile observed in the well bore is normally close to that of the injected water surface temperature. However if the well is shut-in for a period, the permeable zones, which have been taking the water (colder if seawater, hotter or slightly cooler if produced water), warm back towards the geothermal gradient at a much slower rate than those that are not permeable.

Monitoring the warmback temperature response when the well is shut-in will identify the permeable zones and an estimation of the relative contribution can be made.

Through continual processing of the continuously acquired temperature readings it is possible to determine precisely where the temperature unexpectedly changes along the wellbore. These changes can mark the presence of fractures, faults and can confirm into which zones the injected water is flowing. Because it continuously and accurately measures the temperature along the wellbore in real time, the DTS system could provide information that would enable the productivity of some wells to be increased by 10-20%.

Water injected into a reservoir will cool the reservoir at the point of injection to a radius that is typically half the way to the water/oil flood front. Thus if the producing well is close to the injector the breakthrough of injected water will be followed, after a period, by a cold thermal front which can be identified using the distributed temperature system.

The rate of flow between the two wells can be estimated by shutting in the injector well for a period, allowing it to warm up, and then re-commencing injection causing a new thermal front to move towards the producer.

Temperature monitoring responds to thermal effects generated both in and outside the well bore. Consequently if there is an interval with fluid flowing outside the casing, either cross flowing between zones or exiting into the well bore this would have a characteristic response which will be readily identifiable on the distributed temperature profile.

Steamflood efficiency can be continuously monitored and optimized. This has been done onshore in California, Indonesia, Venezuela and Canada at well temperatures between 100 and nearly 300^oC. A reference is Saputelli, L., Mendoza, H., Finol, J., Rojas, L., Lopez, E., Bravo, H., and Buitrago, S.: “Monitoring Steamflood Performance Through Fiber Optic Temperature Sensing, SPE 49184 (1998).

Monitor Wells - Regular distributed temperature monitoring in steam flood monitor wells can identify the arrival of steam fronts by time and depth giving an indication of the efficiency of the steam flood sweep.

Injection Wells - Distributed temperature monitoring in steam flood injection wells can identify the intervals taking steam and the size of the steam chamber in SAGD wells. The combination of thermal modeling and distributed temperature monitoring during steaming can identify the radial extent of the steam front in the reservoir and be used to optimize steam injection.

Sand Detection

Sand production causes high frequency noise due to the sand particles impinging on the pipe walls. Conventional sand detection systems use acoustic monitors to indicate the production of sand, but are limited to surface installation and so cannot differentiate between sand production from different producing intervals. The acoustic flow sensor provides the opportunity to install a sand detection sensor above each producing zone - thus identifying which is the source of the sand production.

Multi-Phase Flow Measurement

It has been demonstrated that acoustic measurements can be used to successfully identify flow regimes using neural net technology. Although a number of different sensors are required to fully describe multi-phase flow, in the case of liquid/gas flow in horizontal pipes the slug flow regime is often dominant and can be detected using an acoustic flow sensor alone. The acoustic flow sensor can detect slugs by their characteristic frequency response in liquid/gas multi-phase flow – thus allowing flow regime identification. If two sensors are mounted adjacently the velocity of the slugs can also be measured.

Single Phase Flow Measurement

It has been demonstrated that acoustic signals in a borehole are proportional to the flow rate and the pressure drop along the flowing section. Thus, a permanently installed acoustic flow sensor can indicate flow rate and changes in flow over time. Because of its robust construction, with no moving parts or electronics, the acoustic flow sensor can be installed between producing zones to give zonal contribution rates similar to that achievable with conventional spinner production analysis.

SMART Well Control

BHP Petroleum’s Douglas field is located in block 110/13 in the Liverpool Bay Development off England’s North West coast. It is a low-pressure reservoir using ESP artificial lift to produce oil from several zones.

During the life of the field it is expected that there will be water ingress into the wells from one of the zones. BHP identified that a new well installation would address water shutoff by using a remotely actuated hydraulic sliding sleeve system (smart well).

It was determined that Sensa’s DTS (distributed temperature system) could identify the temperature effect due to water ingress and indicate the water producing zone, indicating which sleeve would need to be closed.

A completion comprising ESP, hydraulic on/off disconnect, retrievable packers with hydraulic feed-throughs and hydraulic Interval Control Valves (ICVs) was installed on the Douglas Platform during December 2000.

Sensa installed their distributed temperature sensor fibre into one of the control lines that was used to actuate the ICVs. This control line was Sensa’s specialist SBF control line specifically used for fibre deployment. The system was designed so that an optical fibre could be used for monitoring each of the three ICVs to indicate which of the producing zones showed a temperature change - water breakthrough. BHP could then isolate that zone.

As the Halliburton (PES) mini-hydraulic system was initially designed purely to operate hydraulic sleeves. It was modified to ensure that fibers could be deployed successfully for the duration of the well’s life. This required a new design of on-off wet-connect and a hydraulic isolation tool (HIT) to facilitate fibre installation.

BHP installed the Sensa/Halliburton intelligent ICV system in December 2000. Once the completion was nippled up and fully tested, the optical fibre was deployed into one of the control lines. 5,100 ft of fibre were installed, tested and connected to the surface equipment.

Sensa’s surface equipment was already installed on the platform having been monitoring the distributed temperature in another well for 20 months. This included a remote access facility for data extraction, configuration etc. All that was required to activate the distributed temperature system was to link the new well’s downhole fiber to the existing surface DTS computer.

Temperature traces are transmitted directly to BHPs and Sensa’s offices for interpretation. During the later part of December 2000, there was a noticeable drop in the temperature (approximately 5°C) of the production fluids observed in the optical fibre at the upper completion zone. Analysis of other surface parameters revealed that, coincident with this temperature change, the platform had observed a dramatic increase in water cut from below 20% to over 35% (mainly injected water). With this type of measurement across the entire production interval and the ability of the ICV system to isolate specific zones, production of water can be located and minimized.

Frankenburg, A., Bartel, P., Roberts, G., and Hupp, D.: “An Optical Probe Tool For Measuring Gas Holdup Is Referred To In Gas Shutoff Evaluation And Implementation, North Slope, Alaska,” SPE 62892, 2000 SPE Annual Technical Conference and Exhibition, Dallas, Texas 1–4 (October 2000).

Recent advances in production logging technologies, including a new optical probe tool for measuring gas holdup, have provided the ability to directly measure gas holdup (Y_g) in horizontal well bores. This measurement has greatly enhanced our ability to quantify oil and gas contributions from producing intervals. Evaluation of the production profiles was at minimum a two-phase problem (oil and gas) and usually three phases were involved. Production logging tools were chosen to allow evaluation of three-phase downhole fluid conditions in the horizontal wellbores on a perforation set-by-perforation set

“Enhanced recovery techniques used in Prudhoe Bay include produced water and gas re-injection to maintain reservoir pressure as well as miscible injectant to increase displacement efficiency. Both of the gas injection techniques, along with natural pressure depletion, have created free-gas entry points within existing well completions.”

“The tool string selected was chosen not only because it could identify fluid entry points, but also because it could accurately identify three-phase fluid contributions for each interval logged. The tool string included gamma ray, temperature, pressure, X-Y caliper, spinner, water hold-up, and the new optical probe tool for the identification of gas holdup and its distribution across the casing at downhole conditions.

The total tool length was 20.6 feet. Each part of the tool string was included for a specific measurement. The gamma ray (GR) and casing collar locator (CCL) tools were used for depth control with the GR tool also being used to identify possible radioactive scale. The spinner tool was used to measure fluid velocities by using multiple passes at varying tool speeds, similar to traditional spinner evaluation.”

Horizontal wells typically exhibit stratified flow with holdups that are deviation dependent, which complicated the evaluation of velocity of the different phases. The small casing size and high velocities reduced the uncertainty created by stratified flow. The temperature survey provided information for PVT calculations, including conversion of downhole rates to surface rates, and helped identify fluid entry points. Typical temperature gradient analysis had to be modified for the horizontal wells, as there is little to no vertical depth variation in this environment. The pressure survey was also used for PVT and downhole-to-surface rate calculations. The centralizer located at the spinner probe provided an independent X-Y caliper measurement. This hole size measurement allowed accurate flow rate calculations in the presence of enlarged or reduced casing ID.

The water holdup tool allowed measurement of water holdup where the fluid velocity did not exceed the limitations of the tool. When the downhole fluid velocity exceeds 350 ft/min, the water holdup measurement is not able to distinguish hydrocarbons from water. In this environment, the optical probe tool provided additional information through direct measurement of gas holdup. The new optical probe tool was used to identify gas holdup for this project.

The tool consists of four optical probes spaced on centralizers, providing gas holdup (Y_g) and its distribution across the casing. The optical probe tool also measures the gas bubble count rate, caliper, and sensor orientation through a relative-bearing measurement. An image of the gas holdup distribution can be generated, aiding the interpretation of this sensor data. A light source is connected to a fiber optic cable, which attached to the optical probe. The amount of light reflected from the tip of the optical probe is indicative of the phase of the fluid on the probe. A patented "Y coupler" allows the measurement of the reflected light at a photodiode located in the tool. Gas holdup is obtained by calculating the percentage of time the probe returns a gas signal relative to a predetermined time interval. A gas bubble count (B_c) rate is calculated by summing the number of gas bubbles impinging on the tip of the probe in the same time interval. In addition, evaluating the optical probe tool response enabled us to identify oil holdup due to the optical properties of the liquid hydrocarbon. While most of the wells had very low water cuts, the ability to distinguish three-phase holdups was valuable to this project.

The horizontal nature of the wells in this project necessitated pushing the tools to the bottom of the wells. Two options were considered for this: coiled tubing and tractor. Both options allowed surface readout to monitor tool operations providing excellent opportunities to quality control the logs, ensuring acquisition of the necessary data to evaluate these wells. The tractor allowed acquisition of data while logging both down and up. The down passes were restricted to a single tool speed, but the up passes were made at multiple tool speeds. Coiled tubing-conveyed operations allowed logging in both the up and down directions at multiple speeds. Friction caused by flow in the casing/coiled tubing annulus typically reduced the well flow rate but did not affect the ability to identify gas and liquid entry into the wellbore.

A well test prior to performing the production log evaluation indicated 1421 BOPD, 16 BWPD, and 27.6 MMscf/D gas. The tool string consisted of gamma ray, CCL, temperature, pressure, X-Y caliper, spinner, water holdup, and optical probe. The presence of the coiled tubing inside the small liner caused the production rate to decrease during the logging operations because of the increased friction created by the small annular area. In spite of the reduced production rate, gas and fluid entry points were clearly identified from the production logging data (See Fig. 4). The spinner indicates high fluid velocities across the entire logged interval with a slight increase at the middle-perforated zone and larger increase at the top zone. The optical probe tool indicates near 100% gas holdup from the bottom zone with liquid entry

Tague, J.R., Hollman, G.F.: “Downhole Video: A Cost/Benefit Analysis,” SPE 62522, 2000 SPE/AAPG Western Regional Meeting, Long Beach, California (19–23 June 2000).

“In the past few years, downhole video has emerged as a viable and cost-effective means for analyzing various wellbore problems. Despite this, numerous misconceptions concerning the cost, application, and complexity remain. In an effort to provide insight into the proper application and selection of this unique tool, the results of over 30 downhole video logs conducted by Chevron in the West Coalinga field will be presented and discussed. Examples will include images obtained of damaged liners, casing holes, and corrosion problems, as well as their application to remedial well work. Other examples will include images of the in-situ producing environment, in particular, the ability of downhole video to image fluid entry and the impact of various wellbore plugging agents including scale and organic precipitation. Finally, the total cost of running a video log and the steps necessary to prepare a well will be compared to more traditional means of logging. Overall, this paper should provide valuable insight for anyone considering the use of downhole video.”

In many cases, downhole video technology has become the logging method of choice due to its unparalleled ability to accurately assess the downhole environment. However, downhole video technology is not applicable in all cases.

The first attempts to use camera technology in a wellbore occurred in the 1940’s at the request of a local pump manufacturer located in the San Joaquin Valley. The early attempts led to the capture of black and white pictures on stereoscopic slides that were used with a viewfinder to create a 3-D aspect. These early cameras were very large in diameter and limited to depths of up to 1000 feet. Technology led to further developments in downhole video deployment in the 1960’s through development of coaxial cable capable of handling the transmission of high frequency signals required for motion video. In the early 1990’s, an Electro-Opto logging cable was developed utilizing fiber optic technology. This greatly enhanced the ability of the camera by addressing pressure constraints and opening up new applications in production logging. The downhole video camera uses Electro-Opto fiber optic technology. This technology produces real time video at 30 frames per second with a working temperature of 257 F to 350 F, depending on tool diameter. The tool is made up of three basic components – the electrical chassis, the centralizer, and the “Backlight” camera. The light source is positioned above the camera in the same housing. This facilitates indirect illumination, as well as creates an unobstructed view of the wellbore. This coupled with a surfactant applied to the camera lens allows the operator to descend into the well through an oil/gas column of several thousand feet and maintain the ability to image the wellbore where a clear fluid is the primary medium. This technology is routinely applied to pumping wells with minimal preparation. In many cases, by shutting in the well and allowing the fluids to separate, clear real time video can be achieved. Today, downhole video technology is a viable diagnostic tool for many downhole applications. Downhole video technology has been used for numerous applications including mechanical inspection, open hole logging, formation damage analysis, fishing operations, as well as detection of fluid and sand entry.

Limitations include well preparation, cost, and the inability to piggyback the system with other logging tools. The largest limitation or obstacle to successful imaging is the effort required to prepare the well. In many cases, the wellbore fluids are too opaque to obtain a clear image. If the produced fluids are too opaque to provide a clear image, then additional effort is required to obtain a clear image. There are also costs of running the tool.

A final disadvantage of the tool is its limitation to the field of vision and the inability to piggyback other logging tools with the system. Thus any attempts to gain data beyond the wellbore required multiple logging runs. However, several companies are working on combining the downhole video camera with a suite of production logs including spinners, tracer tools and even gamma and neutron tools. When introduced on a regular basis, this will make the downhole video/combo tool the preferred method of production logging. The problem is a common field occurrence and other symptoms exist, it is often less expensive to run a simple mechanical profile log, or even an electro-magnetic casing inspection tool. However, if the nature of the damage is uncertain, running a video log often proves invaluable. Fishing Operations. In fishing operations, if the initial attempt to remove the lost tool or item fails, running a camera

McKay, G., Bixenman, P.W., Watson, G.: “Advanced Sand Control Completion With Permanent Monitoring,” SPE 62954, 2000 SPE Annual Technical Conference and Exhibition, Dallas, Texas (1–4 October 2000).

“Permanent downhole monitoring can provide valuable information for production decisions without the need to perform an intervention to gather data. This type of technology has been excluded from sand control completions because of the complexity of placing measuring devices in the production interval. This paper describes the completion design of an openhole, horizontal, gravel-packed completion with permanent monitoring equipment in the production interval. As is typical for gravel-packed wells, the completion is run in two trips: the sandface completion is run in the first trip, and the upper completion is run in the second trip. The sandface completion includes two hydraulic lines in a U-tube configuration with a hydraulic wet connector at the top of the completion string. The completion is gravel packed using an alternate path technology that decreases the risk of a failed gravel pack placement due to hole collapse or losses. It also allows placement at lower flow rates, thus reducing the risk of damaging the hydraulic control lines. The upper completion is run and stabbed into the hydraulic wet connect. The hydraulic lines provide a continuous, environmentally protected conduit for the fiber-optic line. Once the upper completion is run and the wet connect is tested, the hydraulic lines are flushed and the fiber-optic (distributed temperature sensor) is installed.

Openhole gravel-packed completions have a high cost of intervention to evaluate the well performance. In many cases the cost can be prohibitive and may deter an operator from gathering well performance data needed to manage the reservoir. The challenge of incorporating permanent reservoir surveillance sensors has historically been avoided in unconsolidated formations requiring sand control. Complexities such as sensor position, conductive isolation, packer interface, deployment protection, and data interpretation have generally resulted in the use of nonintelligent sandface completions combined with the use of conventional logging techniques to gather data.

The use of fiber-optic distributed temperature sensor (DTS) is one such technology (currently used in platform and land wells only) that can help provide important real-time data for the life of the well. Once installed, the fiber-optic strand used in conjunction with the appropriate software and light source becomes a highly precise temperature sensor, providing the capability to measure subtle changes in thermal profile at increments of +/-1.0 m, for distances of up to 12 km. Thermal profiling along the reservoir section and over the well itself reveals trends, which when analyzed help corroborate reservoir inflow and well performance characteristics. Trend analysis can be used to help identify and in some cases manage the following downhole conditions:

· Optimization of flow rate to mitigate the above • damaged or noncontributing intervals

In addition to monitoring at the sandface, having a continuous sensor along the entire length of the well enables additional thermal data acquisition, which can establish:

Installation of the DTS fiber is the last phase of the completion operation. Because the fiber is pumped through a dedicated 0.25-in. conduit, all of the fiber connections are made at the surface. This means that in the event of fiber degradation over time, it is possible to retrieve and replace a sensor without affecting well operations or necessitating intervention.

The fiber-optic sensor is installed in a conduit line that forms a U-tube configuration with a turn-around sub located below the bottom joint of screen. The conduit is made from 1/4-in. hydraulic control line running from the surface. A wet connector is provided above the production packer to join the control line on the upper completion assembly to the control line on the sandface completion assembly. The control lines penetrate the production packer with a pressure-tight seal on the bottom and top subs of the packer. The control line is routed in a protective channel on the screen shroud to the turn-around sub.

Openhole Gravel-Pack Screen Assembly Alternate path technology was chosen for the openhole gravel pack to allow lower pump rates while ensuring a complete gravel pack. High pump rates increase the risk of damaging the control lines during the pumping operation. The openhole gravel-pack screen assembly is a shrouded 4 1/2-in. base pipe with wire-wrap screen and an eccentric shunt tube configuration. A timed thread is used on the screen joints to ensure the shunt tubes line up when the joints are made up to the specified torque. The shunt tubes are designed to guarantee gravel pack placement on long highly deviated intervals. The configuration has two large carrier tubes that run the length of the screen assembly in combination with two packing tubes that are contained within each joint. The slurry flows from the carrier tubes into the packing tubes at the top of each joint. The screens have a longitudinally welded shroud with a channel located at the weld seam. The channel is sized to contain the two encapsulated control lines used for the distributed temperature sensor. The design ensures that the control lines are not damaged when the screens are run into the openhole section.

The multiport packer is a hydraulically set 9 5/8-in. x 5 1/2-in. retrievable production packer with two bypass ports for the 1/4-in. control lines. The packer is set with the gravel pack service tool. The packer has dual setting pistons to ensure a correct set in the event that tubing movement is impossible with the long screen assembly in the horizontal openhole. The bypass ports in the packer provide a straight, uniform hole so the control lines can be easily fed through the packer. Each control line has a metal-to-metal seal in the upper and lower subs of the packer. The packer has a control line test feature that allows the control line ports to be isolated from the tubing and tested at the well site for pressure integrity of the metal-to-metal seals. Once the test is completed, the test port is removed and a plug is installed. With the test ports removed, the control line passages are once again in communication with the tubing to ensure they remain at hydrostatic pressure, thus minimizing the pressure differential across the control line seals. When the packer is retrieved, the overall length remains the same to ensure there is no damage to the control lines during the retrieval process. Damage to the control lines could result in a loose line that could form a “bird nest” and complicate the retrieval process.

A hydraulic wet connector allows a high-integrity connection for the control lines to ensure that the fiber optic can be successfully pumped through the connection. The wet connector has a large “mule shoe” to accept the male connector run with the production seals. The mule shoe has adequate strength to turn and align the male connector at the bottom of approximately 8,200 ft of 5 1/2-in. production tubing. Calculations were made to determine the amount of torsional resistance that would be generated by the production tubing if the connectors lined up 180° out of phase. The calculation shows that the torque needed to rotate the connection 180° was below the breakout torque for the tubing joints. Because make-up torque is below the rating of the connector, it was decided not to run a swivel above the connector. The wet connector also doubles as the production seal bore and production seal assembly, providing for 6-in. seals with a through diameter equivalent to 5 1/2-in. tubing. The connector has a course and a fine alignment system. The course alignment is provided by a slot at the end of the mule shoe and a mating key in the male connector. A short distance before the control line connectors start mating, a robust key and slot arrangement engages in the connector. The keys and slots have a close tolerance to the position of the control line connectors to ensure that the connections engage properly. The keys also protect the male control line connections for tubing sizes down to 3 1/2-in. The male control line connectors are positioned on the lower half of the wet connector to provide resistance to debris. A female connector in this location would tend to collect debris. Debris in the flow line connection could prevent installation of the fiber optic. The control line connectors provide a clean, straight flow path to facilitate installation of the fiber optic. No movement of the wet connect is allowable once the installation is complete, or the fiber optic could become damaged. Set-down weight of the upper completion is calculated to prevent a disconnect.

Buchwalter, J.L., Calvert, R.E., McKay, C.S., Thompson, S.J.: “Maximizing Profitability in Reservoirs Using New Technologies For Continuous Downhole Pressure Systems,” 2000 SPE Annual Technical Conference and Exhibition, Dallas, Texas (1–4 October 2000).

“Continuous downhole data in conjunction with new reservoir analysis tools made to work with this data have the potential to revolutionize the accuracy of reservoir management. The economic value of continuous downhole pressure data and the array of available options justify the use of these systems in almost all petroleum reservoir developments. The greatest value of these gauges is that with new data analysis tools reservoirs can be accurately managed early in the producing life, thus optimizing both short and long term reservoir management strategies. Traditionally, the value of these systems has been for completion optimization using a small subset of downhole data. The full value of the complete data stream has been ignored due to the large volumes of data, and the lack of software systems for efficiently working with these data. Consequently the reservoir has not been fully understood. A system of software tools has been developed to capture the full value of the data from permanent downhole gauges. This new software system automates the filtering of these data in an intelligent fashion. The resulting filtered pressure data can then input into a variety of reservoir analysis tools, for example reservoir simulation programs can now have a continuous reservoir simulation. Reservoir and production engineers can always have the optimal production strategy for the reservoir based on the current data. These tools are very easy to use, so models can be developed quickly and continually maintained with minimal effort. Typically it takes less than a week to build the initial model, and only a few hours a month to update and maintain an accurate history match. The paper will include a brief review of the downhole technologies and the software system, which makes the data accessible to reservoir simulation and other reservoir analysis tools. Applications for the filtered data in both Gulf of Mexico and North Sea reservoirs will be introduced.

Carnahan, B.D., Clayton, R.W., Koehler, K.D., Harkins, G.O. and Williams, G.R.: “Fiber Optic Temperature Monitoring Technology,” SPE 54599, paper presented at 1999 SPE Western Regional Meeting, Anchorage, AK (May 26-28).

Fiber optic distributed temperature monitoring of downhole conditions is an emerging technology that can be used to obtain important reservoir temperature information where conventional methods have failed. Due to the development of fiber coatings and improved deployment techniques, fibers are now used reliably up to 480°F in Aera Energy’s California field. Case 1 is an installation on tubing in rod pump wells has been useful in detecting early steam breakthrough and is expected to reduce the need for temperature observation (TO) wells in the future. Case 2 is a permanent installation on the outside of casing in TO wells, which is used to determine accurate reservoir temperature profiles. In one example, the fiber has shown fluid migration behind pipe, which was remediated successfully before the steam reached the surface. Case 3 is a failed attempt to use fiber to continuously monitor multilateral horizontal well temperatures to determine relative fluid contributions of the wellbores without shutting in the well.

Spatial Resolution	1.0 meters or 2.5 meters depending on the model
Accuracy	+/- 0.1^oC +/- 1.0^oC depending on the model
Resolution	+/- 0.1^oC +/- 0.5^oC depending on the model

Light Source	Pulsed Class 3 Laser
Optic fibre	Multi-mode
Temperature Analysis	Raman back scattering
Temperature range	-40° to +300° C
Single ended accuracy	+/- 0.5° C
Single ended resolution	+/- 0.5° C
Double ended accuracy	+/- 0.1° C
Double ended resolution	+/- 0.1° C
Depth increments	1 meter
Time increments	15 minutes plus
Operating Length/range	<12 km

Operating Range	0 to 18,000 psi in 2,000 to 6000 psi steps
Accuracy	+/- 0.035% of range
Resolution	+/- 0.05 psi
Repeatability	+/- 0.035% of range
Long term drift	<0.5 psi per year
Sampling frequency	1 second plus
Maximum temperature	175°C
Temperature accuracy	0.5°C
Measurement range	>12 km
Housing Diameter	0.625 inches

Frequency range	5-10,000 Hz
Dynamic range	80 db
Sensitivity	30 mV/ms²
Frequency resolution	1/20 Hz
Maximum temperature	150°C
Maximum pressure	20,000 psi
Time increments	15 minutes plus
Operating range	20 km