conceptos fibra optica.pdf

Copyright 2001, Society of Petroleum Engineers Inc. This paper was prepared for presentation at the 2001 SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, 30 September3 October 2001. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

Abstract Development and exploitation of oil and gas resources in increasingly difficult operating environments such as deepwater raise many technical challenges. Among these is the ability to provide assurance on the completions and production from high-cost and complex wells. Real-time, permanent wellbore and reservoir monitoring is a critical technology for providing assurance and maximizing profitability of these fields.

Recent developments in fiber optic sensing technology have resulted in reliable alternatives to conventional electronic systems for permanent, downhole production and reservoir monitoring. In-well fiber optic sensors are now being developed and deployed in the field for measuring temperature, pressure, flow rate, fluid phase fraction, and seismic response. Bragg grating-based fiber optic systems combine a high level of reliability, accuracy, resolution and stability with the ability to multiplex sensors on a single fiber, enabling complex and multilateral wells to be fully instrumented with a single wellhead penetration. These systems are being installed worldwide in a variety of operating environments for a variety of applications.

This paper presents several recent deployments of in-well fiber optic monitoring systems, including descriptions of the downhole sensor assemblies, installations, and measured data. Installations of fiber optic pressure and temperature systems in a land well and in the Gulf of Mexico and an all-fiber flow and liquid fraction system in deepwater Gulf of Mexico are discussed. A general description of fiber optic sensing and Bragg grating-based sensing systems is also presented.

Introduction The past several years have seen a great increase in the development, deployment and application of permanent in-well monitoring systems. Drivers behind this increase include new field developments in much more challenging, costly operating environments; the requirement to provide assurance on the production from these new fields; and the desire to optimize management of production and reservoir recovery.

Cost. Many large, new fields coming on line today and in the near future are being developed with relatively few high-cost, high-rate, complex wells. Intervention costs in these wells will be high or even prohibitive. This puts a premium on the value of real-time downhole data during production and on the use of this data to foresee and prevent well problems.

Assurance. The large, up-front capital investment for many new field developments, such as deepwater, puts a tremendous importance on the assurance of producing the anticipated volumes of oil and gas in the anticipated timeframe, in order to make the required return. Downhole monitoring systems provide data to continuously assess the health of the well, optimize well operations, and provide assurance on the flow of oil and gas.

Optimized Production and Reservoir Management. Real-time downhole data offer many opportunities to greatly improve production management and reservoir recovery. These include actively managing drawdown to increase production performance; production and injection profiling in horizontal and multi-zone wells to identify and control fluid flow to and from different parts of the well; providing sufficient information to allow for the early determination and confirmation of reserves; allowing for active reservoir management early in the field life; optimizing drainage; and increasing overall field recovery.

In most, if not all cases, the value derived from real-time, downhole monitoring systems greatly exceeds the cost and can be recovered early in the life of the well, IF these systems are reliable and perform as specified over the life of the well and IF the data are managed properly and used to their fullest potential. Fiber optic-based sensing systems being deployed today offer the promise of achieving the level of performance required to achieve this value.

SPE 71529

The Optic Oil Field: Deployment and Application of Permanent In-well Fiber Optic Sensing Systems for Production and Reservoir Monitoring Tor K. Kragas, SPE, CiDRA Corporation; Brock A. Williams, SPE, BP Corporation; and Gregory A. Myers, SPE, Shell Exploration and Production Company

2 TOR K. KRAGAS, BROCK A. WILLIAMS, GREGORY A. MYERS SPE 71529

In-Well Fiber Optic Sensing Advances in optical sensing technology in the telecommunications and other industries have enabled the development of permanent, in-well fiber optic sensing systems that are attractive alternatives to conventional electronic systems for downhole monitoring.1,2 This is especially true in high temperature operating environments where electronic systems have historically had their highest failure rates.3 In-well fiber optic sensors are either currently available or under active development for measuring pressure, temperature, flow rate, phase fraction, strain, acoustics, and sand production. Potential future sensor developments include measurement of density, fluid chemistry, and even electro-magnetics.

Fiber optic sensing systems can be implemented in single-point, multi-point, and continuous sensing configurations, as shown in Fig. 1. In a continuous configuration the entire optical fiber is used as a sensor. The result is a log of the measured quantity along the length of the wellbore. To date, continuous configurations in wells have only been used for distributed temperature sensing (DTS)4, although distributed strain measurements are also possible. The other two sensing configurations, single-point and multi-point, involve measurements at discrete points along the length of the optic fiber in the wellbore. They offer a much broader range of measured parameters than continuous configurations, as well as higher accuracy and spatial resolution. The remainder of this paper will focus on discrete point fiber optic sensing configurations with an emphasis on systems that use Bragg grating technology. Bragg Grating Sensors Bragg gratings are intrinsic sensor elements that can be written into the core of an optical fiber by an ultraviolet photo-insciption process.5 The grating is a periodic modulation of the retractive index of a small portion of the core of the fiber, as shown in Fig 2. When broad-band light is directed down the fiber, the grating produces a narrow-band reflection whose wavelength is proportional to the modulation of the refractive index. The remainder of the light passes through the grating unaltered and may be used to interrogate other sensors written at different wavelengths. This characteristic makes Bragg gratings an important component for the telecommunications industry, because it serves as the basis for wavelength division multiplexing (WDM), the ability to carry multiple channels of data down a single fiber simulataneously. For the purposes of permanent monitoring, WDM enables multiple optical sensors to be deployed downhole on a single fiber.

When a Bragg grating is subjected to strain, for instance through a change in temperature, the reflected wavelength shifts in a manner directly proportional to the strain in the grating. Thus, the grating can be used as a form of optical strain gauge. Through appropriate packaging and calibration, Bragg gratings can be used to measure a wide range of phyiscal parameters in the wellbore.

Bragg grating-based sensors have many advantages for in-well monitoring applications. The gratings can be put through an annealing process to essentially remove drift in the

reflected wavelength, resulting in very stable sensors, even at high temperatures over long periods. Other advantages include:

intrinsic sensor element; electrically passive; high temperature operation; multi-point sensing capabilities; low profile; multi-parameter sensing; and component common to telecommunications.

Bragg grating sensors have been developed to measure a wide variety of parameters, including temperature, pressure, vibration, acoustics, and displacement.

Components of Fiber Optic Monitoring Systems In-well fiber optic sensing systems consist of four sub-systems as illustrated in Fig. 3: instrumentation unit; wellhead outlet and surface cable; in-well cable and connectors; and sensor assembly.

Instrumentation. The instrumentation unit consists of a fiber optic light source, opto-electronic interrogation unit, signal demodulation unit, microprocessor, monitor, keyboard, associated power supplies, disk drives, and data communication interfaces. It also contains the software required to control the data acquisition, conversion, storage and interfacing. In standard implementations, the instrumentation is designed to reside in a control room environment and interface with an external data management system using Modbus protocol or a serial ASCII data stream. However, it can be modified for special applications, such as stand-alone installations in the desert, jungle, or on unmanned platforms and for subsea installations where part or all of the instrumentation is contained in the subsea control module.

Wellhead Outlet and Surface Cabling. The wellhead outlet provides for feed-through and exiting of the fiber optic cable from the well in a safe and reliable manner and is similar to that for an electrical system. The standard wellhead outlet contains a minimum of two sealing barriers to every potential leak path and is rated to a working pressure of 15,000 psi. It has been DNV certified, both for design and manufacture. The connection from the wellhead outlet to the instrumentation unit is made with the optical surface cabling. On multi-well installations, a multi-core surface cable can be run from the instrumentation unit to a junction box in the well bay and separate surface cables run from the junction box to each well.

Cable and Connectors. The in-well fiber optic cable and connector system provides for light transmission to and from the downhole sensors. It is specifically designed for mechanical and environmental robustness, as well as functional redundancy, and incorporates multiple protective barriers between wellbore fluids and the optical fiber. Every attempt has been made to give the cable a look and feel similar to its electrical counterpart. Mechanical strength and protection of the cable is provided by a -inch metal capillary tube, encapsulated in a polymeric buffer. The tubing encases a specially coated, small-diameter stainless steel fiber in metal

SPE 71529 THE OPTIC OIL FIELD: DEPLOYMENT AND APPLICATION OF PERMANENT IN-WELL FIBER OPTIC SENSING SYSTEMS 3

tube (FIMT) surrounded by a buffering material. The optical fibers are packaged in the FIMT with a hydrogen gettering grease, which provides high striction forces for holding the fiber in place. Together with the cable, high-reliability optical connectors and cable fusion splicing techniques have also been developed for long-term survival in harsh downhole environments.

Sensor Assembly. The sensor assembly consists of the actual fiber optic sensors and transducers, as well as the mandrel and other equipment required to integrate the assembly into the production tubing string. The specific sensors are described in more detail in the following case studies.

Pioneer Fiber Optic Deployments The first in-well fiber optic pressure and temperature system was installed for Shell in the Sleen field in the Netherlands in 1993. It did not involve Bragg grating-based sensors, but consisted of a silicon micro-machined resonator in combination with an optical fiber. The system was designed and manufactured by Optoplan A.S. and called the FOWM system.

Between 1993 and 1999 a total of 10 FOWM systems were installed, mostly in the North Sea, as summarized in Table 1. These included five subsea installations, one of which placed the instrumentation unit in a subsea control module pod. The FOWM systems demonstrated that fiber optic sensors can be deployed in harsh wellbore environments and gave the industry and manufacturers valuable installation and operational experience. They also demonstrated that fiber optic cable and connectors can survive for extended periods in the wellbore.

In the years since the first FOWM deployments, advances have been made in several system components to improve reliability. The design of the in-well fiber optic cable has been changed to increase protection from hydrogen ingression, which results in darkening of the fiber and signal attenuation. Improvements have also been made to the wellhead outlet. The most important advancement has been the development of Bragg grating-based sensors. Since Bragg grating sensors are intrinsic to the fiber, they are not exposed to the same failure mechanisms as the FOWM gauges, and are more resistant to shock and vibration.

Bragg grating-based sensors represent the next generation of single- and multi-point in-well fiber optic monitoring systems with the promise of high reliability and longevity. The following three case studies discuss some of the first deployments of this new permanent downhole monitoring technology. Kern River Pressure/Temperature System Field Trial The worlds first permanent, in-well, fiber optic monitoring system was deployed in March, 1999, in Kern River field, near Bakersfield, California. The system consisted of a Bragg grating-based pressure and temperature gauge, deployed to a depth of 2,200 ft in a beam-pumped well. A Pruett Industries, Inc. downhole gauge was also installed in the well as a

reference. Although the field is under steam flood, the well has not seen steam breakthrough. The gauge is still operational to its original accuracy and resolution after over 10,000 cycles of the beam pump, and continues to show good comparison with the reference gauge. Fig. 4 shows a sampling of the data from the optical gauge after nearly two years of operation, illustrating the cycling of the beam pump and the data comparison. Gulf of Mexico Pressure/Temperature System The first in-well, fiber optic permanent monitoring system in the Gulf of Mexico was successfully installed for BP by CiDRA Corporation and Wood Group Production Technology, Ltd. in April, 2000. The CiDRA Bragg grating-based, single-point pressure and temperature transducer was installed at a measured depth of over 15,000 feet in a 77 deviated section of the well, just above the production packer. No additional rig time was required for installation of the fiber optic gauge over that for a conventional gauge. The performance of the gauge to-date has exceeded expectations.

Pressure/Temperature System Description. The single-point fiber optic pressure gauge provides real-time measurements of wellbore temperature and pressure.6,7 It is 100% optical, contains no downhole electronics, is temperature compensated, and is designed to have a long life at high temperatures. It utilizes two Bragg gratings, one primarily affected by system temperature and one affected by system temperature and pressure, packaged into a single all-glass sensing element. The transducer housing contains an oil-filled dual buffer tube assembly to prevent direct contact between the wellbore fluids and the sensing element and to serve as shock protection for the element. Maximum continuous operating conditions of the transducer are 150C and 15,000 psia. Installation. Prior to shipment offshore, the transducer was welded onto the fiber optic in-well cable and secured to the cable spool. This avoided the need for any fusion splicing or welding on the platform. The cable spool and transducer were shipped along with the gauge mandrel, wellhead outlet, surface cable, instrumentation unit, fiber optic support cabin, optical field deployment kit, and backup gauge to the platform well in advance of the completion. All surface equipment, including the instrumentation and surface cable, was installed and checked out prior to the completion to enable immediate data collection when the tubing was landed.

Installation of the fiber optic pressure and temperature system is very similar to installation of a conventional downhole electronic gauge system. Figs. 5 through 7 show pictures from the installation. The pressure gauge was fed from the spooling unit, through the cable sheaves, and bolted into the gauge mandrel, which was installed in the production tubing string (Fig. 5). The mandrel is specially designed to protect the transducer during the trip down the hole.


In addition to the fiber optic cable, a methanol injection line and a subsurface safety valve line were installed in the well. During the run-in-hole, these three lines were carefully fed through the automatic slips. At each tubing joint, standard LaSalle clamps were used to secure all three lines to the tubing string.

To penetrate the tubing hanger, the outer buffering material was stripped from the fiber optic cable and the -inch tubing passed through the hanger and spooled in the hanger bowl (Fig. 6). Swagelok fittings were installed above and below the hanger to provide a double seal. The fiber optic cable exited the well through the DNV-certified wellhead outlet, which provides two additional barriers to pressure communication with the outside environment.

Once outside the well, a 48-core fiber optic cable was run from a junction box to the surface instrumentation unit, providing flexibility for installation of additional optical sensing systems in the future. The optical fiber is terminated at the instrumentation unit in the control room (Fig. 7).

During the run-in-hole, optical checks of the gauge were performed approximately every 1000 ft by connecting to the surface instrument. These checks were carried out during other well completion activities and resulted in no additional rig time during the installation. This also provided wellbore temperature and pressure data during the run-in. Data. The surface instrument in this installation acquires a pressure and temperature reading every 2.7 seconds. A serial ASCII data stream is sent to a RTU system, which is linked to the platform data historian. A subset of the data is pulled into the data historian system for permanent archiving with other platform data. In addition, all of the data is stored locally on the instrumentation unit, resulting in approximately one megabyte of uncompressed data per day. Periodically the data is downloaded from the unit. The platform data system allows data access to personnel both on the platform and on shore.

A sampling of the pressure and temperature data from the first nine months of operation of the gauge is shown in Fig. 8. Noted on the plot are a pressure transient test and several well shut-ins. Having a real-time pressure and temperature gauge installed in the well means that each of these shut-ins, planned or unplanned, is an opportunity to perform a buildup analysis and to gain valuable information on the health and performance of the well and reservoir.

Approximately one month into the life of the well, a pressure transient test was conducted to determine well and reservoir parameters. An electronic gauge was also installed at the surface for the test. There was an attempt to deploy two memory gauges via wireline for the test as a check on the optical gauge, but this failed due to the inability to run the gauges beyond the 77 deviation.

Fig. 9 presents pressure data from the downhole optical gauge and the surface gauge during the pressure transient test. Fig. 10 show the optical gauge data on an expanded scale. While there was no absolute check of the downhole shut-in pressure data from the optical gauge, it was consistent with the

pressure calculated from the fluid gradient using the produced gas composition.

Because of fluid compressibility effects, the electronic surface gauge data was useless for pressure transient analysis purposes. In fact, careful examination of the surface data reveals a slight decrease in pressure during the buildup portion of the test. On the other hand, pressure transient analysis of the data from the downhole optical gauge allowed interpretation of both wellbore and reservoir parameters, including skin, permeability, reservoir pressure, and drainage area. Results from this analysis were used in decision-making on future management of the well.

The fiber optic gauge in this Gulf of Mexico well continues to perform within specifications, with no deterioration in data quality. The data is currently being used to manage drawdown as the well is put on compression. A second in-well fiber optic pressure and temperature system will be installed in another well on the same platform in mid-2001.

Deepwater Gulf of Mexico Fiber Optic Flowmeter In October, 2000, the first-ever fiber optic flowmeter was successfully installed for Shell by CiDRA Corporation and Nova Technology Corporation in a deepwater Gulf of Mexico well.8 The CiDRA two-phase flowmeter was deployed from a tension leg platform in 3,000 ft of water to a measured depth of over 21,000 ft. It delivers real-time measurements of downhole flow rate, water fraction, pressure and temperature to the surface instrumentation unit located in the platform control room. Installation of the flowmeter was performed as planned with no additional rig time required. In fact, the entire well completion operation was finished ahead of the budgeted schedule. Early performance data indicates that the meter provides flow rate and phase fraction data to within 5% absolute accuracy, as specified. Flowmeter Description. The flowmeter for this installation was designed to be compatible with 3-inch nominal diameter production tubing with a 3-inch internal bore. It consists of two subassemblies, a pressure assembly and a flow assembly, as shown in Fig. 11. The pressure assembly is about 5 ft in length and contains a 15,000 psi pressure and temperature transducer. The flow assembly is about 12 ft in length and contains the velocity and phase fraction sensors. Maximum overall diameter of the tool is 5.60 inches and the overall length is about 20 ft. Maximum operating conditions of the meter are 125C and 15,000 psia.

The two-phase fiber optic flowmeter system provides permanent, downhole monitoring of wellbore pressure, temperature, volumetric flow rate, and water or gas fraction. It contains no downhole electronics, is completely non-intrusive (full-bore), contains no moving parts, and thus has the potential for high reliability. The system is deployed with the production tubing string during well completion in a manner similar to conventional, electronic downhole monitoring systems. It is capable of measuring volumetric flow rate and


water fraction over the full range of water cuts to within 5% absolute accuracy for most oil-water applications.

The meter uses fundamentally new multiphase flow measurement methodologies which take advantage of the high bandwidth capabilities of optic fiber and the ability to multiplex many sensors on a single fiber. All sensors in the flowmeter are based on fiber Bragg grating technology, and are therefore very stable and capable of high reliability. Phase fraction is determined from a acoustic-based sound speed measurement that utilizes the contrast between the speed of sound of the two phases, e.g., oil and water. Volumetric flow rate is determined from a series of full-bore, cross-correlation based sensors that perform equally well in single and multiphase flow regimes.9

The flowmeter has been tested at several flow loop facilities worldwide. Testing included a wide range of oil and water types; flow rates; oil, water and gas fractions; and meter orientations. The flow loop evaluations demonstrated the ability of the meter to determine volumetric flow rate and water fraction to within +/-5% absolute accuracy over the full range of water cuts at bulk fluid velocities over 3 ft/s.10

Installation. As in any well completion operation, successful deployment of the flowmeter system depends not only on the integrity of the technology, but also on careful and efficient execution of the installation. Prior to deployment, regular weekly teleconferences were held with representatives of the flowmeter vendor, the installer, and the operating company, to coordinate planning and logistics. All surface equipment, including the instrumentation unit, the surface fiber optic cable and wellhead outlet, were shipped, installed and tested well in advance of the completion. This enabled system to be hooked up and data to be logged shortly after the flowmeter reached total depth. The flowmeter assembly, backup gauge mandrel, spool containing 29,000 ft of fiber optic cable, optical support cabin, and optical field deployment kit were shipped offshore to the platform a few days before the installation. They were set up, checked out, and ready to go in the hole the next day.

Installation of the flowmeter was similar to installation of any other production tubing-conveyed system. Figs. 12 through 14 show pictures from the installation. Optical checks of the flowmeter and pressure and temperature measurements were performed approximately every thousand feet of completion. Since these checks were conducted while the rig crew was picking up more tubing, they did not contribute to any downtime. The flowmeter was landed at a measured depth of 21,138 feet three days after the start of the completion. The well completion was finished approximately three days ahead of the budgeted schedule and no lost rig time was attributed to installation of the flowmeter. Data. Early-time performance of the fiber optic flowmeter has exceeded expectations and demonstrates the value of real-time downhole production data. Along with providing the production engineer with downhole pressure data to control drawdown while the well was being ramped up, data from the

flowmeter provided other valuable information during well startup.

Figs. 15 through 18 illustrate some of the valuable information that was obtained from the early-time flowmeter data. Fig. 15 shows the pressure and temperature data taken during the flowmeter run-in, providing a temperature and pressure profile of the well. Fig. 16 plots downhole flowing pressure versus downhole flow rate for three different periods, providing a direct measure of the well productivity index, as opposed to relying on predictions from a reservoir simulator. Fig. 17 shows the downhole pressure and flow rate during a well test, along with the average flow rate determined by the test separator. Note the variability in the actual downhole flow rate and pressure during the test. Downhole flow rate measurements offers the opportunity to test the well at any time without having to use a test separator. Finally, Fig. 18 plots the downhole flow rate and pressure versus time during well clean-up. The periodic, gradual increase in downhole flowing pressure and decrease in flow rate corresponds to the choke becoming clogged with solids, followed by a "rocking" of the choke to dislodge the accumulated solids. In addition to these applications, as was discussed previously in the fiber optic pressure/temperature gauge case study, having a real-time downhole gauge provides pressure buildup data during each well shut-in, planned or unplanned.

Although the well was shut-in shortly after it was brought on line, the flowmeter has continued to provide downhole pressure and temperature data since installation. A fiber optic pressure and temperature system will be installed on the same platform in mid-2001, with the possibility of a second fiber optic flowmeter installation in late-2001. Conclusions Real-time downhole production data has been a dream of production and reservoir engineers for years. In many of todays new field developments this data has become a necessity. Permanent in-well fiber optic monitoring systems are increasingly being turned to as a reliable alternative to conventional downhole systems. Significant advantages of optical sensiing systems include no downhole electronics and high temperature operation. Bragg grating-based fiber optic systems offer additional advantages of high stability, high flexibilty, multi-parameter and multi-point sensing, and being intrinsic to the fiber. The systems described in this paper have accumulated over four years of in-well operating experience without a failure. In addition to pressure, temperature, flow rate, and phase fraction, Bragg grating-based sensors are being developed to measure acoustics, strain, and displacement. As these systems continue to develop a track record of reliabity, they will provide a wealth of data to improve the management of oil and gas reservoirs. Acknowledgements The authors gratefully acknowledge BP, Shell Offshore, Inc., and CiDRA Corporation for permission to publish this work. The authors would also like to acknowledge the significant efforts of coworkers in BP Exploration, Shell Offshore, Inc.,


CiDRA Corporation, and Optoplan A.S. and of personnel in Wood Group Production Technology, Ltd., Nova Technology Corporation, and Pruett Industries, Inc. in the development and installation of the systems described in this paper.

References 1. Udd, E.: Fiber Optic Sensors: An Introduction for Engineers

and Scientists, John Wiley & Sons, New York, (1991). 2. Kersey, A.D.: A Review of Recent Developments in Fiber

Optic Sensor Technology, Optical Fiber Technol. (1996), 2, 291.

3. van Gisbergen, S.J.C.H.M and Vandeweijer, A.A.H.: Reliability Analysis of Permanent Downhole Monitoring Systems, paper OTC 10945 presented at the 1999 Offshore Technology Conference, Houston, Texas, May 3-6.

4. Hartog, A.H., et al.: Distributed Temperature Sensing in Solid Core Fibers, Electron. Lett. (1985), 21, 1061.

5. Kersey, A.D., et al.: Fiber Grating Sensors, J. Lightwave Technol. (1997), 15, No. 8.

6. Kersey, A.D.: Optical Fiber Sensors for Permanent Downwell Monitoring Applications in the Oil and Gas Industry, IEICE Trans. Electron. (2000), E83-C, No. 3, 400-404.

7. Kersey, A.D., Gysling, D.L., and Bostick, F.X.: Fiber-Optic Systems for Reservoir Monitoring, World Oil (1999), October, 91-97.

8. van der Spek, A.M., Gysling, D.L., Myers, G.A., Purdy, G.E., Tucker, C.F., and Rambow, F.: Deep Water Deployment of Downhole Two-Phase Fiber-Optic Flow Monitoring System, paper submitted for SPE publication, June, 2001.

9. Gysling, D.L., Vandeweijer, T., and van der Spek, A.: "Development of a Permanent Downhole Two Phase Flow Meter," paper presented at the SRI 2000 Multiphase Metering and Pumping Conference, Houston, Texas, February.

10. Gysling, D.L., and van der Spek, A.M.: "Fiber Optic Downhole Multiphase Flow Meter: Flow Loop Evaluation for Oil/Water Mixtures," paper presented at the National Engineering Laboratory Downhole Instrumentation Seminar, Glasgow Scotland, October 23, 2000.

Table 1. Pioneer In-well Fiber Optic Deployments

Field Year Operator Completion

Type Depth

(ft) Temp.

(F) Press. (psia)

Sleen 1993 Shell Land 5,900 185 1,800 Gyda 1994 BP Platform 18,000 320 6,750

Guillemot 1996 Shell Subsea Pod

6,900 230 6,000

Heron 1998 Shell Subsea 13,800 338 13,500 Heron 1998 Shell Subsea 13,800 338 13,500 Heron 1998 Shell Subsea 13,800 338 13,500

Egret 1998 Shell Subsea 13,800 338 13,500 Marnock 1998 BP Platform 12,500 320 10,500 Marnock 1999 BP Platform 12,500 320 10,500 Marnock 1999 BP Platform 12,500 320 10,500

Single-Point Sensor

Single Sensor Location

Continuous Sensor

Distributed Sensor

Multi-Point Sensor

Multiple Sensor Locations

FiberCore

PhotoimprintedGrating

L

Input Spectrum

InputSignal Transmitted

Signal

Transmitted Spectrum

ReflectedSignal

Reflected Spectrum

De

P

l

P

llB l

Pstrain-induced

shift

lB

Strain

Fig. 1Configuration modes for permanent in-well fiber optic sensor systems.

Fig. 2Section of optical fiber with a Bragg grating written into the core. The grating acts as a wavelength-specific reflector of light. When the grating is subject to strain, the reflected wavelength shifts in a linear manner. Thus, the grating can be viewed as an optical strain gauge.


Qualified for high temperature & pressure,

H2S, corrosives

Cables & Connectors

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Flow,Liquid Fraction,

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DistributedSensing,Multi-well

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Buffer Tubes

Pressure Foot

Fig. 5Fiber optic pressure and temperature transducer being installed in the gauge mandrel, in preparation for deployment in a Gulf of Mexico well.

Fig. 6To penetrate the tubing hanger, the 1/4 fiber optic cable was passed through the hanger and spooled in the hanger bowl. Swagelok fittings above and below the hanger provided a double seal.

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Fig. 7The multi-core fiber optic surface cable was run from a junction box to the instrumentation unit in the control room.

48 Core Cable

Fig. 8Sampling of data from the first 9 months of operation of the fiber optic pressure and temperature gauge in a Gulf of Mexico well. Pressure divisions are 500 psia and temperature divisions are 25F.

Fig. 3Components of an in-well fiber optic monitoring system.

Fig. 4Data from the Bragg grating pressure gauge at Kern River field after two years of operation, compared with data from a reference gauge. Note the correspondence in pressure cycling data as the beam pump unloads.


Single Fiber Optic Cable

Pressure and Temperature Gauges

Standard Premium ThreadConnectors

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12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:0012:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00Time

Shut-in Step Rate Test Buildup TestShut-in Step Rate Test Buildup TestShut-in Step Rate Test Buildup Test


Electronic Surface Gauge

2900

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12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00

Pres

sure

, psi

a

12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00Time

Shut-in Step Rate Test Buildup Test


2900

2920

2940

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2980

3000

12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00

Pres

sure

, psi

a

12:00 18:00 0:00 6:00 12:00 18:00 0:00 6:0012:00 18:00 0:00 6:00 12:00 18:00 0:00 6:00Time

Shut-in Step Rate Test Buildup TestShut-in Step Rate Test Buildup TestShut-in Step Rate Test Buildup Test


Fig. 9Comparison of data from the fiber optic downhole gauge and an electronic surface gauge during a pressure test.

Fig. 10Expanded-scale plot of data from the fiber optic downhole gauge during a pressure test.

Fig. 11First-ever in-well fiber optic flowmeter delivers real-time pressure, temperature, flow rate and water fraction data.

Fig. 12Fiber optic cable spool and support cabin on the riser deck, along with spools for chemical injection and safety valve lines.

Fig. 13The fiber optic flowmeter is lifted from the transport cradle on the rig floor by the pipe lifting system, hoisted in place, and installed in the production tubing string. The cable clamps are shown in the foreground.

Fig. 14Standard clamps are used to secure the fiber optic cable, along with the safety valve and chemical injection lines, while running in hole. Right photo shows the line being fed through the automatic slips.

Fiber Optic Cable SpoolFiber Optic Cable Spool

Fiber Optic Flowmeter


7400.0

7450.0

7500.0

7550.0

7600.0

7650.0

7700.0

7750.0

1500 2000 2500 3000Flow Rate (bpd)

Pre

ssu

re, p

sia

time period 2:36-4:02



Fig. 15Pressure and temperature data obtained from the flowmeter while running in hole, providing a log of the well.

Fig. 16The fiber optic flowmeter enables a direct determination of productivity index during well startup. Here, downhole flowing tubing pressure is plotted versus downhole flow rate for three periods, showing excellent consistency of data.

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17:45 18:15 18:45 19:15 19:45 20:15 20:45 21:15 21:45 22:15Time

Flo

w R

ate,

bp

d

7200.0

7210.0

7220.0

7230.0

7240.0

7250.0

7260.0

7270.0

7280.0

7290.0

7300.0

Pre

ssu

re, p

sia

Total Flow Rate, bpd downholeWell Test, bpd @ separatorPressure, psia

Fig. 17Downhole flow rate and flowing pressure during a surface separator well test. The difference between the average separator flow rate and the average downhole rate is an indication of the formation volume factor of the oil.

Fig. 18Downhole flow rate and flowing pressure during well clean-up. The pressure increases and flow rate decreases as the choke clogs, and then recovers when the choke is rocked.

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PS

IA)

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Pressure

Temperature

6000.0

6200.0

6400.0

6600.0

6800.0

7000.0

7200.0

7400.0

7600.0

7800.0

8000.0

1:57 2:27 2:58 3:28 3:59 4:30 5:00 5:31 6:02 6:33Time

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ssu

re, p

sia

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tal F

low

Rat

e, b

pd

PressureTotal Flow Rate

conceptos fibra optica.pdf

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