AU2005203588B2 - Wellbores utilizing fibre optic-based sensors and operating devices - Google Patents

Description

P/0/011 Regulation 3.2

AUSTRALIA

Patents Act 1990 COMPLETE SPECIFICATION STANDARD PATENT Invention Title: Wellbores utilizing fibre optic-based sensors and operating devices The following statement is a full description of this invention, including the best method of performing it known to us: WELLBORES UTILIZING FIBER OPTIC-BASED SENSORS C AND OPERATING DEVICES 5 BACKGROUND OF THE INVENTION L Field of the Invention.

00 00 en This inventioh relates generally to oilfield operations and more particularly to the downhole apparatus utilizing fiber optic sensors and use of c same in monitoring thecondition of downhole equipment, monitoring certain geological conditions, reservoir monitoring and remedial operations.

Za Background of the Art A variety of techniques have been utilized for monitoring wellbores during completion and production of wellbores, reservoir conditions, estimating 3 .quantities of hydrocarbons (oil and gas) operating downhole devices in the o wellbores, a d determining the physical condition of thwellbor and downhole on devices.

S. Reservoir monitoring typically involves determining certain downholed 00 00 parameters in producing wellbores a various locations in one or more producing wellbores in afield, typically over extended ime periods. Wirelinetools are most commonly utilized to obtain such measurements, which involves O. transporting the wireline tools to the wellsite, conveying the tools into the c 10 Iwellbores, shutting down the prodtionand making measurements over Sextended periods of time and processing theresultant data at the surface.

Seismic methods wherein a plurality of sensors are placed on the earth's surface and a source placed at the surface ordownhole are utilized to provide maps of subsurface stcture. Such information is used to update prior scismic maps to 16' 15 onitor the reservoir or field corinditions. Updating existing 3-D seismic maps over time is referred to.in industry as "4-D Seismic". The above described Smethodsare vtry expensive. The wireline methods are tilized at relativey large time intervals thereby not providing continuous information about the wellbore condition or at of the surrounding formations.

Pacement of pennan sensors in the weflbore, such as temperafure sensors, pressure sensors, accelerometers and hydrophones has been proposed to obtain continous wellbore and formation information. A separate sensor is utilized for each type of parameter to be determined. To obtain such measurements from the entire useful segments of each wellbore, which may 4 have multi-lateral wellbores, requires usinga large number of sensors, which SCA. requires a large amount of power, data acquisition equipment and rativelylarge.

Sspace in the wellbore this may be impractical or prohibitively exleusive.

.:Once the information hasbeeni obtained, it is desirable to manipulate 00 O downhole devices such as completion and production strings. Pior art methods n .for perfoiming such fuctions rely on.the use of electrically operated devices S with'signals for their opetration communicated through electrical cables.

0 r Because of the harsh operating conditions dovnhole, electrical cables are subject to degradatiort In addition, due to long electrical path lengths for downhole devices, cable resistance becomes significant unless large cables are used This.

is difficult to do within the limited space available in produciion strings. In addition,.due to the high resistance power requiremets also become large. One particular arrangement in which operation of numerous downhole devices becomes necessary is in secondary recovery. Injection wells have, of course, been employed for many years in order to flush residual oil in a formnnation toward a production well and increase yield from the ara. A common infection scenario is to pump steam down an injection well and into the formation which functions both to heat the. oil in the formation and force its movement through thepracticeof steam flooding.. In some cases, beatiing is not necessary as the residual oil is in a flowable form, however in some situations theoilis i such a viscous fornthat it requites heatingin orderto flow. Thus, by using steam one accomplishes both objectives of the injection well: 1) to force residual oil toward the production well and 2) to. beat any highly viscous oil deposits in order mobilize suchoil to flow ahead ofthe flood front toward the Sproduction well.

;ZAs is well known to the art, one of the most cmmon drawbacks of employing the method above noted with respect to injection wells is an occurrence Scommonly identified as 'breakthiough". Breakthrough occurs when a portion of 00 00 .the lood front reaches the production well. As happens the flood water remaining in the reservoirwill generally tend to travel the path of least resistance An d will follow the brehrough.chanel to the production well. At this poit, N movement of the viscous oil ends. Precisely when and where the.breakthrough will occur depends upon water/oil mobility ratio, the lithology, the porosity and permeability of the formation as well as the depth thereof Moreover, other geologic conditions such as.fauls and unconformities also affect the in-situ sweep efficiency.

While carefulexarnination of the fonnrmatioi by skilled. geologists can yield a reasonable understanding of the characteristics thereof and therefore deduce a plausible scenario of the it'way the flood.front will move, it has not eretfore been known to monitor precisely the location ofthe flood fr6nt as a whole or as individual sections thereof By so monitoring the flood frot, it is possibleto direct greater or lesserflowto different areas in the reservoir, as 20 4desired, by adjustment of the volume and location ofboth injection and .20 'ad ct production, hence controlling overall sweep efficiency.. By carefil cIntrol of the flood front, it can be maintained in a controlled, non fingered pofile. By avoiding premature breakthrough the flooding operation is effective for more of the total formation volunmei and thus efficiency in the production of oil is improved.

00 In production wells, chemicals are often injected downhole to treat the 0 z producing fluids. However, it can be difficult to monitor and control such chemical q injection in real time. Similarly, chemicals are typically used at the surface to treat the produced hydrocarbons to break down emulsions) and to inhibit 00 5 corrosion. However, it can be difficult to monitor and control such treatment in real 00 n time.

It is not admitted that any of the information in this specification is common Sgeneral knowledge, or that the person skilled in the art could be reasonably c" expected to have ascertained, understood, regarded it as relevant or combined it in anyway at the priority date.

Summary of the Invention The invention entails the concept of permanently disposing downhole at least one fiber optic sensor in a first well at a location for sensing at least one parameter associated with injecting a fluid into a formation adjacent the well, which may be a subterranean reservoir.

The fiber optic sensor may be utilized to make measurements of downhole conditions in a producing borehole. The measurements include temperature and pressure measurements; flow measurements related to the presence of solids and of corrosion, scale and paraffin buildup; measurements of fluid levels; displacement; vibration; rotation; acceleration; velocity; chemical species; radiation; pH values, humidity; density; and of electromagnetic and acoustic wavefields. These measurements can be used for activating a hydraulicallyoperated device downhole and deploying a fiber optic sensor line utilizing a common fluid conduit. A return hydraulic conduit may be placed along the length of a completion string. The hydraulic conduit is coupled to the hydraulicallyoperated device in a manner such that when fluid under pressure is 7 Ssuppied to thee conduiC it #ould actuatethe devic.' Thi e string is placed or convey c~ d in.i n P'wellbor Fiber optic cablecariing a-number of sensors is fo-rced:into on& end of the conduit until it returns at the surface at the other end.- Light source and signal proessing equipment is installed at the surface. The fluid is supplied under sufficient pressure to activaie the device when desired.

00 00 -The hydraulically-operated device may be a packer, choke, sliding sleeve, o perforating device, flow control valv6ompletion device, an anchor or any otherL o device. The fibr optic; sensors carried by the cable may include pressure sensrs, temperature sensorsvibration sensors, and -flow measurement sensors.

This invention also provides at method o f controlling production from a, webore. A productionstring crya n electrical submersible pump is preferbly made at the sur.: Aopticalfiber carring apluraity of fiber optic sensors is placed along a high voltage line that suppies power to the pump for taking measurements along the welbore length. In one configuration, a portion ofthe fiber canyingselected sensors is deployed below the pump. ueh sensors may includ a teede ature senso, a pressure sensor and a flow rate measurement sensor. These sensors effectvelyplce th e instamepntation package usually -installed for the pump.

in an appication ootrol of injection wells, the invent p rovids siificantly more information towell operators thus enhancing oil recovery to a degree not hretofore now This isaccom plished by pr oviding real tim e information about the formation itself and the flood-front by provi ding pennanent downhole sensors capable of sensingchanges in the swept and 81 unswept formation and/a the progression of the flood front. Preferably a Splurality of sensors would be employed to provide inf ormation about discrete portions of strata surrounding the injection well. -This provides a more detailed data set regarding the well(s).and surrounding conditions. The sensors are, preferably, connected to a processor either downhole or at the surface for 00 0O processing of information Moreover, in a preferred embodiment the sensors are o. connected.to cromputer processors which are also connected to sensors in a in.

production well (which are similar-to those disclosed in U.S. Patent No.

0* 5,597,042 which is fully incorporated herein by reference) to allow the production well to "tal" dirctlyto the related injection well(s) to provide an .extremelyefficient real time operation. Sensois emriployed will be to sense temperature pressure, flow rate, electrical and acoustic conductivity density and to detect various light transmission and reflection ihenoerau. All of these sensor tDypes are available commercially in various ranges aid sensitivities which are selectableby one of ordinary skill in the art.depending upon particular conditions known to exist in apaticular well operation. Specific pressure S. measurements will also include.pressure(s) at the exit valve(s)down. the -injection well and at thepump which may be located downhole or at the surface: .Measuring said pressure at key locations such as at the outlet, upsream of the .':valve(s)'near the pump will provide information about the.speed, volume, direction, etc. at/in which the waterflood front (or other fluid) is moving. Large differences in the pressure from higher to lower over a short period of time could *indicate a breakthroughk Conversely, pressure from lower to higher over short.

periods of time cquld indicate that the flood front had hit a barrier. These.

conditions are, of course, familiar to one of skill in the art but heretofore far les s.

9 would have been known since o workable system fo.measuring the parameters S* existed. Therefore the present invention since it increases knowledge, increases.

productiyty.

Refening now to the measurement of density as noted above, the present: .00 00 invention may use fluid densities to monitor the flood front from the trailing end. As o will be appreciated from the detailed discussion herein, the inteface between the '4T flood front and the hydrocarbon fluid provides an acoustic barrierfrom.which a 0 Cl signal can be refleted. Thus by generating acousti c signals and mappig the reflection, the pfile of the front is generated in 4D three dimensions over time..

t Distributed sensors find particular utility in the monitoring and control of various chemicals which are injected into the well.

Such chemicals are needed downhole to address a large number of known problems such as for scale inhibition and various pretreatnents of the fluid being producced In accordance with the present invention, a chemical injection .monitoring and control system.includes the placement of one ormore sensors ownhole in the producing zone for masring the chemical properties of the produced fluid as well as for measuring other dwnhole parameters of interest.

These sensors are preferably fiber optic based and are formed from a sol gel matrix and provide a high temperature, reliable and relatively inexpensive indicator of the desired chemical parameter. The downhole chemical sensors may be associated with a network ofdistributed fiber optic sensors positioned along the wellbore for measuring pressure, temperature and/or flow. Surfe.

o and/or downhole controllers receive input from the several downhole sensors, and to in response thereto, control the injection of chemicals into the borehole.

Preferably, parameters related to the chemical being used for surface treatments are measured in real time and on-line, and these measured 00 5 parameters are used to control the dosage of chemicals into the surface treatment oo00 system.

en Examples of the more important features of the invention have been 0 0 summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features of the invention that will be described hereinafter and which will form the subject of the claims appended hereto.

Brief Description of the Drawings For a detailed understanding of the present invention, reference should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals, wherein: Fig. I shows a schematic illustration of an elevational view of a multi-lateral wellbore and placement of fiber optic sensors therein., Fig. 1A shows the use of a robotic device for deployment of the fiber optic sensors.

Fig. 2 is a schematic illustration of a wellbore system wherein a fluid conduit along a string placed in the wellbore is utilized for activating a hydraulically-operated device and for deploying a fiber optic cable having a 00 00 Cn c 0 ~:number of senors along its lengt acording to o 6preferred embodiet ofth :p resen t,in v en tion

I

otcFIG. 3 shows a schematic diagramfi of a producing w.ell wherein. a fiber otccable, wit'sensors is utilized to determine the'health- of dwnkhle devices.

mnd lerltn oto -make, measuremecnts downhiolratg t sch devices and other downho6le parameters.

flG...4 is a schematic ilutration of a weilbre system wherein a pergmanently ins~talled electrically-operated device is operated by a fiber optc basedyse.

is4 ashemiatic representation of ani injection well illustrating a plurality. of sensors mounted therein.

FIG. 6 is a scenai representation illustratng both aniijection well, a nd a production well having sensors and a flood: front ninning between the..

Wells.

j i t: .12 o FPIG. 7 is a schematic representation similar td. FIG. 6 but-illustrating bJ3 fluid loss through unintended frcturing. FIG. is A schematic representation of an injectonproduction.. well 00 00 system where the wells are located on either side of a tau t ci FIG. 9 is a schematic illustation 6if a chemical injection, monitoring and contmil system utlin a te sensor arrangementand dowuhole chenilcal monitoringsensorss ::p .'no isa chma illraio ofa fiber optic sensor sytem for_:: mnitoring cheical propgtie of pmduced fids.

HG. ills a scmatci" illsratio f f"ibeotc sot gel indicatore~:~ prb for use wit .the sensorsystem of FIG. 10. FIG. 1 i a schemaic jlustrin of a surface teatment system.

FIG. l3 is a schematic of a ointrol and monitongsystem for the surface treatment systeinof FIG.'. 12.

13 'FIG. 14 is a schematic illustration of a wellbore system whein electric Spower is generated downhole utilizing a light cellfor use in operating sensors: and devices downhole.

FIGS. 15A-15C show the power section of fiber optic devices 00 00 for- use in the system of FIG. 1.

00 0 -8e"FI: SFIG. 16 is a schematic.illustration of a wellbore with a completion string having a fiber optic energy generation device for operatinga series of devicesdowihole.- FIGS. 17A iC show certain configurations for utilizing the fiber optic devices to produce the desired energy.

DETAILEDDESCRIPTION OF PREFERRED EMBODIMENTS Figures 1-17, show schematic illustrations of wellbores utilizing fiber optic-based sensors and operating devices.

FIG. .shows an exemplaiy main or.primary wellbore 12 formed from.

the earth surface 14 and lateral wellbores 16 and 18 formed from the main 7. :r 14 Swellbore 18. For thepurpose of explanatiqn, and not as any limitation, the main 0 N wellbore 18 is partially formied in a producing formation or pay zone I and partially in a non-producing formation or dry formation II. The lateral welbore 16 extends from the main wellbore at ajuncture 22into the producing formation S I, while thelateral wellbore 16 extends from the main iwellbore 12 at juncture 24 00 00 into a second producing fonation III. For the puposes of this illustration only, the wellbores herein are shown as being drille n land; however, this intention is equally applcable to offhore welbores. It should be noted that all welibore 0 C configurations show and. described herein are to illustrate the present invention: and are not be construed to limit the inventions claimed herein.

In one application, a number of fiber optic sensors 40 are placed in the wellbore 1. A single or a plurality offiber optic stings or segments; each such segment containing a plurality of spaced apart fiber optic sensors 40 may be usod to install the desired nunber of fiber optic sensors 40 in the wellbore 12. As an example, FIG. 1 shows two serially coupled.segments 41.a. and 41b, each containing a plurality of spaced apat fiber:optic season40. A light source and detector (LSID) 46a coupled to an end 49 segment 41a is disposed in the wllbore 12i.to transmit light einergyto sesors 40 and to receiversignals from the sensors 40. A data acquisition unit (DA).48a is disposed downhole to control the operation of the sesors 40, proess downhole senior signals and data, and to communicate with other equipm t and devices, including devices in the wellbores or at the surface shown below inFIGS 2 17.

Sternanvelya light-source 46b and the data ccquisition anhdptocess'ing. unitn, 48b may be placed on the surface 14. Similaly, fiber optic senr strings may be disposed in other welibores in the system, such as welibores 16 and weflbore.18. A single light source, such as lightsource 46a or 46b may be used for allfiber optic sensors ut' he'variouswelbores s s shown bythe dotted 00 00 lie 70. Altemtivl multiple sources and data acquisition unitsmay be used'..

o downhole, at the surface, or in combination. Since the same sensor may make different typesof measuremets, the data acquisition ut 48a or 48b is ci prorammed hto multiplet measurts.r Multiplexing techniqus r well ex-th& Mits. ques art well: known in'the art nd c thus not described in dtail herein. Thedata acquisition unit 46a may be programmedto control the dwnhMle sensorsa usly upon, receiving coniiazd signals from h-the-surfac or a comnbin~ation of these methods.

*MThesensors4 0 abe installedthewllboresl,6andl.8b ef&or iafte fiallngcasings ihnthwellbofes-suchascasings5ishowninstalledinthe U welbore 12. This ay be accomplishd -by connecting the stings 412 and 41 b alongtheisdcasi ngs 52. Insuch amchothesirins4l 6 and. 41 are preferably coc-ted end-to-end at the surface to ensure proper conntons of.

2 the couplings 2. The fiber optic sensors 40 and/or strings 4i and 41b may be deployed or instald by convieyingon coil tubing or pipes or other known'thod.'.Alteatively, the fiber optic sensors may be conveyed and installed.by robotics devices. This is ilusrated inHG IA where a roboticdevice 62 i's shownwith a string of sensors 64 attached to it The robotic device proceeds n dnthe wellbore 12 having a casing 52 therein to the position indicated by 16 S 62' deploying the string of sensors in the position indicated by 64'. In addition to install inrg sensors, the robotic device 64 miy also perform other functins, sijch as rninitoring the performance of the.sensors,and cn ommunicating with Sother devices such as the DA the IS&D and other.downhole devices described below. The robotic devices may also be utilized to replace a sensor, conduct 00 O repairs and to retrieve the sensors or strings to the surface. Alternatively, the o fiber optic sensors 40 may be iced in the casing 52 at the surface while Sidividual casingsections (which are typically'about forty feet long) are joined S prior.to conveying thecasing sections into the borehole. Stabbing techniques for joining casing or tubing sections are known 'i the art and are preferred over rotational joints becaus stabbing gerally provides better alignment of the end SIcouplings 42 and also because it allows operators to test andinspe optical Sconnections between segments or proper two-way transmission of light encgy through the entire string 41.

In the system shown in FI., a pluralityoffiber optic sensors 40 are installed spaced apart in one or mor welbores such as wellbores 12, 16 and 18.

i i istalled sspa e vartPYL oe or Weli s~ If desired, each fiber optic sensorcanoperatein minore than one. hode to provide a number ofdifferent measurements. The light source 46a and dat detection and acquisition system 48a are peferbly placed downhole. Although each fiber S optic sensor 40 prodes measurements for multiple parameters, it is relatively snall compared to individual commonly used. single measurement sensors, such aspressure sensors,strain gauges,.temperature sensors, flow measurement devices and acoustic sensors This makes it possible to make a large number of 17 on different types.of measurements utilizing relatively:little space dowfnhoe 0 Installing data acquisition and processiig devices or units 48a.downhole allows.

making a large number of data computations and processing downhole, avoiding the needfor transmitting large amotints of data to the surface. Installing the light source 46a downhole allos locating the source 46a close to the.sensobrs 00 00 which avoids traismission of light over great distances from the surface. The rn o data froithe downhole acqisition system 4 may be trasmittedto the surface -by any suitable method including wireline connectors, electromagnetic telemetry, and austic methods. Still, in some applications, it may be desirable 0 to locate the ligh -ource 46b andorthe data acquisition and pocessing system 46b at the surface..:Also, in some cases, it may be more advantageous to S partilly processthe datownhole and par at the surfac.

Still referring to FIG. 1, any number of other sensors, generally denoted herein by numeral 60 may be disposed inany of the wellbores 12,16 and 18.

Such sensors may include sensors for determining the resistivity of fluids and .foations, gamina rayscrsors, and hydrophones. The measuremeits from the Sfiber optic sdnsors 40 and sensors 60 are combined to determine the various.

conditions downhole. For example, flow measurements froin productioin zones .and the resistivitymeasurements may be combined to determine wa saturation or to determine oil, gas and water content.

In on'e mode, the fiber optic sensors are permanently installed in the willbores at selectedlocations. In a producing welbore the sensors continuously or periodically (as programmed) provide the pressure and/or o temperaiture and/or fluid flow measurements. Such measurements are preferably N made for each producing zone in each of the wellbores. To perfonmcertain types of reservoi analyses, it is required to know the temperature and pressure Sbuild rates ihn the welbores. This requires measuing temperature d pressure at selected locations downhle over extended time periods after shutting down 00 00 aie.e he well at the surface. In prior art methods, the well is shutdown, a wireline tool is conveyed into the wellbore and positioned at one location in the wellbore.

o The tool contiiously measures temperatureand prssure and may provie other 0.

S measurements, such as flow rate ese measurements arethen utilized to perform reservoir analysis, which may included determining the extentof the.

Ir &-the. t e..

.hydrocarbon reserves remaining ia. field, flow characteristics of the fluid from.

the producin foraion, water content etc. The abovie descitibed prior art methods.do not povide continuous measurements while the well is producing and require special wireline tools to.be conveyed into the borehole. The present invention,.on the other ba provides, in-situ measurements while the well is producing. The fluid flow informationfn each zone is used todetenniie th effectieness of each prodcing zonDecreasingflow rates over time indicate problems with the flow control devces, such a screeni and sliding sleeves, or clogging of the perforations and rock natrix near the wellbore. This information ".is used to determine the coiurse of action, which may include fluther opening or.

closing sliding sleeves to increase or decrease production rates, remedial work such as cleaning or reaming operations, shutting down a particular zone, etc.

This is discussed below in reference to FIGS:2-13. The temperaire and' :.7 pressure measurements are used to continually monitor.each production zorine and to update reservoir models. To make measurements deterining the 19 temperature and pressure buildup rates, the wellbores are shut down and the.

0 ci rocess ofmaking measurements continues. This does not require transporting S wireline tools to the locati, something that can be very expensive at offshore locations and wellbores drilled in remote locations: Furthermore, in-situ measurements and computed data can be communicated to a central office or the 00'. .00 offices of the logging and rcsvoir egieers via satellite. This continuous monitoring of wellboresalows taking relatively quick action, which ca6 significantly improve the hydrocarbon production and the life of the wellbore. The above described methods mayalso be taken for non-producing zones, such .as zone U, to aid in reservoirmodeling to determine the effect of production. from various wellbores on the field in which he wellbores are being drilled.

FIG. 2 is a schematic diagn of a welIborc system 100 according to one embodiment of the present ivention. System 100 icludes a wellbore having a surface casing 101 installed a short distance from the surthce.104- After the welbore 102 has been drilled to a.desired depth. A completion or.

production string 106 s conveyed into the wellbore 102.. The string 1 includes at least one downhill hydraulically operable device 114 caried by a tubing 108 which tubing may be a drill pipe, coiled tubing or production tubing.

A fluid qoduit 110 having a desired inner diameter 1 1 is placed or attached.

either on the outside of the string 106 (as shown in FIG. 2) or in the inside of the string (not shown). The conduit' 11 is routed at a desired location on the string via a ijoint 112 soas to provide smooth tralsition for returning the conduit 110 to the surface 104. A hydraulic connection i 24 is provided from the conduiit 110 to the device 114 so that a fluid under pressure can pass fron the .0 conduit 10 to thedevice 114. After the string 106 has been placed or installed at a desired depth in the' S wellbore.102, an optical fiber 112 is pumped ilet 130a under pressure by a 00 00 source of fluid 130.

.0 The optical fiber 122 passes through the entire length of the conduit 110 N and returns to the surface 104 via outlet 130b.: The fiber 122 is then optically.

o coupled to alight soure and rcord&r (ordetector)(LS/REC) 4 A data acquisition/signal processor (DA/SP) 142 processes data/sgrial received ia the optical fiber 122.and also controls the operatioi of the light source andrecorder 140.

The optical fiber 122 includes aplurality of ensrs 120 distributed along its length. Sensors 120 may include temperature sensors, pressure sensors, vibration sensors or any other fiber optic sensor that can be placed on the.fiber Sopt-2ic cable 22. Sensors 120 i formed into the cable rge manufacturing of th cable 122. The dowhole devce l 14 may be.any downhole fluidactivated device and-may be a valve, i sliding sleeve, a perforatig device, a .20, ye a s~ ding sl& packer or any other bh y ulicallyactivated device. The dowihill device is activated by supplying fld under pressIre through the conduit f110. Details.of the sensor rangement were described above with rtference to FIGS I lA.

21 llThus, the system 100 includes aiydraulic-control line in onduit- 110 0 carried on a string 16, The control lie 110 receives fiber optic cable 122 throughout its length and is connectedto surface instrumeritation 140 aid 142 for distributed measurements of downhole parameters along its length, such as temperatuCe, pressur, etc. The conduit 106 also carries fhiid under pressure 00 00 from a source of fluid underpressure 130 for:operating a fluid-actuated device' kG.

114 such as a sliding sleeve connected to the line 110. The line 110 may be arranged dowuhole along the string 106 in aVr other coniven t shape.: he 0 fluid-actuat device 114 may also be.a choke, fluid.flow regulation device, m~~ay'.vie.: packer, perforating gun or other completio and or prodiction device.

During the completion ofkthe wellbore 102, the sensors 120 provide useful measurements relating to.their associated downhole parameters 'and the line 106. is used to actuate a dowhole device. The sensors 120 coitinue to .prvide infprmation about the downholeparamneters over tine; as discussed; aboe with refetceto.FIGS I IA., Downhole devices may be controlled using optical fibers.

Fig. 2 shows a schematic diagram of a producing well 202 that preferably with two electric submersible pumps CSP") 214 one' S forpumping the oil/gas 206 the surface 203 and the other to pump an separated w ater back into formfation The formation flui 206 flows from a producing :Packert 21 d.21~0b zone 208 into the wellbore 202-via perforations20 Packers Oa and1b installed below and above the ESP 214 force the fluid 206 to flow to.the surface 22 O203 viawpumps ESP 214. An oil 1water-sparaor 250 separates the oil and water i and provide them to their respective pumnps 214a- 214b.A choke 252 provides desired back pressure. An instrument'package 260 And pressure sensor s installd in the pump string 213 to measure related parameters during production. The'present invention utilizes optical fiber with embedded sensors.

00.

00 toprovide measureinmts of selected arameterssuch as tepecrature, pressure, In o vibration, "flow rateas dcibed-below. ES Ps 214'.run atvety high voltage o *wch i issupplie d ~froma hih voltage source 230 at the surfacevii a high c-'l :v oltage cable 224. Dueotehig carried by the cable 224, lcrcal sensors are genea btt placen or aon side the'cable 224.: As shown in Fig. 4, a fiber optic cable 222 carrying sensors 220 is placed along the power cable 224. The fie opic-le22i ex.ee toblow the ESPs 214a~dt6b to tesensors i h instrumentation packae 20 and to povide control to the.devices ifdesired hi one application, the sensors 22measure vibration and teperatue of'the ESP 214. It is desirable topeate the ESP at aiow temrature and without j excessivec vibration. TheES? Z14 speed isadjusted so as o maintainone or bothsuch parm bebe low their predeteinmaxim value orwithin their respective predetermined ranges The fiber optic sensors are used ini thiis' ap cafion td toconinuously or periodi cally determine the physical conditiozf (health) of the ESP. Toptic cae 22m e extended or gcdeployed1222. in" below the ESP at the time of installing theprducption 'striin 218 in the manner desnbd wirespect to .FIG: 2 Such a configuration may be utilized to continuouslyrneasure-donll parameters, monitor the hr1fiof downhill'.

M FIG. 4 shows a schematic of a weilbore system 400 wvherein a permanently. installed electrically-operated device is operated by a fiber optic 00 00 based systemn. The system 400 includes a wellbore 402 and an electricallyo operated-device 404 installed at a des ired depth, whhmay be a sliding sleeve, a Vo ch e, afluid flow control dvice etc., An electric cntrol unit 406controls the operation of the device 404 A priducion tubing 410 installebovje thedevice A0 44 lows'formation fluid to flow t othe surface 401. During the manuacur .of the string411tht ~incd.s the device 404and the tubing 410, a c 42 is clamped long th lenth of the -tin 410with cl.amps 421. An opticalh *couple 407 is provided- at the electrical control'unit 40.6 which can maiate with a.

coupler fed through the conduit 422.

S-Either fpior toor atr placingtstring 410i 402. ibr optc cabl 4 l inte cnduit 42 so that a coupler422a at the cable 421 endwould coule with the coupler 407 of thecont l unit 406. Alight source440 Provdesthelgenr to. the fibc 42. A plurality ofsensors420 may be deployed alongthefiber422 asdescribeefore. Aa sensor prefealy.

pmvided on the-fiber 422 detmines -the flow rate of foriba flid,414 flowinthrugth the device 404. Command si s are sent by DAIS 442 to actvae the device.404 viathe fiber 422. hes signs arc detected by the control unit.406 which in turn operate the device 404 Thi in the configuration 24 of I f 4, fiber optics is used to provide two way conunuication between 0 downhol devices d sensors and a surface u nit andto operate do ole d evices 00. A particular application of the invention is in thecontrolof dowhole devices in secondaryrecovery operatinion Refering to .G 5, oie of ordinary skil in the art will.a ppreciate a sche ic TOrsetton of an injection.well Asrecognizable will be the representation o flod front 52) which mncates fromthe ijection well andi intended tovpogresstoward a product6on well. This is also wel represented in FIG.. ofthe presntapplicatiQn: In the .present invention at least oe andpreferaby, a plurality f sensors 512 are located: perantlyinstalled in the injection well and-whici areconnected via: .the electrical wire cabling or.fiber optic cabling to aprocessor whichmay either be a permanent downhole processor or a surfce proeessor..me system provides inrnediate real .time information regarding the codition of the fluid front.having been injected into the formnation by the injection well. Bycarefully monitoring parameters such as conductivity, fluid density, pressure at the injction ports 514' or at 516 Nyh b wh tpositio or at the pump 516 (wch while represented at the surface can be positioned.

dowhole as well), acoustics and fluorescence.for biological activity, one n ascertain significant information. about the progress of the flood front such as whether the front has hita barrier or whether the front may have."fingered" resulting in a likely premature breakthrough. This information is extremely valuable to the operator in order to allow remedial measures to prevent occurrences that would be detimental to the efficiency of the flooding operation.

-thatwoulbe. etrim S.-Remedial actions include the opening or closing of chokes or other valves in 0 0 N' increments or completely in order to slow down particular areas of injection or bD increase the speed ofparticular areas of injection in order to provide the most uniform flood front basedupon the sensed parameters. These riinedialmeasures can be taken eitherby personnel at the surface directing such activity or 00 00 automatically upon coimand by the surface cntroller/processor on downhole ermn in'. b ri 66 processing unit 518. The sensors contemplated herei may be in the in tion c well or in both the.injection well and the production well. They are employed in N .several different methods to obtain infornation such as that indicatedabove.

107 Control is further heightened in an.alternate embodiment.by providing a link between downlihole sensors in the poduction well to the downhole sensors in the injection well as.well as a connection to the flow control tools in both 6 dyqable con'~e t en..

wells. By proiding the operableconnectionsto all of these pats ofte system the well can actually run itselfandprovide the most efficient oil recovery based uponthe.creatioli and maintenance of a uniform flood front It will be iderstandable a this point to oe of ordinary skill in th art that the flood front .an be regulated'from both sides of FIG. 2 i, the injection well and the production well by opening production wellvalves in areas where the flood front'I is laggng while closing valves i areas where the flood front is advancing.

Complementary to this, the fluid inectioi valves sliding or rotating sleeves, etc. would be choked or closed where the flood froit is advancing quickly and opened more whee the flood front is advancing slowly. This seemingly complex set of circumstances is easily controlled by the syste of the 26 in .invention andpidlyremedies any. ano it inthe intended flodprofile- Cl wpo efficiepcy of the steam or other fluid front is g realy enbancd byth&".

systm of the invention. Allof the sensors ntptin t puction e andtheinje n well are, prefblyea l Isalled dwnholes sensors which arecon~cted to procssorsnlto i one kanothte by electrical cabling or 00 00 fiber optic cabling.

C l in In anotheremb6diment of the: inventionillustrated schematicallyin, FIG. 7, downhole sensrs measure strai d in the frnoon by the injected fid. Strain is arn important paramneterfor avoiding exceding the, foration parting pressure orfractuPrepressreof the formation with the inj ected fluid. By yavoioig thepeing of or widenig of natural pre-deisting fractures arge unsweptaeas f eesevir anbe avoided. The reason this info rmation izsimtpan intherglation of pes of the fluid to avoid such activity is that 1 when psu oe fafactures are created there is a pthffi 1Much less resistance fot fluid tru n through. Thu as statd earlier, since the.

ijqection fluid ill follow the path of least rsistance itwould generally rn in t hef fraczres and arod areas of the'reservoir that need to be swept. Clearly this s.ubstanally redces itsefficicency. Thesituation is geerally referred to in the 2 artasan"arifcially highjebiif ychannel.";i Another deimment to such a condn is the uncontrolledloss of injected fluids.% This is-clearly aloss of oil due to fie-reducedeffifi i qyfof hel-mp and~aditionaUV..=Yftlyfit rtio ::asar econom.. :oh~ic drain: e to-the 1 6 fl~~e~q uids.* m r 27: SFIG.7 schematically illustrates the embodimeit and the condition set.

0 O Sforth above by illustrating an injection well. 550 and a production well 560.

Fluid 551 is illustrated.escaping via the unintended fracture from the formation.

554 into the overlying gas cap level 556 and the underlying water table 561 and S it is evident to one ofordinary skill in the art that the fluid is being lost in this.

00 00 location. The condition is avoidedby the invention by using pressure sensors to o -limit the injection fluid pressure as described above. The est ofthe fluid 552.s Sprogresig as it is intended to through the formation 554. In order to easily and 0 reliably detemine what the stress is sin the formation 554, acoustic sensors 556 are locat in the injection well 550 at various points.therein. Acoustic sensors which are well suited to the tak to which they will be put in the present inv entio f S. Innov: invention are commercially available from Systems Innovations, Inc Spectns Corporation and Falmouth Scientific, Inc. The acotic sensors pick up sounds generated by stress in the formation which propagate throgh the servoir fluids or resvoir matrixto the injection well. In general, highe sound levels would indicate severe stress in the formation and should generae a reduction in pressure of the injecte fluid whether by automatic control r by technician control. A data acquisition system SS9is preferable to render the system S extremely reliable and system 558 maybe at the siurface where it is illustrated in the schematic drawing or may be downholc. Basedtipon acoustic signals received the system of the invention, pref b ly automatically, although.

manually is workable, reduces pressure of the injected flid by reducing pump pressure Maximum sweep efficiency is thus obtained.

28 Si n Y etanther embodmeit ofthe invenion asschemarically illustrted' Ypeo edtd.ter n:i Sin- FIG. 8, acoustic generators andreceivers are employed to dtermine whether Oil a formation which is bifurcated by a flt is sealed along the fault oris permeable along the fault. It is knownby one of ordinary skill in the art that d ifferenit strata within a formation bifurcated by a fault may have some zones oo00 that flow and soine zones thatare sealed; this is the illustration of FIG. 8.

00 0 .Refening directly to FIG. 8, injection well 570 employs .a plurality of serisors

O%

S 572 and acoustic generators 574 which, most preferably, altemate with 0 Sinreasig depth in the welbore. In production well580, a similar arrangement of sensors 572 and acoustic generators 574 are positioned. The sensors.and generaiors are preferably connected to processors which are either downhole o: on the surface and preferably also connect to the associated production or injection well. The sensors 572 can receive acoustic signals that are naturally generated:ina the formation, generated by virtue of the fluid flowing through the formation from the injection well and to the production well andalso can receive signalswhich are generated by signal grierators 574. Where signal generators 574 generate signals, the reflected signals that are received by sensors 572 over a period of time can indicate the distance and acoustic volume through which the acousticsignal have travelc This is illustrated in area A of FlG Sin that the fault line 575 isealed between area A ad area B on the figure. Thisi illustrated for puiposes of clarity only by providing circes 576 along fault-liie 575.1 Incidentally, the aicas of fault line 575 which are permeable are indicated.

Sbybashsarks 577 through fault line575. Since the acoustic signal.represented.

by arrows and semi urves and indicated by numeral:578 cannot propagate 2& through the area C of the drawingwhich bifurcates area A from area B on. the :29.

it i. let side of the dtwing, that signal will bounce andit then can be picked up by sensor 572. The ti delay, number and intensity ofreflections and.

mathematical inre o wich is common inthe atovide an* indication of thelack ofpresswre transnissivity between those two zones. Additionally this' pressure transmissivity can be confirmed by the detection by said.acoustic 00 00 signals by sensors 572 in the prodiction well 580. In the drawing the area o ;directly Ibeneath arca A is indicated as area E is peeable to area B throigh fault 575becausethe region in that area is permeable and will allowI flow of the flood front fron the injection well 570 throughfailt line 575 to the prduction well 580. Acoustic sensors and generatos can be employed her as well since the acoustic signal witravel though the rea and, therefore, reflection intensity t the recei'ers 572 will decrease.. Time delay will increase.

Since the ksois and generators are connected to a central processing unit and to one another it is a simple operation to.determine that the signalin fact, traveled from onewell to the othe'and indicates penmcability throughout a particular zone. Byprocessing the information that the acoustic.generators and sensors can provide the ijection and production wellscan n automatically by determining where fluids can flow and thus opening and closing valves at relevantlocations.

on the injection well and prod ion well i order to flush production fluid in a direction advantageous to run through a zone ofpermeability alongthe fault.

Other information can also be generated by this alternate system of the invention since the sensors 572 are clearly capable of receiving not only the Sgenerated 'acoustic signals but natually cuing acoustic waveforms arising 2 from bothi the flow of the injected ids as the injection well and from thos arising within tie reservoirs in result of th fluid injection operatipris and O simultaneous drainage of the reservoir in resulting production operations. The S. preferred permanent deployment status of the sensors and gdnerators of the invention permit and see to.the measurements.simultaneously with ongoing injection flooding and production operations. Advancements in both acoustic: oo nIasurement capabilities and signal processing while.operating the flooding of iO 0 n 6 h -gcal d cj tat te p art Cc, the, rc~c-servoir ~r~repr~ sents 4 s1'bmifi cap tcho t. 10 van n nor~Uckr~q requires ra ons. in ord I requires -cessation.of the injection1 production operationi order to monitor o acoustic paranmeters downhole. As oneof ordinary skill in.the ar will recognize the cessatiozi of injection results in natural redistribution of the active flood.

profile due primaily to gravity segregation of fluids and entropic phenomena tha not present during active flooding operations. This clearly also enhances .the pssibility of prematurc. breakthrough, as oil migrates to the relative top.of 'the fornion ad the injected fluid usually water, migrates to the relative., bottori of the fonrmation, there is a significant possibility that.the watr will actually reach the production well and thu s further pumping 6f steam or water will merely mndern t the laye of oil at the to of the formation and the sweep of that region would be extremely difficult thereafter.

S0 .In yet another embodiment of the invention fiber optics are eMiployed (simi ar to those disclosed in the U.S. application SeriNo. 60/048,989 filed on June 9, I997(which is fully incorporated herein by reference)to determine the amount of andlor presence of biofoulini within the reservoir by providing a culture chamber within the injection orproduction well, wherein light ofa predetermined wavelength may be injected by a fiber optical cable, irradiating a 31 S sample determining the.degree to which biofoulimay have occurred. As one of ordinary skill in th art will recognize, .various biofouling organisms will have- Sthe ability to fluoresce at a given wavel gth, that wavelength oiice determined, i useful for the purpose above stated.'' oo In another enbodiment of the invention, the flood front is monitored 00 .from the 'ack 'employing sensors installed in the injection well. The sensors whhich are adequately illustrated in FIGS. 5 and 6 provide acoustic signals which 0 reflect-from the wa /oil interface thus providing an accurate picture in a S moment in time of the three-dimensional floo1 front Taking pictures in 4-Di.e., three dimensions over real time provides an accur foiat of the density profile of the formation due to th advancing flood front Ths, a particular profile and the relative advancement of thefront can be accurately detenied by the densityprofile changes. It is ctainly possible to limit the ssors and acoustic generators to the injection well for such a system, however it is even more preferable to also iitroduc sensors and acoustic generators.in tie" prodiction well toward which the front is moving thus allowing an immediate double check of the fluidfront profile That is, acoustic generators on the .productionwell will reflect a si gnal off the oillwater interface and willprovide an equally accurate three-dimensional fluid firont indicator. The indicators from both sides of the front should agree and thus provides an extremely reliable indication of location and profile.

Referring now to FIG. 9, the distributed fiber optic sensors of the type.

described above ae also well suitedfbr use in a production Well where 32 chemicals are being injected therein.and there is a resultant needd fo the 0 N .monitoring of such a chemical injection process so as to optimize the use and ;Z effect of tch injected chmicals- Chemicals oftei need to be pumped down a.

Sproduction well for inhibitig scale. paraffins and the like as well as for other known processing applications and pretreatment of the fluids being produced.

00 00 SOften, asshown in FG.9, chemicals are introduced in an annulus 600 between th d 004pf a 'Well 606,i~~,b Thh ceri: a the production tubing 602and the casing604 of a well 606. The chemical Sinjcction (shown schematically at608) can be accomlished ina ariety of 0 Sknown methods such as in coniectionwi a submersib lepump shown for .1 example in U.S. Patent 4,582,131, assigned to tie assignee hereof and: incorporaed herein b reference) or through n auxiliar line associated with a cable used with an electrical submersible pump (suh as shown for example in U-S. Patent 5,528,824, assigned to the assignee ereof and incorporated herein by reference) -I et O. oe o mo In accordance with an embodiment of the present invention, one or ore bottomhole sensors 610 are located in the prduci zone for sensing a variety of parameters associated with the producing fluid and/or interaction of the-injete- .chemical and the producing fluid. Thus, the bottomhole sensors 610 will sense 20 parameters relative to the chemical properties of the produced fluid such:as the.

potential.ionic content, the covalent content.pHri level, oxygen levels- organic precipitates and like measurements. Sensors 610 can also measure physical properties associated wiith the producing fluid and/or the interaction of th injected chemicals and producing fluid such as the oil/water cut, viscosity and

J.

opcent olids. esors 6~0 n alSo provideifation relatdo paraffin and conten a i sale build-up, H 2 S t and dte like. Botoinoey sensors 6iefeably omuniat with and/or are ,:iseri or§ '.612' qb al; g associatedwitha plurality of distributed ss 62whii arepositionedao 00 0at least a portion of the welibore feraly the interior of the production tubng) for easuring pressure ttenpe rdlot flow rate as discussed'above c I~tubing) f rtr 0 in conedtion,with. -I Thepresent invention is-alo preferably'associated witha surfawe control and-monitoring syste 614nd one rhmore kown surfae sso 615 for sensing parameterseated to, theproduced'fluid, and more particulrly for sensingand monir the effectivenss of atreatt.rendeed by the injected chemicals.- The sensors615 associated with surface syste.= 61 cansense parameters elte d to the content andnt oC for s t 614 rc -an *eample, hydrogen sufide, hydraes, pkaflins, water, solidsand as.

well-disclosed in FIG. 9 has associated therewitha s-called'"intelligent dow ohole control and monitoring sstemni whichmy include a downhole 6omtezed contoller 618 and/or the aforeip~oacsifacct andmoni em 614. This control and momitofng system is of the tye disclosed iatent 5,597,042,' Which is assigned th bassigneehereof and flatly incorporatederin by reference.- As disclosed in Paent 5,97,042, the sensors-in the intelligent"production wells of' tI we ar associate d wit~h ~d nhol cputer and/or surface controlles which .infonnation sah fr e snsors and baed onthis information, iitiate some tqe of -control forenancinig, or oping the efficiencyf productionof the well or m 25: some othe way effecting the productin of d from the foi In the.: some on of flid s ormatom 34 Spresentivei the surface and/or downhole computers 614, 618 will manitor v-c -presen i neltcl

M

0 o the effectiveess of the treatment of the injected chemisals and based on the sensed information the control .computer will initiate some change in the mann amount or type of chemical being injected. In the system of the present S invention, the sensors 610 d 612 nay be connectedremtely or in-stu oo 0O 0 In a preferred embodiment of the present invention the bottomhole sensor compise fiber opti chemical.sensors. Such fiber optic chemical in emr rzbs cq~impnse

C

0 sensors preferably utilize fiber optic probes which are used as a sample interface to allow light from the fiber optic to interact with .the.liquid or gas stream and re urn to a -spectrometer for easurement The probes are tpically composed of sol ge indicators Sol ge indicators allow for oline, real time measurement and control through the use of indicatoiaterials trapped in a porous, sol gel Sderived, glass atix. Thin films of ti material are coated onto optical components of various probe designs to create sensors for process aid environmental measurements. These probes provide increased enssitivity to chemica species based upon charactenstics of the specific indicator. For example, sol gel prbes can measure with great accuracy the pH of a material and sol gel probes neals measurefor speci h cehmical content The sol.

matrix is porous, and the size of ffe pores is determined by ho, the glass is prepared .The sol gel process can be controlled so as to create a 6ol gel iidicator.

composite with pores small enough to trap an indicator in the rmatrix but large.

enough to allow ions .of aparticular chemical of interest to pass feely in and out and react with the indicator. An example of suitable sol gel indicator for use in F 5 thprcsent ietoisf shown in FIGS. 10 and 11.

S Ref'ening to, FIGS. 10 and 1.1,.a probe is shown at 616 connectedlo a: '.fiber optic cable 618 which is in turn connected both toa light source 620 and a own in FiG. probe ncludes a sensor housing 624 connected to, a lens 626. lens 626 has aolcoat 628: thereon wich 00 00is tailored to mreasure a secific downbole parameter such as PH or is selected to detect the presence, absence or amount of a paricular chemical such as oxygn, kT

'H

2 S or the like. Atached to and spaced horn lens 626isa mior 630. Dring 0 use, lightf fromthe fiber optic cble 618 is collimated bj lens 626 whereuponi the 0 ight pases thrugh the sol gel coating 628 and sample space 632. The light is *then, refected by mirrbr 630and reu to the fiber optealcable. Lit Strinsmnitted by the fiber optc a e is measured by tspctrometer 622. Spectrometer 622 (as wl light, souce620) ma be located either at the.

surface orat some location dowphol. Based ori the spectrometer measuirements, a cotrOl cpmputer 61,66 will the measureent -MIS 3Wm thtage the amoint (dosage andcone ntrati)ate or type of chemical being injected downhole into the well. Information. from the'cheical injection apparat *relating to amount of chemicalleft'in storage, cemical quality level and the like Will alo beb senxttotelh coIgro copt s The controlcompute may also bise its. control decision on input received fom sce senr 615 relating to the effectiveness of the chemical treatment on the produced fluid, the presene and coc ati-on of any unpu'nb es orumndesired by prducts and the like In addition to the bottoinhole sensors 610 being comrisd of te fiber ,optic sot -gel tye ensors, inadd n hed sensors612 along ind I otiFn tubing 602 mayMrna so'incudethe fiber optic chemical sensors (ol-gel.

o 'Abiydicators of th~e p discussed aove. -In this way, the chemical contetft of the production fluid may be m6nitred, as it travels up the production tubing if that is desirable.

S00 T 00 permanent placement of the sensors 610,612 and controlsystem' 0 M cI 61.7-dowhol in thewellastoas ignificant'advanice in the field -and'D~ for real tin6, remote control of che a injeins into a well without the need o for wireline device or other wellintrventions.

fcr w irelin- er.we l.' Referring to Fig. 12, a typical surface treatment system used for treating produced fluid in oil fields is shown. As is well known, the fluid produced from the well includes a combination of emulsion, oil, gas and water. After these well fluids are produced to the surface, theyare contained in a pipeline known as a "flow linc. Tbe flow line can range P in enth fom a few fet to seeral thousandfeet. Tyicaily, the fowv line -is' connected directly into a series of tanks and treatment devics which, rei intended to provide separati of the water in emulsion from, the oil and gas. In addition; it is intended that the oil and gas beseparatedfor. transport tothe The producedlthuds flowing in thieflw line and the various seprtion technqus which act on these produced fluids lead to serious corrosion problems. Presently measurement of the rate of corrosion on the variou metal 37.

kn components-of the treatment systems such as the.piping and tanks is 0 accomplished by a number of sensor techniques including weight loss coupons,-.electrical resistance probes, eectrdchemical linear polarizatiori techniques, electrochemical noise techniques and AC.impedance techniques. While these sensors are useful in measuring the coosion rate of a metal: vessel or pipework, 0 00 6 do not provide any.inform on reative to the chemicals C themselves, that isthe conetion cterizati on or other parameters of n chemicals introduced into the treatment ysteim. These chmicals are introduced 0 0 for a variety of reasons including corosion inhibition and emulsion breakdown, as well as scalew asphaltene bacteria and hydrate control.- Sensors may be used in chemical treatment systems of the type disclosed in Fig. 12 which monitors the chemicals themselves as opposed to the effects of the chemicals (for example, the i rate of corrosion). Such sensors provide the operator of the treatment system with a real time understanding of the amount of chemical being introduced,the.itansport of that cheicathroughout the system, the concentraion of the chemicalin the system and like parameters. Examples of suitable sensors.which maybe. used to detect parameters relating to the 20.- chemi cal traveling through the treatment system include the fiber optic sensor Sdescribed above with reference to FIGS. 10 and 1 as well as other known sensors such as those sensors based ona variety of technologies including, ultrasonic absorption and reflecon, laser-heated cavity spectroscopy.(AMS) Xray fluorescence spectroscopy, neutron activation spectroscopy, pressure measurement, microwave or milimeter wave radar reflectance or absorption, 38.

and other optical andacoustic (i e. -ultrasonic or so nar) methods. A suitable microwave sensgor for sensing moisture and other constituent s in the solid and liquid phase inlunt and effluent stramis is described in U.S. Pateiit:No...

5,455,516" all of the contents of which are incorporated herein by teference.. An.. S examp .le of a suitable apparaus for'sensing using TARS is .disclosed in U.S.

00 0 ei b 00 PatentNo. 5,379,103 all of th contents of which are incorporated herein by eeng m i' heLSA o Irefere An examplef a suitable appa fora senisinge LS s the LA.SMA LaseMas Analy availablefromAdvanced-PowerTchnoogiesnc o Washinton, D.C. An example. of suitable ultrasoniq sensor is disclosed -inU S.-Patent 5,148,700 (all of the cntents ofwhich are incorporated herein-by.

reference). A suitable commrcially a vailable acoustic sensor is sold byEntey Design, Inc., of DetTexs under the traderk MAPS. Preferably, the, sensor is prated ta multiplicityof frequencies hd signl streng Sitable millimeter waverada teciques used in conjunction withtp n ti n 15 are described.in chapter IofPrinciples andApplications ofMillimter, Wave Radar dited by N.C. Curie andC.2E. Brown, Artecn House, Norwood, MA', 19S7., The ultrasonic'techbogoy rfeztced above can be logically extended to millimeter wave dcs ,WiJlethesnsors maybetutilized ia syem such as shownnflG 12, at a vanety of loctions thearrows nuinbered 70,throuh 716 indicatthose.

psitions where afonn a on relaive 0t the chemical intoduction would be e]pcially useful 39 S Referring now to Fig. 13, the surface treatment system of C Fig. 12 is shown generally at 720. The chemical sensors 700-716) will sense, in real time, parameters concentration and 2 classification) related to the introduced chemicals and supply that sensed iThfonnation to a controller722 (preferably a computer or microprocessor based 00 0': 00contrller Based, on tiat qnsed if o monitored t dontrollt 721, the Cl, controllerwill1struct a pmp or otherm mteringdevice 724 m ainvary. or.,.

I. otherwise alter the amount of chemical andlor t fe of chemical bing added to 0 0 hthe sface treatment ystem 720 The supplied cheiical fro tanks 726 72' and 726" can of course,.comprse any suitable tiratment chemical such as those chemicals used to treat corrosion, break down em ulsions etc. Examples of suitable coosion inhibitors include long chaizramines or aminidiazolines SSuitable commercially available chemicals iiclude CronoxO whichl is a corrosion.ihibitor sold by Baker Petrolite, a division of Baker-Hughes, Incorporated .of Housto Texas.

thus; in accordance with the ontrol and minonitoring system of FIG. 13, based on information provided by the cbhemical sensors 700 716, corrective measures can be taken for varying the injectionof the chemical (corrosion inhibitor,nulsion breakers, etc.) into the system. The injection point of these chemicals couldbe anywhere upstream of the location being sensed such as the loction where the corrosio is being efised. Of course this injectioi point could include injections dowuhole. In the contexC of a corrosion inhibitor, the".

inhibitors work by foring a protective film on the metal and thereby prevent water and corrosive gases from coroding the metal surface. Other surface '4h ns in&lude emulsion breakers which break the emulsion and ~n .treatmnt chemical, ldeeulio A f aciitate water removal. .In. addition to rempying or breaking emulsions-, c theials are alsoa introdced to breakout and/oir remove solids, w, ec Typic~aly chemicals are introduced so as to provide What is known as a base'.

sediment and water (BS. and of less than%.

00 00- S In addition to' diepa-rmters reating to th chemicl introduction being.:.' sensed by chemical sensors 7007. 716. the monitoring and control system of the cpresent invention can also utilize known corrosion measurement devices as well including fow rate, temperature.and pressire senors. These other sensors'are sduienatienily shown in FIG. 13 i723 and-730.. The' peent inventiopn thus provides a mcans forenasuring parameters rlat$ to the introduction of chemicalsnto the systminreal teandonline. Asmentione, these parametericudcical ncnraioi and mayalsoinclude such chemical W pa eteinpl u I d Coc propctiC aspotenia ioni conet the covylen~ctcntpgj leeoye levels,, organic precijpitaes and li measurements. Sirilaly, oil/water cut vis cosity and peret solids can be measureidas well as paraffin and scale buildpzconciland thebikq Another aspect is the ability to transmit optical energy *downhole and co nvetit to another f oft, n stio downhol devics FIG. 014 shows a tiellb~pere 80ih a prin string 804 having one or mote electricaLly-opeted or opticallyopermted devices, generally denoted hein by num eal 850 and one or more dowhole sensors 814. The suing 804includes battenes 812 which provide electrical power to the devices 41: 850 and sensors 814. The battees are charged by generating power downhole 0 by turbines (not shown) or by supplying power for th&. Atrfac& ia a cable (not Sshown).. Light cell 810 is provided in the string 804 00 oo which is coupled to an optical fiber 822 that has one or more sensois 820 en o asociated therewth light soqurce 840 at the surface Iroides light to the light k- fght- v e S.cell 810 which geerates electricthiych charges th e downhill batteries 812.

0 C The light cell 810 essentialy trickle charges thie batteries In:many applications 'the downhole devices, such as devices 850, are activated infrequently. Trickle charging the'batteries may be ufficient and thus may eliminate the use of other poer genration devices. In applcationsrequing greater power consmtion the light cell may be aused in cojunction with othr power generator devices.

tmavly ifthe device 850 is optically-activated the fiber 822 is coiled to the device850ss bte dotted line 82 and is activated by* cp ld i 'i i e supplying optical pulses from the surface unit 810. Thus in the configuration of FIG. 14, a fiber optics device isutilized to generate electrical energy downhole, whichi thentised t cagea soulice, such a battery, or operate adevice The fiber 822 is also used td provide two-way conimriunicatioi between the DA/SP 842 aiid'downholesensors and devices.

FIG. 15 is a schemaii illustratiin of a weilbore system 900 utilizing fiber optic energy producing devices, r 42 O System 900 includes a wellbore 902 having a surface casing 901 installed a relatively short depth 904a from the surface 904. After the weilbore 902 has been drilled to a desired depth, a completion or production string 906 is conveyed into the wellbore 902. A fiber optic energy generation device 920 placed in the string 906 generates mechanical energy. The operation of the 00 fiber optic device 920 is described in reference to Figs. 1SA-1 SC.

00 In' rn 0 c c The fiber optic device 920A show'n in Figrlle 15A contains a K seal~d chaniber 922a containing ags 93 w h will epn rpdly when opticpl enaslaserergy asisapplied tote gs 923 A Piston 924a disposed -in the evice otard whengas 92 3ea When the optical energy-i's not beig aplied to the gas 923a spring92$aor another. suiitable device coped to apiston rod piston 26abacktoitsoriginal position.- The gas 923 is periodicaly chargedwith the opticalenergy conveyed to the device 920avao o nductororfier 94. 'FIG 15B'shows the,, optical device 920B wherein a spring 926b is disposed witin. the' enclsure 921 to urge the pton 924b back to-its oi position.

Refeig hack to FIG. 1the Qutward motion of the niember L.

925.of the'device 920 causes a valve 930 to open allowing the welibore fluid 908at the hydrostatic pressure to enter through port 43 932.,The..valve-930 iscoupled to hydraulically- operateddevice 935in, ci a mann~ r that allows the fluid 908under pre ssre to enter the device 935 via the port 932. Thus, i in theconfiguration of FIG. 15, fiber optic device 920 controls'te flow,.of the fluid 908 at the hycarostatic -pressure to the hydraul callyp erated device 935..The device 935, 00.

00 b a r, fluid valve, safety valve, peforating device; anchor, sliding sleeve: etc. .The operation ofthedevice 920 is preferably* kr) c 9"0, t ouic, e L. s th controlled from thesufce 904.a light.suce LS 940 provides the optical energy to the device 908. via the "fiber 944. Oneormore sensors 927 may be provided to* obtain. feedback relating to the downhok opertions. The sensors 927 provide measurements downhoopqratons.' ating to the fluid flow, fr aplied to thv lv -:downhole pressures, downhole temperatures etc. The signals'from sensors 927 May be. processeddowuhole or sent to.thie surface data acquisiton and procesingnit 942 via the er An, alternatee embodimento a light ate transducer for use m-i fudflow. control ii show;n inFG MS. The'device 950.

includes a photovoltaic cel 960 a. bi..maph elementfud av cel90 pia nerigy from anotical fiber 944 is-connecdbymeane'of optical lead -946 to a photovoltaic cell 960.' The photovoltaic cell 960 upon. excitation. by liht pr-oduces, an electric currenLt that'is" conveyed by lad-962 toor ae e imetallicsti (bi-mrh element) .964 Passage of current through the bimetalic strip causes it to bend to' ;.7 44' position.964'.and move aball 980 thatressin a valve s at976.

0Motion'ofthe- ball 980away from'the seat to 980. enables a fluid 982 Ci .toflo:through the inlet ort 972jin theh.-i-morvhelement.fudval Lve ell 97 an d the outlet port 974. Other arrangements of the bimetallic strip -and. the valve arrangement would be famiihar to those 00 00 This -fflustrat e' :~uioment intn whioptic -erg 0 -inyet ainother emabodiment ofthe inv ow the S. optcaenrgisused 'to ialedthphsica propsee ries of a Phowosensitivemateral, such as a-get that is incorprated inai flowcontrol device. Screens having a gravel pack are commonly, used in oil and- ga's production to screen out pariculaLte matter. In'one embodiment of the invention, aphotosensitive gel is used ias the: packing material in the screen. Activation of the gel 'byoptia energchanges the physical haracteristrics of 'the, gel,: partially crystallizing git.This makes, it possible'6 to adjust thes p flowing throughlthe screen.L 18 shows welbore system, 1000 wherein the fiber optic devices 1020 are used topraore ol devices and <wherein the pressurized fluid is suplid through a conduit which.

also carries the optichafiberto -the deices 1020 from the surface 904.

A valve 1030 is oerated by the fber optic device 920 in the manner l 7 described above with reference to FIG. 15. Pirssuriied fluid 1032 from asource 1045 is sipplied to the valve 1030 via a conduit 1010.

The conui1010 the oqpticatfibe-r1044 ispumped through the conduit from an the surface. Alternatively, the conduit 1010 containing the fiber 1044 may be assembled'at the su rface. an i 00 deloyed into the weJbore withthe strng1006. Tooperate the'device- 35, the fiber optic device 920 is operated and the fluid .1032- under' pressure is continuously supplied-to the vdlire.,1030 via the conduit 1010, w ich activates or sets the device 1035. Other downhoe- -ib devices 10Sb L1050c etc.may b6 disposed in the string 1006 or Mi the welbore 1002. Each suh device utilizes separate. er op SdevicOe.s920 andmay utilize. a common conduit 1010 for the opcal Sfiber 1044L andlr for thepressurxized flid 1032.

I. AshG.o1 w configuration utilizing multipl fbr o ptic ds120a-1 .to 0generate rota.rypower. Tedevices ~I h..d s .1120A: S1.20c are' imbilar to te .devices 920 descnbed ab Light energy is preferablyprvided to such dvices via acommon optical fiber 1144-: The source 940operates the devices 1120a Zoc in a particular order with a predetrne phse dierenc. An address system (not L shown) my be utilized to addressthe devicesy signals for such devics, The:piston arms 1127a 1127c are coupled to a cam shaft 1125'at locations 1125a:.. 12k es~pctly whcrtei the direction 1136 to provide rotary power The rotary. power may be 0 c k c) 46 utilized for any.deniedpurpose, such as to operate a pumpor, a generator togenerate electrical power- SFIG 17B- 17C shows.a cdnfiguration wherein the fiber optic devices are used to.pumfluids. The fiber optic devices I182aofflG 17 contains a i 00 firing cylinder 1IS4an d a secondcylinder 1184b. The second or hydraulic MS cylinder contains an outlet poi 11 83b. Suitable fluid is supplied to the hydraulic '4Th. .cylinder via the inlet port 1183 When the device 1182a is fired, the pistori S 1186 moves downward,blocking the inlet port 1183 and simultaneously displacing the fluid 1186 fronm the cylinder 1184b via the outlet port 1183b. The.

spring 1185 forces the piston 1186 to return to its original position, uncovering the inlet port until the next firing of the vice 8. I this manner the device.

182 inay be utilized to pum fluid... The flow rate iscontrolled by the firing frequency and the size 9f the fluid chamber 1184b.

SFIG. 17C shows two fiber optic devices 382b and382c (similar to the device 382a) conne ted in series to pump a fluid In this configuration, when the device 382b is fired, fluid 390 from the channels 391 of the device 382 discharges Eio the chamb&,391b of the device 32c via line 392' A one-way .0 check valve allows the fluid to flow only in the directio of the device 382c.

The firing of the devie 382 discharges the fluid from the chamber 391b via *line 394 to the niext stage.

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b13 47 While the foregoing disclosure is directed to the preferred embodiments of the invention, various modifications will be apparent to those skilled.in theart.. it is intended that all variations within the scope and spirit of the append ed claims be embraced by the foregoing disclosure. i

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Claims (2)

1. 2. An automatic injection/production system including: an injection well having at least one sensor and at least one flow controller; a production well having at least one sensor and at least one flow controller; at least one system controller operably connected to said sensors and said fluid controllers whereby said system controller controls said flow controllers according to information received by said sensors.
2. 3. A method for enhancing hydrocarbon production wherein at least one injection well and an associated production well include at least one sensor and at least one flow controller, including: providing a system capable of monitoring said at least one sensor in each of said wells and controlling said at least one flow controller in each of said wells in response thereto to optimize hydrocarbon production.