GB2354583A

GB2354583A - Method of obtaining improved geophysical information about earth formations

Info

Publication number: GB2354583A
Application number: GB0031132A
Authority: GB
Inventors: Nils Reimers; John W Harrell; Iii James V Leggett; Paulo S Tubel
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 1996-10-09
Filing date: 1997-10-09
Publication date: 2001-03-28
Anticipated expiration: 2017-10-09
Also published as: WO1998015850A1; NO991667L; GB2354822B; GB2354583B; GB2334104A; GB9908166D0; NO991667D0; GB0031132D0; CA2268104A1; GB2354822A; NO335379B1; GB0031129D0; CA2268104C; AU730715B2; AU4902297A; GB2334104B

Abstract

The method comprises permanently deploying a plurality of fiber optic sensors in a survey wellbore, each said sensor having a fiber optic element detecting a seismic wave using said fiber optic sensors for detecting seismic waves travelling through the subsurface formations and processing the detected seismic waves to obtain geophysical information about the subsurface formation.

Description

2354583 MLE: NMHOD OF OBTALUNG D"ROVIM GEOPHYSICAL MORMAT10N "OUT E"TH

FORMAnONS

Field of the Invention

This invention relates generally to the placement of wellbores and management of the corresponding reservoirs and more particularly to selectively drilling one or mom wellbores, for conducting seismic surveys therefrom to improve the sSemo and utilizing the improved pgraphs to determine the type and course of wellbores, fbr developing a field. The method of the presew invention fwther relates to obtaining io seismic information during drilling of the vmUbores and during production of hydrocarbons for impmving hydrocarbon production from the reservoirs. The method of the present invention finther relates to using the derived seismic information for automatically controlling petroleum production wells using downhole computerized control systems.

Backemund of the Invention Seismic surveys are performed fi-om surface locations to obtain maps of the structure of subsurface formations. The. se surveys are in the form of maps (re&rred herein as seismographs") depicting cross-section of the earth below the surveyed region or area Three dimensional ("3D) surveys have become common over the last decade and provide significantly better information of the subsurface formations compared to the previously available two-dimension (M") mwmys. The 3D surveys, have significantly reduced the number of dry wellbores. StM,'sinm such s6smic survLys are performed from the surface, they lose resolution due to the distance between the suzf= and the desired hydrocarbonbeadng formations, dips in and around the subsurface formations, bed boundary delineations, which- is typically several thousand &PA.

Surface seismic surveys utilize relatively low fi-equency acoustic signals to perform such surveys because such signals penetrate to greater depths. However, low frequency provide lower resolution, which provides low resolution High frequency signals provide relatively high resolution botmdary delineations, but attenuate relatively quickly and are, thus, not used fbr performing seismic surveys from the surface.

Only rarely would an oil company drill a weUbore without fwst studying the hs for the area The number of wellbores and the path of each wellbore is 3.o typically planned based on the seismographs of the area. Due to the relatively low resolution of such seismographs, wellbores are fiNuently not drilled along the most effectve wellpaths. It is therefore destrable to obtain improved seismographs prior to drilling production wellbores. Additionally, more and more complex wellbores are now being drilled, the placement of which can be improved with high definition seismographs.

Furthermore, relatively recently, it has been proposed to drill wellbores along contoured paths through and/or around subsurface fbrmations to increa e potential recovery or to improvet production rates of hydrocarbons. In such cases, it is even more critical to have seismographs-tha relatively accurately depict the delineation of subsurface formations.

Conventionally, seismographs have be= updated by (a) performing borehole wifich is typically conducted while drilling a weflbore and (b) by crosswell tomography, which is conducted while between a number of producing wells in a region.

In the case of borehole' a seismic source.seismic source generates acoustic signals during drilling of the wellbore. A numbtr of receivers placed on the stufice receive 2 acoustic reflections from subsurface formation boundaries, which signals are processed to obtain more accurate bed boundary information about the borehole. This technique helps improve the surlitce seismographs in piecemeal basis. Data from each such well being drilled is utilized to conUMA&Y update the seismographs. However, such wellbores are neither plarmed nor optimally placed for the purpose of conducting subsurface i i surveys Thew wellpaths; and am are detenmined based upon potential recovery of hydrocarbons. In the ca of cross-wall tomography, acoustic signals are trmistnitted between various trwismitters and receivers placed in producing wellbores. The effectiveness of such techniques are reduced if the weUbores am not optimally placed in lo the field. Such techniques would benefit ftm wellbores which are planned based on impmved seismographs.

In the control of producing reservoirs it would be useful to have information about the condition ofthe reservoir away from the borehole. Crosswell techniques are ardilable, to give this Idnd of information. In seismic tomography, a series of 3-D irna ofthe reservoir is developed to give a 4-D model or the reservoir. Such data has usually been obtained using wireline methods in which seismic sensors are lowered into a borehole devoted solely for monitoring purposes. To use mich data on a large scale would require a large number of wells devoted solely to monitoring purposes. Furthemore, seismic data acquired in different wireline runs commonly saffers from a data mismatch problem whex-P, due to differences in the coupling of the sensors to the formation, data do not match.

The present invention addresses the above-noted problems and provides a method of conducting subsurface seismic surveys from one or more wellbores. These wellbores 3 may be drilled f or the purpose of conducting such surveys. Alternatively, permanently implanted sensors in a borehole that could even be a production well could be used to gather such data. The data f rom such subsurface surveys is utilized to improve the previously available seismographs. The improved seismographs are then utilized to plan the production wellbores. Borehole seismic imaging and cross-well tomography can be utilized to further improve the seismographs f or reservoir management and control.

SUMARY OF THE INVENTION

According to the present invention, there is provided a method of obtaining geophysical information about subsurface formations, comprising:

(a) permanently deploying a plurality of fiber optic sensors in a survey wellbore, each said sensor having a fiber optic element detecting a seismic wave; (b) using said fiber optic sensors for detecting seismic waves travelling through the subsurface formations; and (c) processing the detected seismic waves to obtain geophysical information about the subsurf ace formation.

ARMDFSCRIMON- OFT RE AMWINGS Fordetaed- ofthe p invendon, re&re=es shot, be =ade to s the foRowing detaged desmiption ofthe 1, - risr A embodiinent, ub3 in coviunction with the g dravnqm in wbich Re elemmus have been loven hlw nimeraL% wherein FIG. I shows a schemati Mush-adon, ofthe pbwewgm:t. of a weMxwe and tra-mmillm- and receivers for conducting subsinf= sciumcavveys; 10 IqG. la shows a re=iver grid for use at -the sufface.

FIQ 2 shows a scheamfic Mustradon of the pb=u= of a pkwdlity of weM=w and =xes g transmitW gmd reedven for conducting suinacffice semiac Mvve; FIG. 3 sbows a.schemafic Mustraian uf =jldple production weMbum formed for proalcing]hyd&o=t.= the kfinmudm d3bined, fimm survv.79 patrzaed; FIG. 4 shows a sd=afic Musumfian of pro&wdan vieffiares &rmed for producing'. I utRizin the inlizzaafim obtained fim surveys perimmed according to the present irwenficr- wherem. at least ow of%e prnductim weHborcs is finmed frqm the weMore, fix7ned for pe&nnb subsurfi= seismi =vey.

FIG. 5 is a of an 2caughc SeIS13= MCW DLrTAUZD RX QRR3LOW T I-MRID nMQDRUNIM OF HE lAiweral, the present inventionpravides meffiods for dAgning in madels'porior to dn'11g production weftores, dalliAg vieflbores Wed at least partially on the unpmvcd seismic modd and miethod for improving reservw modeling by continued seismic survey during the F& of the production vieMortk is FIG. I sham a schematic Mustr4tim of an emmple afthe placement of a xwvcy weflbore and recertws and the source points for cm&lctm vAmf= sei=c surveys according to the present imvetition. Ior the purposesofiRustrwan and ea of understa:ndinst the niethods of the present invention are descn- bed by way of thus, swh ccamples shall not be constraed as limmmons. Further, the methods am -bed = referenee to drMing weWx= offibare but are equally appl=blk to &Mm (if Lv= weMcm fi-orn ousbm kxab=& In this a sum vieflhore 10 is planned based an any preadstimg infi=ztion abcon the submufa= fi=mcm structum Such i6brmation typically inchWes seisni arvep pufmaned at the surfla and may hx6ide kfirmation frr= welIbores previou4yhrmed in the same or umby fields Asan

6 example, FIG. 1 shows non-bydrocarbon bearing formations Ia and]b separated by hydrocarbon bearing formations Ha and Ub (aLso, ref=Ted to herein as the production zones" or."reservOile). Afka the wellpath fbr the survey wellbore 10 has been determined, it is drilled by any conventimW manner Typically, reservoirs are found several thousand feet deep from the earth's surfi= and in many instances oil and gas is U'apped in multiple zones separated by non-hydmcarbon b=ing zones. It is pref=ed that the hydrocarbon beamg formations be not invaded by drilling fluids and other drilling activity except as may be necessary to drill wellbores for recovering hydrocarbons from such formations. Therefore, it is generally preferTed tha the survey wellbore 10 be placed lo in a non-hydrocarban bearing formalion, such as formation Ia. Additionally, it is prderred that the survey wellbore be placed relatively dose to and along the reservoirs.

Typically, production wellbores are relatively large in diameter, generally grew than seven inches (7") in diameter Such large diameter wellbores are expensive to drill.

1,5 Survey wellbores, such as exemplary wellbore 10, however, need only be large enough to accomm acoustic receivers, such as hydrophones, fiber optic sensors, and an acoustic source moved within the weUbore as more My explained later. Such small diameter wellbares cab be drilled relatively irmpensively in non-producing- zones without concerning invading formations near the borehole. AdditionaDy, relatively inexpensive fluids may be utilized to, drill mch wellbore& As noted wxfier, reservoirs typically lie several thousand fl!et below the eartWs surface and thus the survey wellbore, such as wellbore 10, may be placed several thousand feet below the eartWs surflice. Additionally if the survey wellbore is not eventually going to be utilized for purposes that would require casing or otherwise completing the vmlbore, such wellbore may be filled with a heavy 7 fluid (caed the nkill-weiglit" fluid) to prevew collapse of the wellbore.

on= the survey wellbore 10 has been drilled, a receiver string or fine 12 with a plurality of serially spaced receivers IU is placed along the wellbore. The receiver locations 12a are preferably equi-spaced and each receiver location 12a. may include one or more receivers, such as hydrophones, meters or accelerometers. The receivers could also be single or a phwality of fiber optic strings or segment, each such segment containin a plurality of spaced apart fiber optic sensors: in such a case, a light source and detector (not shown) are disposed used in the wellbore to transmit light energy to the lo sensors and receiver the reflected light energy from the sensors and a suitably placed data acquisition and pmcessing unit is used for processing the fight signals. The use of such receiver lines is known in the art and is not described in detail herein. Akernatively or in addition to the receiver string 12, one or more receiver lines, such as lines 14, each having a plurality of serially spaced acoustic sensors 14a may be placed on the ocean bottom 16 for relatively shallow water applications. For relatively deep water applications, one or more receiver lines may be placed a relatively short distance below the water sinface 22. Receiver lines 22 are made buoy= so that they remain at a desired distance below the water surface'. FIG. la shows a plan view of an exempWy configuration of a plurality of receiver lines RI-Rn that may be placed on the earth!s stirfi=. The receivers in each line designated by q, where.i represents the fine and j represema the mquential position in Ihe line L The receivers in 4acent fines are shown staggered one half the distance between adjacent receivers.

8 The same fiber-optic sensor could be -used as an acoustic sensor and to deternfine other downhole conditions, such as the temperattire, pressure and fluid flow. The use of fiber optic s=sors in downhole tools is fidly described in Provisional Application Saw No. 60/045,3 54, incorporated herein by reference.

Referring back to FTG. 1, to perforni a seismic survey from the auvey wellbore 10, a seismic source (acoustic transmitter) is energized at a first location, such as location Mi. The acoustic signals travel around the survey weffbore 10 and am reflected and reftacted by the bed boundaries between the various formations The reflected waves, lo such as waves 30 are detected by the receivers 12s in the survey wellbore, 12. The detected signals are transmitted to a sinface control unit 70, which processes the detected signal according to known seismic processing methods. Desired infomiation relating to the survey activity is displayed on the display and any desired information is recorded by the recorder. The control unit preferably includes a computer with a seismic dam procw4ng programs for pmbrming processing receiver data and fbr controlling the operation of the source 15.

The -gource 15 is then moved to the next location in the wellbore 10 and the above process is repeated. When receiver lim, such as lines 14 are deployed on the sea bottom by tim 16, then the -signals 32 reflected from the submah formations are detected receivers 14a. The signals detected by the sensors 14a are then collected and processed by the control unit 70 in the manner described emiier. When receiver lim 18 are suspended in. the ocean water 20 then reflected signals as shown by lines 34 are detected by the receivers I ft in lines 18. The signals received by the lines 18 are then processed by the 9 control unit 70 in the manner described eadier. It should be noted that for the purpose of this embodiment of the invention any combination of the receiver lines may be utilized, Additionally, the source may be activated at surf= locations.

In the fim embodiment of the invention, the source 15 is preferably conveyed into the survey wellbores 10 and moved to each of the source points 15sj. This allows utilizing only one source for performing the survey. The source 15 preferably is adapted to transmit acoustic signals at any fiequency witWn a range of frequencies. The control unit is used to alter the amplitude and frequency of the acoustic signals transmitted by the lo source 15. Since the survey wellbore is strategically placed from relzovely short distance from some or all of the producing formauons, a relatively high frequency signals may be utilized to obtain high resolution seismic maps for short distances, which is nor feasible from any c surveys performed from the surface. Additionally, the source 15 may be oriented in any direction to transmit acoustic signals in a particular direction (herein refaTed to as the- focused signals). This can allow obtaining true three dimensional bed boundary information respecting formations surrounding the survey wellbore 10. During drMing of the wellbore, core mittings from known depths provide information about the rock structure, which in turn can be used to determine relatively accurately the acoustic velocities of some of the formations surrounding the survey wellbore 10. These velocities are utilized 'in processing the signals detected by the receiver lines, such as lines, such as line 12, 14 and IS. This provides more accurate delineation of bed boundaries compared to. surface seismic surveys which typically use estimated values of acoustic velocities for subsurface fbrmations.

The information obtained from the survey as described above is used to update pre==g seisrmc models. This may be done by combining the data obtained from the survey puformed from the survey weWbore 10 or by any other known method.

Additionally acialat acoustic velocities of the subsur:face formations obtained herein can be ufiBzed to update the seismic models of the are& Now referring to FIG la, the source line defined by st -s. is shown to be symmetrically placed in relation to the surface seismic lines Rt -R... It is preferred to io utilize sy=etrical receiver and trwL9mitter configumfions because it simplifies processmg, of data.

FIG. 2 shows a schematic Mustration of the placement of a plurality of wellbores and corresponding transmitter and receiver lines for conducting subsur&ce, setsmic survey is according to one method of one embodiment of the invention. In this configuration, a stirvey weUbore 100 is formed along a welipath based on the prior seismic and other subsurface formation information available. The wellbore, 100 has a first branch wellbore 100a placed above the first reservoir Ha and a second branch w6flbore 100b placed above and along a second reservoir 11b. Other configurations for multiple survey weMores may -to be adopted based upon the location of reservoirs to be developed. Fo!. - ocample, separate wellbores may be drilled from dff&rent mxface locations. A survey weUbore may be drilled along a dip to more precisely map the dipping formation utilizing relatinn6y high frequency acoustic signals.

11 Fm:h of the survey wellbores, such as wellbores 100a and 100b are lined with a receiver fine 102 and 104 respectively. To conduct seismic survey fi-om wellbore 100a, a transmitter is activated from each of the source points s. The reflected signals 106 are detected by the receivers r in the line 102, receivers in any other survey wellbore and by any other receivers pLwed on the surface. The data fmm the receivers is then processed by the control unit in the manner described -earlier with respect to FIG. I to obtain infonnation about the subsurface formations. Seismic data may be obtained at different fi- equencies and by utilizing focused signals in the mamer described earlier with respect to i o FIG. 1.

FIG. 3 shows a schematic illustration of multiple production wellbores formed fi3r producing hydrocarbons utilizing the information obtamed from surveys performed according to one embodiment of the invention. Once the subsurfa= geological 1.5 information- bas been updated, the size and the placement Df production wellbores, such as wellbores 100, 100a and 100b for developing a region am determined based upon the updated seismographs or subsurface models. The desired production wellbores are drilled and completed to produce hydrocarbons. It is desirable to place a plurality of receivers, such as receivers 202 in wellbore 200a and receivers 206 in wellbore 200b. In some cases it may be desirable to Imme the receiver line 12 in the. survey wellbore, 10. During the fife of the wellbores 200a and 200b, acoustic sources may be activated at selective locations in any of the production wellbores and in the survey wellbore 10. The receivers in the vanous wellbores detect signals corresponding to the transmitted signals. The detected signals are then processed to determine the condition of the various reservoirs over time.

12 This information is then used to update reservoir models. The updated reservoir models are subsequently utilized to manage production from the various wellbores in the field,

The updated models may be used to selectively alter production rates from any of the production wellbores in the field, to sbiA in a particulu well, to workover a particular production weRbore, etc. The permanent availability of receiver lines in the surM welIbore 10, rehitively close to the production wellbores. 200a and 200b, provides more accurate information about the subsurface formations than surveys conducted fi-cm the surface. However, surface setsmic survey% if performed after the wellbores have been producing, may still be updated with information obtained from surveys performed u lo survey weUbore 16.

FIG. 4 shows a schematic illusti-ation of multiple production wellbores fbrmed for produchig hydrocarbons utilmng the information obtained from surveys performed according to one embodirnent of the invention, wherein at least one of the production is wellbores is formed from the wellbore formed for performing subsurface seismic survey.

In some cases it may be desirable to drill a survey wellbore which can later be utilized to form production branch wellbores therefrom. MG. 4 shows the formation of a survey weUbore 300a from a common vertical well section 300. The weUbore 300 is first used to perform seismic surveys in the mann described herein and then one or more production wellores, such as wellbores 300b and 300c,;tre formed from the survey wellbore 3005L Additional production wellbores such as welIbore 310 may be formed from the common wellbore section 300 or fimm other surface locations (not shown) as desired. Receivers 302a and 312a respectively shown in the wellbores 300a and 310 perform the same fimctions as explained earlier with respect to FIGS. 1-3.

Another aspect of the invention is the use of permanently installed downhole acoustic sensors. FIG. 5 depicts a schematic representation of the acoustic seismic monitoring system as described immediately above. FIG. 5 more particularly depicts a production well 410 for producing oil, gas or the like. Well 410 is defined by well casing 412 which is cemented or otherwise permanently positioned in earth 414 usin an appropriate cement 416. Well 410 has been completed in a known manner production tubing with an upper section of production tubing being shown at 416A and a lower section of production tubing being shown at 410. Attached between production lo tubing 416A and 416B, at an appropriate location, is the permanent acoustic sensor in accordance with the present invention which is shown generally at 41& Acoustic seismic sensor 4111 comprises a housing 420 having a primary flow passageway 422 which commun;cates with and is generally in alignment with production tubing 416A and 416B.

Housing 420 also includes a side passageway 424 which is laterally displaced from primary 1.5 flow passageway 422. Side passageway 424 is defined by a laterally wending section 426 of housing 420 and an interior dividing wall 42& Positioned within side passageway 424 is a downhole electronics and control module 430 which is connected in series to a plurality of permanent acoustic receivers 432 (e.g., hydrophones, seismometers and accelerometers). The acoustic receivers 432 are placed longiWdinay along production Vibing 416 (and therefore longitudinally along thL wall of the borehole) in a region of the geological formation which is of interest in terms of sensing and recording seismic changes with respect to time. At the surface 434 is a surface control system 436 which controls an acoustic transmitter 438. As discussed, twisiniaw 438 may also be located beneaih the surface 434. Transmitter 438 wifiperiodically 14 transmit acoustic signals into the geological formation which are then sensed by the array of acoustic receivers 432 with the resultant sensed data being processed using known analysis tpdiniques- A more complete description ofwellbores containing permanent downhole formation evaluation sensors can be found in US. PaL Nos. 5,662,165 all of the contents ofwhich are mcorporated herein by reference.

As discussed in trade journals such as in the articles entitled 4D Seismic Helps Track DTainage, Pnmure Comp ibfintion, Oil and Gas JournaL Mar. 27,1995, pp 55-sa, and "method Described for Using 4D Seismic to Track Reservoir Fluid Movement, " Oil and Gas Journal, Apr. 3, 1995, pp. 7044 (both articles being fWly incorporated herein by reference), seismic monitoring of wells over time is becoming an important tool in analyzing and predicting well production and performance. Prior to the present invention, such i6smic monitoring could only be done in near real time using known wire-Ime techniques; or on sensors mounted on the outside of tubing of various sorts for shallow applications (nem in producing wells). E=mples of mch seismic monitoring an described in US. Pat. No. 5,194,5,90; the article "Time-lapse crosswell seismic tomograin Interpretation. Implications for heavy oil reservoir - n, thermal recovery process monitoring and tomographic imaging technology" Geophysics v 60, No. 3, (May-June), p 631-650; and the article "Crosswell seismic radial survey tomograms and the 3-D pretation of a heavy oil geamflood." Geophysics v. 60, no. 3, (May-June) p 651-659 all of the contents of which are incorporated herein by reference. However, in accordance with the present invention, a Ognificaut advance in seismic monitoring is accomplished by installin the seismic (eg., acoustic) sensors as a permanent downhole installation in a weEL A plurility of seismic transmitters, as described in US. Patent 5,662,165 are used as sources of seismic energy at boreholes at known locations. The seismic waves detected at receivers in other boreholes, upon proper analyssis, provide a detailed thred-dimensional picture of a formation and fluids in the formation with respect to fim Thus, in accordance with this invention, a well operator has a continuous real time three dimensional image of dw borehole and surrounding formation and is able to compare lo that real time image with prior irnages, to ascertain changes in the formation; and as discussed in detail above, this constant monitoring can be done from a remote location.

Such an imaging of fluid conditions is used to control production operations in the reservoir. For example, an image of the gas-water contact in a producing gas reservoir 1.5 makes it possible to take remedial action before water is produced in a well by selectively closing sleeves, packers, safety valves, plugs and any other fluid control device downhole where it is feared that water might be produced without remedial action. In a steam-flood or C02flood operation for secondary recovery of hydrocarbons, steam or C02are injected into the reservoir at selected injection wells. The stem or C02drive the oil in the pare spaces of the n-,servoir towards the producing wells. In seconemy recovery operations, it is critical that the stem or C% not enter the producing wells: if a direct flow path for steam or C02 is established between the injection well and the recovery well (called a breakthrough), finther "flushinle operations to recover oil we ineffective. Monitoring of the position of the steam/oil or CWoiI, interfa is therefore important and by clo 16 sleeves, packers, safty valves, plugs and any other fluid control device in a producizig well wtiere breakthrough is imminent the flow- patterns can be altered stifficiently to avoid a breakthrough. In addition, sleeves and fkAd pressure control devices, can be operated in the injection wells to affect the overall flow of fluids in the reservoir. 1"he downhole s seismic data for performing the tomographic analysis is t -a U-2 uphole wsing metho ds described in U.S. Pat 5,662,165, gathered by the control center and transmitted to a remote site where a powafW digital computer is used to perform the tornographic analysis in accordance with methods described in the pa and references above.

Another aspect of the invention is the ability to control a fracturing operation. In a "frac joV, fluid at a high pressure is injected into a geologic formation that lacks adequate permeability for the flaw of hydrocarbons. The injection of high pressure fluid into a formation at a well has the effect of fracturing the formation. These fi-dettres generally propagate away from the well in directions determined by the properties of the rock and the underground stress conditions. As discussed by PS. Wills et al in an article entitled -Active and Passive Imaging of Hydraulic fractures7 Geophysics. the Leading Edge of Exploradon, July, p 15-22, (incorporated herein by reference), the use of downhole geophones; in one well (a monitor weU) makes it possible to monitor the propagation of fi-Acun-es. from another well in which fi2caning is being mduced. The propagating fi=ture in the formatiov.acts as a series of small seismic sources that emit seismir, waves. These waves can be recorded in thesensors in the monitor well and based upon the recorded signals in a in er of monitor wells, the active edge of the fiacture can be mapped. Having such real-time observations nukes it possible to control the fiacturing operation itself using the methods ofthis invention..

17 VAffle, the foregoing disclosure is directed to the pre&n-ed embodiments of the invention various modifications will be app to those skilled in the art. It is intended that an variations within the scope and spirit of the appended danns bC- CInbraced by the foregoing disclosure. Examples of the more important features ofthe invention have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contnibutions to the art may be appredatecL 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.

18

Claims

1. A method of obtaining geophysical information about subsurface formations, comprising:

(a) permanently deploying a plurality of f iber optic sensors in a survey wellbore, each said sensor having a f iber optic element detecting a seismic wave; (b) using said f iber optic sensors f cL.r detecting seismic waves travelling through the subsurface formations; and (c) processing the detected seismic waves to obtain geophysical information about the subsurface formation.

2. The method of claim 1 wherein the processing is performed at the surf ace or downhole.

3. The method of claim I further comprising deploying a source of light downhole, said source providing light energy to the f iber optic sensors.

4. The method of claim 1 wherein the fiber optic sensors are distributed along the wellbore.

S. The method of claim 1, wherein the survey wellbore is f ormed so as to not intersect a hydrocarbon bearing formation.

6. The method of claim 1 further comprising combining the obtained geophysical information about the subsurface formations with other data to obtain enhanced geophysical information about the earth's subsurface formations.

7. The method of claim I further comprising forming a production wellbore in the earth formation utilizing the obt-ained geophysical information.

a. The method of claim 6, wherein the enhanced geophysical information is one of a seismograph of the earth's subsurface formations (ii) an acoustic velocity of a subsurface 0 formation, (iii) distance between the survey wellbore and a bed boundary, and (iv) distance between at least two subsurface bed boundaries.

9. The method of claim 8, wherein the seismograph is a 4-D map of the subsurface formations.

10. The method of claim 1, wherein the seismic waves are generated by a source placed at a location that is one of (i) within the sur-vey wellbore, (ii) at the surface, (iii) an offshore location, and (iv) a secondary wellbore.

is Ii. The method of claim 1 further comprising:

(i) placing a second plurality of spaced seismic receivers outside the survey wellbore; (ii) detecting said seismic waves in the second plurality of receivers and generating signals responsive to such detected seismic waves; and (iii) combining the signals from the first and second pluralities of receivers to obtain the geophysical information.

12. The method of claim 11 wherein said second plurality of spaced seismic receivers comprises fiber optic sensors.

13. The method of claim 1 further comprising:

(i) subsequently conducting seismic surveys to obtain secondary information about the subsurface formation, and (ii) combining the obtained geophysical information and the secondary geophysical information to obtain an enhanced map of the subsurface formation.

14. The method of claim 1 further comprising producing a cross-well seismograph from the detected seismic waves.

15. The method of claim 1 wherein said survey wellbore f ollows a predetermined wellpath as a sidebore from a production wellbore.

16. A method of obtaining geophysical information about subsurface formations, comprising:

(a) deploying.a plurality of fiber optic sensors in a first survey wellbore, each said sensor having a fiber optic element for detecting a seismic wave; (b) generating seismic waves in the subsurface using at lest one transmitter in a second survey wellbore and using said fiber optic sensors for detecting said generated seismic waves travelling through the subsurface formations; and (c) processing the detected seismic waves to obtain geophysical information about the subsurface formation.

17. The method of claim 16 wherein the processing is performed at the surface or downhole.

18. The method of claim 16 further comprising deploying a source of light downhole, said source providing light energy to the fiber optic sensors.

19. The method of claim 16 wherein the f iber optic sensors are distributed along the wellbore.

20. The method of claim 16, wherein the survey wellbore is f ormed so as to 'not intersect a hydrocarbor-i bearing formation.

21. The method of claim 16 further comprising combining the obtained geophysical information about the subsurface formations with other data to obtain enhanced geophysical information about the earth's subsurface formations.

22. The method of claim 16 further comprising forming a production wellbore in the earth formation utilizing the obtained geophysical information.

23. The method of claim 21, wherein the enhanced geophysical information is one of (i) a seismograph of the earth's subsurface formations, (ii) an acoustic velocity of a subsurface.

formation, (iii) distance between the survey wellbore and a bed boundary; and (iv) distance between at least two subsurface bed boundaries.

is 24. The method of claim 23, wherein the seismograph is a 4-D map of the subsurface formations.

2S. The method of claim 16 further comprising:

(i) using a second plurality of spaced seismic receivers outside the f irst survey wellbore for detecting said seismic waves reflected by earth's formations and generating signals responsive to such detected seismic waves; and (ii) combining the signals from the fiber optic sensors and the seismic receivers to obtain the geophysical information.

26. The method of claim 25 wherein said second plurality of spaced seismic receivers comprises fiber optic sensors.

27. The method of claim 16 further comprising:

(i) subsequent '.',.y conducting seismic surveys to obtain secondary information about the subsurface formation, and (ii) combining the obtained geophysical information and the secondary geophysical information to obtain an enhanced map of the subsurface formations.

28. The method of claim 16 further comprising producing a cross-well seismograph from the detected seismic waves.

29. The method of claim 16 wherein at least one of said first and second survey wellbores follows a predetermined wellpath as a sidebore from a production wellbore.