GB2354822A

GB2354822A - Obtaining improved geophysical information about earth formations

Info

Publication number: GB2354822A
Application number: GB0031129A
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: 2001-04-04
Anticipated expiration: 2017-10-09
Also published as: AU730715B2; NO335379B1; AU4902297A; GB2334104A; CA2268104A1; CA2268104C; GB2354822B; NO991667D0; GB9908166D0; GB2354583B; GB0031132D0; GB0031129D0; NO991667L; GB2354583A; WO1998015850A1; GB2334104B

Abstract

The method comprises injecting a fluid in an injection wellbore spaced apart from the production wellbore to make a fluid/hydrocarbon interface in the formation, permanently installing a plurality of seismic sensors in a survey wellbore, transmitting seismic signals into the formation from a plurality of source locations, detecting said seismic signals by the seismic sensors in the survey wellbore, determining a parameter of interest relating to the fluid/hydrocarbon interface from the detected seismic signals, and operating a downhole tool at at least one location selected from (i) the production wellbore, and, (ii) the injection well, in response to the determined parameter of interest to control the flow of hydrocarbons into the production wellbore.

Description

2354822 T=: N=OD OF OBTAWMG UIMOVM GWPHYSICAL RWORMTION "OUT F.ARTH

FORAUTIONS

Field of the Invention

This invention relates gene=Uy to the placement of wellbores and management of the corresponding reservoirs and more particulady to selectively drilling one or mom weftores for condacting seismic surveys therefrom to improve the seismographs and utilizing the improved to determine the type and course of wellbores, for developing a field. The method of the present invention further relates to obtammg seismic information during drilling of the weMores and during production of hydrocarbons for improving hydrocarbon production from the reservoirs. The method of the present invention fixrther relates to using the derived semmic information for automatically controlling petroleum production wells using downhole computaized control system.

Backemund of the Invention Seismic surveys are perfbrmed from surfice locations to obtain maps of the structure of subsurface ffirmations. The. se surveys are in the form of maps (refem!d herein as seismographs") depicting cross-section of the earth below the- surveyed region or area Three dimensional (73D') surveys have become cornmon over the last decade and provide sicantly better irrfiarmation of the subsurface formations compared to the previously available two-dimension C'2D) surveys. The 3D surveys have significantly reduced therurrn er of dry wellbores. StW,'sinm such seismic mirveys are performed from the surfice, they lose resohition due to the dist between the surfi= and the desired hydrocarbonbearing formations, dips in and arotind the subsurface formations, bed boundary 2!5 delineations, which, is typically several thousand feet.

Surface seismic surveys utilize relatively low fi-equency acoustic signals to perform such surveys because such signals penetrate to greater depths. However. low frequency ",Rnall pDvide lower resolution, which provides low resolution seismographs., I-ligh frequency signals provide, relatively high resolution boundary delineations, but attenuate relatively quicidy and are, thus, not used for perfbrming seismic surveys from the nrf=.

Only rarely would an oil company drill a wellbore without fa-st studying the seismographs for the area. The number of wellbores, and the path of each wellbore is lo typically planned based an the seismographs of the area Due to the relatively low resolution of such i mograp wellbores are frequently not drilled along the most effective weapaths. it is therefore desirable to obtain improved seismographs phor to drilling production weIlbores. Additionally, more and more complex wellbores are now being drilled, the placement of which can be improved with high definition i Furthermor e, relafively recently, it has been proposed to drill wel1bores along contoured paths through and/or around subsurface formations to increase potential recovery or to improve production rates of hydrocarbons. In such cases, itis even more critical to have smsmographs Ihat relatively accurately depict the delineation of subsurface formations.

C onventionally, seismographs have been updated by (a) performing borehole imaging, which is typically conducted while drilrmg a wellbore and (b) by cross-well tomography, which is conducted while between a miniber of producing wells in a region.

In the case of borehole g, a seismic source.seismic source generates acoustic signals during drilling of the wellbore. A number of receivers piaced on the sui- face receive 2 acoustic reflections from subsurface formation boundaries, which signal are processed to obtain more accurate bed boundary inforn=on about the borehole. This technique helps improve, the surface seismographs in piecemeal basis. Data from each such well b drilled is ufilized to continually update the scismo However, such wellbores are neither planned nor optimally placed fbr the purpose of conducting subsurface seismic surveys. Their wellpaths and si7= are determined based upon potential recovery of hydrocarbons. In the case of cross-weU tomography, acoustic signals are transmitted between vanous trarismitters and recervers placed in producing wellbores. The effectiveness of such techniques are reduced if the wellbores are not optimally placed in the field. Such techniques would bene& from wellbores which are planned based on irnproved seismographs.

In the control of producing reservoirs, it would be useful to have information about the. condition of the reservoir away from the borehole. Crosswell techniques are available is togive this Idnd of information. In seismic tomography, a series of 3- D images of the reservoir is developed to give a 4-D model or the reserv&. Such data has usually been obtained using wirehe methods in which seismic sensors are lowered into a borehole devoted solely for monitoring: purposes. To use such data on a large scale would require a large number of wells devoted solely to monitoring purposes. Furthermore, seismic data acquirer in different wireline runs commonly suffers from a data mismatch problem wtere, due to differences in the coupling of the sensors to the formation, data do not match The present invention addresses the above-ricyted problems and provides a method of conducting subsurface seismic surveys from one or more welIbores. These wellbores 3 N be drMed for the purpose of conducting mxh smrveys. Afternafively, permaneWy impimsed in a borehole Vbzt could.even be a producticni well could be used to pth mxh data. The data from such subsurface surveys is xxtilized to =wove the previously available The improved arethenixtilizedtoplan.

the production wellbores. Borehole 17nagi andwoss-well-Im-graphycanbe uffi7m to fiirther the seismogmphs for reservoir management and control, MW4ARY OF 3M ---- N According to the present, invention, there is provided a method of recovering hydrocarbons f rom a production wellbore producing hydrocarbons f rom. a formation comprising:

(a) injecting a fluid in an injection wellbore spaced apart from the production wellbore to make a fluid /hydrocarbon interface in the formation; (b) permanently installing a plurality of seismic is sensors in a survey wellbore; (c) transmitting seismic signals into the formation from a plurality of source locations; (d) detecting said seismic signals by the seismic sensors in the survey wellbore; 4 (e) determining a parameter of interest relating to the fluid/hydrocarbon interface from the detected seismic- signals; and (f) operating a downhole tool at at least one location selected from (i) the production wellbore, and, (ii) the injection well, in response to the determined parameter of interest to control the flow of hydrocarbons into the production wellbore.

I BRMF DESCRON OF THE DRAWINGS For detailed unders=ffing of the present invenfion, references should be made to the following detailed description of the prefaTed embodiment taken in conjunction with the accompanying drawings, in which like elements have been given hike numerals, wherein:

FIG. I shows a schematic Mush-ation of the placement of a wefto're and io corresponding transmitters and receivers for conducting subsurfice seismic surveys FIG. la shows a receiver grid for use at the suiface FIG. 2 shows a schematic illustration of the placement of a plurality of weM)ores and corresponding Uwsmitter and receivers for conducting subsurface seismic survey 2 0 FIG. 3 shows v. I schematic Must-ation of multiple production weMores formed for producing hydrocarbons uti'lizing the information obtained from surm7s performed according to the present invenfion.

FIG. 4 shows a schematic Mustration of multiple producdon wellbores formed for 6 producing hydrocarbons utilizmg the 1 6 nation obtained from surveys perfinm2ed according to the present invention, wherem at least one of the production wellbores is formed from the weIlbore formed for performing subsurface scismic survey.

FIG. 5 is. a lagrarnma c view of an acoustic seismic monitoring system in accordance with the present invention.

DETAU-ZD DESCRIMON OF THE PREP IMED EMODIMICNIS In general, the present invention pmvides methods for obtaining improved models'prior to drilling production wellbores, drilling weUbores based at least partially on the improved seismic models and method for improving reservoir modelmg by contimied seismic survey during the life of the production wellboret.

FIG. 1 shows a schematic illustration of an example ofthe placement of a sui-vey wellbore and receivers and the source points for conducting subsurface seismic surveys according to the present invention. 'For the purposes of illustration and ease of the methods of the present invention are described by way of examples and, thus, such examples shall not be consbmed, as limitations. Further, the methods are described in re&rence td. drilling weRbores offshore but are equally applicable to drilling of wellbores from onshore locations. In this configuration, a survey weUbore 10 is plamied based on any premisting information about the submirfitce fbrmatLon structure. Such information typically includes seismic surveys performed at the surfitce and may include information from wellbores previously formed in. the same or nearby fields. As an

7 example, FIG. I shows non-hydrocarbon bearing formations Ja and Ib separated by hydrocarbon bearing formations Ha and.111b (also referred to' herein as the "Production zones" or."reservoirs'). After the wellpath for the survey wellbore 10 has been Aetermined, it is drilled by any conventional marmer. Typically, reservoks are found several thousand feet deep from the cartWs surface and in many instances oil and gas Ls trapped in multiple zones separated by non-hydrocarbon bearing zones. It is preferred tha the hydrocarbon bearing formations be riot invaded by drilling fluids andother drilling activity except as may be necessary to drill wellbores for recovering hydrocarbons from such formations. Therefore, it is generally preferred that the survey wellbore 10 be placed io in a non-hydrocarbon bearing formation, such as formation LL Additionally, it is preferred that the survey wellbore be placed relatively close to and along the reservoirs.

Typically, production wellbores are relatively large in diameter, genera[ly greater 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 accommodate acoustic receivers, such as hydrophones, fiber optic season, and an acoustic source moved within the wellbore as more fully explained later. Such sman diameter wellbores can be drilled relatively inexpensively in non-producing- zones without concerning invading formations near the borehole. Additionally, relatively inexpensive fluids may be utilized to. drill such wellbom. As noted earlier, reservoirs typically He several thousand feet below the eartWs surface and thus the survey wellbore, such as wellbore 10, may be placed several thousand feet below the earth!s surface. Additionally, if the survey we:11bore is not eventually going to be utilized for purposes that would require casing or otherwise completing the wellbore, such wellbore may be filled with a heavy fluid (called the Okill-weight" fitfid) to prevent collapse of the wellbore.

Once the surM wellbore 10 has been drilled, a receiver string or fine 12 with a phirafity of serially spaced receivers IU is placed along the weUbore. The receiver 5' locations IU are preferably equi-spaced and each receiver location 12a. may include one or more receivers, such as hydrophones, seismometers or accelerometers. The receivers could also be single or a phz&ty of fiber optic strings or segment each such segment epnl:%ining 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 ligbt energy to the lo sensors and receiver the reftected light enerU from the sensors and a suitably placed data acquisition and processing unit is used for processing the figbt signals. The use of such receiver lines is known in the art and is not described in detail herein.'Altanadvely 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 1 for relatively shallow water apphcations. For relatively deep vrdw applications, one or more receiver fines may be placed a relatively short distance below the water surf= 22. Receiver lines 22 are made buoyant so that they remain at a: desired distance below the water muface. FIG. la shows a plan view of an ecernp1my configuration of a plurality of receiver lines Ri-Rn that may! be placed on the eartlYs, surface. The receivers in each line designated by r,,j, where i represents the line and j represents the sequential positida in the line L The receivers in adjacerd lines are shown staggered one half the distance between adjacent receivers.

9 The same fiber-optic sensor could be used as an acoustic sensor and to det=me other downhole conditions such as the temperature, pressure and fluid flow. The use of fiber optic sensors in downhole tools is fully described in Provisional Application Saw No. 60/045,354, incorporated herein by reference.

Referring back to FIG. 1, to perforni a seismic survey from the survey wellbore 10, a seismic source (acoustic transmitter) is energized at a first location, such as location Mi. The acoustic sioal travel around the survey wellbore 10 and are reflected and reffacted by the bed boundaries between the various formations. The reflected waves, lo such as waves 30 am detected by the receivers 12s in the survey wellbore 12. The detected signals we transmitted to a surface control unit 70, which processes the detected signals according to known seismic processing methods. Desired information 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 data processing programs for performing processing receiver data and for controlling the operation of the source 15.

The -source 15 is then moved to the next location in the wellbore 10 and the above process is repeated. When receiver lines, such as lines 14 am deployed on the sea bottom 16, then the signals 32 reflected frLm the subsurface formatiows, are detected by the receivers 14a. The signals detected by the sensors 14a are then collected and processed by the control unit 70 in the manner described earlier. When receiver lines -18 are suspended in the ocean water 20 then reflected signals as shown by lines 34 are detected by the receivers 18a in lines 18. The signals received by the lines 13 are then processed by the control unit 70 in the mann described earlim It should be noted that fbr the purpose of this embodiment of the invention any combination of the receiver lines may be utilized. Additionally, the source may be activated at anface locations.

In the first embodiment of the invention, the source 15 is preferably conveyed into the survey wellbores 10 and moved to each of the source points 15si. This allows utilizing only one source for performing the survey. The source 15 preferably is adapted to transmit acoustic signals at any fivquency witlim. a range of frequencies. The control unit 70 is used to alter the amplitude and fi-equency of the acoustic signals ftwumitted by the source 15. Since the survey wellbore is strategically placed from relatively short distance from some or all of the producing formations, a relatively high fi-equency signals may be uffized to obtain high resolution seismic maps fbr short distances, which is nor feasible from any seismic surveys performed from the surf=. Additionally, the source 15 may be oriented in any direction to transmit acoustic signals in a particular direction (herein referred to as the- focused signals). This can allow obtaining true three dimensional bed boundary information respec ting formations surrounding the survey wellbore 10. During drilling of the wellbore, core cuttings from Imown depths provide information about the rack structure, which in turn clan 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 18. This provides more accurate delineation of bed boundaries compared to. surface seismic surveys which typically use esfumated values of acoustic velocities for submnface fbrmations.

The information obtained from the survey as described above is used to update preexisting sessmic models. This may be done by combining the data obtained from the survey performed from the survey weUbore 10 or by any other known method.

Additionally actual acoustic velocities of the subsurflice formations obtamed herein am be utilized to update the seismic models of the area.

Now referring to MG la, the source fine defined by si -sp is shown to be symznetrically placed in relation to the surface seismic lines R, -R., It is preferred to JWH7 syminetrical recxiver and trazismitter configurations because it simplifies processing of data.

FIG. 2 shows a schematic illustration of the placement of a plurality of wellbores and corresponding transmitter and receiver lines for conducting subsurface seismic survey is according to one method of one embodiment of the invention. In this configuration, a survey wellbore 100 is formed along a wellpath 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 Ila and a second branch wellbore, 100b placed above and along a second reservoir Hb. Other configm-Ations for multiple survey wellbores may 2c be adopted based upon the location of reserwirs to be developed. For comple, separate wellbores may be drilled from Merent sur6xce locations. A sinvey wellbore may be drilled along a dip to more precisely map the dipping formation utilizing relatively high frequency acoustic signals- 12 Each of the survey weUbores, such as wegbores 100& and 100b are lined with a receiver line 102 and 104 respectively. To conduct seismic survey from wellbore, 100a, a transmitter is activated fi-orn. each of the source points s. The reflected signals lo6 are s detected by the receivers r in the line 102, receivers in any other survey wellbore and by any other receivers placed on the surface. The data fmm, the receraws is then processed by the control unit in the man= described -earlier with respect to MG. I to obtain information about the subsurfice formations. Seisnuc data may be obtained at dfferent fi-equencies and by utilizing focused signals in the manner descrbed earlier with respect to lo FIG. 1.

FIG. 3 shows a schematic illustration of nwItiple production wellbores formed for producing hydrocarbons WAizing the information obtained from surveys performed according to one embodiment of the invention. Once the subsurface geological informatio n has been updated, the size and the placement of production wellbores, such as wellbores 100, 100a and 100b for developing a region are, determined based upon the updated seismographs or subsurface models. The desired production wellbores are driHed and completed to produce hydrocarbons. It is desirable to place a phu-Aty of receivers, such as receivers 202 in wellbore 200a and receivers 206 in weDbore 200b. In some cam ft may be desirable to leave the receiver fine 12 In the survey weflbore 10. During the life of the wellbores 200& and 200b, acoustic sources may be activated at selective locations in any of the production wellbords and in the survey wellbore 10. The receivers in the various well1mres detect signals corresponding to the trmed signals. The detected signals are then processed to determine the condition of the various reservoirs over time.

13 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 from any of the' production wellbores in the field, to shut in a particular well, to warkover a particular s production wellbore, etc. The permanent availability of receiver lines in the survey wellbore 10, relatively close to the production wellbores. 200a and 200b, provides more accurate information about the subsurfime formations than surveys conducted from the surflace. However, surface scismic surveys, if performed after the wellbores have been producing, may still be updated with information obtained from surveys. performed lo survey wellbore 10.

MG. 4 shows a s6ematic illustration of multiple production wellbores formed for producing hydrocarbons utilizing the information obtained from surveys perfbrmed according to one embodiment of the invention, wherein at least one of the production 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 ptoduction branch wellbores therefrom FIG. 4 shows the formation of a survey wellbore 300a from a common vertical well section 300. The wellbore 300 is first used to perform scismic surveys in the manner described herein. and then one or more production wdbores, such as wellbores,300b and 300c, are formed from the survey we- lbore: 300a.

Additional production wellbores, such as wellbore 310 may be formed from the common wellbore section 300 or from other surface locations (not shown) as desired. Receivers 302a and 312a, respectively shown in the weffbores 300a and 310 perform the same finictions, as explained earlier with respect to FIGS. 1-3.

14 Another aspect of the invention is the use of permanently installed downhole acoustic sensors. PIG. 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 pernmently positioned in earth 414 using an appropriate cement 416. Well 410 has been completed in a known manner using production tubing with an upper section of production tubing being shown at 416A and a lower section of production tubing being shown at 416B. Attached between production io ukmg 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 413 comprises a housing 420 having a primary flow passageway 422 which communicates 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 is flow passageway 422. Side passageway 424 is defined by a laterally extending section 426 of housing 420 and art interior dividing wall 423.

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, setw=meters and accelerometers). The acoustic receivers 432 are placed longitudinally along product= tubing 416 (and thereforc longitudinally - along the wall of the borehole) in a region of the geological formation which is of interest in terms of sensmg and mwrding semme changes with respect to time. At the surface 434 is a sad= control system 436 which controls an acoustic transmitter 43& As discussed, transmitter 438 may also be located beneaih the surface 434. Transmitter 438 w6periodically transmit acoustic signals into the geological formation which are then sensed by the array of acoustic recervers 432 vath the resultant sensed data being processed usmg known analysis techniques.

A more complete description ofwellbores containhig permanent downhole formation evaluation sensors can be found in U.S. Pat. Nos. 5,662,165 all of the contents of which are incorporated hemn by reference.

As discussed in trade journals such as in the articles entitled, 4D Seismic Helps Track Drainage, Pressure Comp on," Oil and Gas Journal, Mar. 27, 1995, pp 55-58, and -Method Described for Using 4D Seismic to Track. Reservoir Fluid Movement" OR and Gas Joumal, Apr. 3, 1995, pp. 70-74 (both articles being My 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 ieismic monitoring could only be done in near real time using known wa-e-line techniques; or on sensors mounted on the outside of tubing of various sorts for shallow applications (never in producing wells). Examples of such, seismic monitoring are 2a described im U.S. Pat No. 5,194,590; the article "7r=e-12pse% crosswell seismic tomogram Interpretation: Implications for heavy oil reservoir on, thermal recovery process monitoring and tomographic imaging technoloe Geophysics v. 60, No. 3, (May-June), p 631-650; and the article "Crosswell seismic radial survey tomograms and the 3-D interpretation of a heavy oil stgamflood." Geophysics v. 60, no. 3, (May-June) p 16 651-659 all of the contents ofwhich are incorporated herein by reference. However, in accordance vinth the present mvention, a significant advance m seismic monitonng is by installing the seismic (eg., acoustic) senmrs as a permanent downhole installation in a well- A phumlity of seismic transmitters, as descril)ed in U.S. Patent s 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 analysis, provide a detailed thred-dimensional picture of a fi=ation and fluids m. the formation with respect to time. TUis, in accordance with this invention, a well operator has a continuous red time three dimensional image of the borehole and m=unding fbrmation and is able to compare i o that real time hinage with prioir images to ascertain changes in the formation; and as discussed in detail above, this constant monitoring can be done fmm 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 makes it possible to take remedial action befbre water is produced in a well by selectively closing sleeves. packers, safi" 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 C02 flood operation for secondary recovery of hydmcarbons, stearn or CO are injected into the reservoir at selected injection well& The steam or C02 drive the oil in the pore spaces of tl;.e reservoir towards the pm Jucing wells. In secondary recovery operatiorq. it, is antical that the stem or C02 not enter the pmducing wells: if a direct flow path for steam or C02 is established between the injection well and the recovery well (called a breakthrough), further "flushingr operations to recover oil are ineffective. Monitoring of the position of the steam/off or C02/oil interfl= is therefbre important and by clo 17 sleeves, packets, safi valves, plugs and any other fluid control device in. a producing well -where breakffirough is imminent, the flow. patte= can be altered sufficiently to avoid a breakthrough. in addition, sleeves and fluid pressure control devices can be operated in the injection weUs to affect the ovexaff flow of Wds in the reservoir. The downhole seismic data for performing the tomographic analysis is transmitted uphole using methods descnbed in U.S. Patent 5,662,165, gathered by the control center and transmitted to a remote site where a powerfW digital computer is used to perform the tomographic amsis in accordance with methods described in the patent and references above.

Another aspect of the invention is the ability to control a fiwturing operation. In a -frac, job-, fluid at a high pressure is injected into a geologic formation that kcks adequate permeability for the flow ofhydrocarbons. The injection of high pressure fluid into a formation at a well has the effect offracturing the formation. These fi-=res genemuy propagate away from the well in directions determined by the properties ofthe ro& and 1.5 the underground stress conditions. As discussed by PJ3. Wills et al in an artide entitled -Active and passive Igingin of HydraLdiefrachires" Geophysics, the LeadngEdge of Eipioradon, July, p 15-22, (incorporated hexein by refi:rence), the use of downhole geophones in one well (a monitor weU) makes it possible, to monitor the propagation of ftactures from another well, in Which fi=turmg is being induced. The propagating f17=ire in the formation acts as a series of =4, seismic sources that emit semnaic waves. These waves can be recorded in the sensors in the monitor well and based upon the recorded signals in a number of monitor wells, the active edge of the fiwture can be mapped. Having such real-time observations makes it possible to control the firacturing operation itself using the methods of this invention..

While the fbregoing disclosure is directed to the preferred embodiments of the invention various modifications wiU be apparent to those skMed in the arL It is intended that all variations widun the scope and spirit of the appended claim be embraced by the foregoing disclosure. Fxamples of the more important features of the invention have been mmmiarized rather broadly in order that the detailed desenption thereof that follows may be better understood, and in order that the contutions to the art may be appreciated17here are, of course additional features of the invention that will be described hereinafter and which will form the subject ofthe claims appended hereto.

19

Claims

I A method of recovering hydrocarbons from a production wellbore producing hydrocarbons f rom a formation comprising:

(a) injecting a fluid in an injection wellbore spaced apart from the production wellbore to make a fluid/hydrocarbon interface in the formation; (b) permanently installing a plurality of seismic sensors in a survey wellbore; (c) transmitting seismic signals into the formation from a plurality of source locations; (d) detecting said seismic signals by the seismic is sensors in the survey wellbore; (e) determining a parameter of interest relating to the fluid/hydrocarbon interface from the detected seismic signals; and (f) operating a downhole tool at at least one location selected from (i) the production wellbore, and, (ii) the injection well, in response to the determined parameter of interest to control the flow of hydrocarbons into the production wellbore.
2. The method of claim I wherein the downhole tool is selected from the group consisting of flow control devices and formation isolation tools.
3. The method of claim 1 further comprising operating a downhole tool in the production well in response to the determined location of the f luid/hydro carbon interface to control flow of hydrocarbons from the production wellbore.
4. The method of claim, 3 wherein the downhole tool is selected from the group consisting of flow control devices and formation isolation tools.
5. The method of claim I wherein the survey wellbore is the production wellbore.
6. The method of claim I wherein the plurality of source locations includes at least one location in the injection wellbore. 10
7. The method of claim I wherein the fluid being injected is selected from the group consisting of steam, water and gas.
8. The method of claim 1 wherein the seismic sensor is selected from the group consisting of geophone, accelerometer, hydrophones, and fiber optic sensor.
9. The method of claim I wherein the hydrocarbons comprise a gas and the fluid is water.
10. The method of claim 9 wherein the parameter of interest is a location of the gas-fluid interface.
11. The method of claim I wherein the hydrocarbons comprise oil and the fluid is selected from the group consisting of (A) water, (B) steam, (C) C02, and, (D) gas.
12. The method of claim 1 wherein determining said parameter of interest further comprises updating a model of a reservoir in the formation producing said hydrocarbons.
13. The method of claim 1 wherein the survey wellbore is a side well.
14. The method of claim I wherein said seismic signals are transmitted at a location selected f rom (A) a wellbore, and, (B) the surface of the earth.