Patent Publication Number: US-2010107753-A1

Title: Method of detecting a lateral boundary of a reservoir

Description:
FIELD OF THE INVENTION 
     The present invention relates to a method of detecting a lateral boundary of a compacting or expanding region in a subsurface formation, and to a method for producing hydrocarbons. 
     BACKGROUND OF THE INVENTION 
     There is a need for technologies that allow monitoring of depleting reservoir regions during production of hydrocarbons from the reservoir. The geometric structure of a reservoir region is normally explored by geophysical methods, in particular seismic imaging of the subsurface during the exploration stage of an oil field. It is however difficult to extract precise information about fluid fill and connectivity between different reservoir regions from seismic data, because relatively small faults and seals are difficult to detect in seismic images. 
     U.S. Pat. No. 6,092,025 discloses a method for enhancing display of hydrocarbon edge effects in a reservoir using seismic amplitude displays based on a delta-amplitude-dip algorithm applied to an amplitude-vs-offset data set obtained from the seismic amplitude. 
     Even at further stages of the development of a field, when data from exploration, appraisal or even production wells are available, there is oftentimes uncertainty about the position of lateral edges of producing reservoir regions. 
     During production of hydrocarbons (oil and/or natural gas), the reservoir region is typically compacting, and this compaction can in principle be studied by time-lapse seismic surveying. In time-lapse seismic surveying, seismic data is acquired at least two points in time, to study changes in seismic properties of the subsurface as a function of time. Time-lapse seismic surveying is also referred to as 4-dimensional (or 4D) seismics, wherein time between acquisitions represents a fourth data dimension. 
     A general difficulty in seismic surveying of oil or gas fields is that the reservoir region normally lies several hundreds of meters up to several thousands of meters below the earth&#39;s surface, but the thickness of the reservoir region or layer is comparatively small, i.e. typically only several meters or tens of meters. Sensitivity to detect small changes in the reservoir region is therefore an issue. Typically operators must gather data from several years of production before clear differences can be detected and conclusions about reservoir properties can be drawn. 
     Similar issues arise in the case of an expansion of a subsurface region. One particular example is the expansion of a reservoir region due to injection of a fluid into a subsurface formation, e.g. CO 2  or water. Another example involves the heating a subsurface region, in which case the reservoir region will expand. There is a need for a more simple method to explore the lateral extension of a compacting or expanding region in a subsurface formation. 
     SUMMARY OF THE INVENTION 
     To this end the present invention provides a method of detecting a lateral boundary of a compacting or expanding region in a subsurface formation, which method comprises 
     determining non-vertical deformation of the earth&#39;s surface above the subsurface formation over a period of time; 
     identifying a at least one contraction area and at least one adjacent dilatation area of the earth&#39;s surface from the non-vertical deformation over the period of time; and 
     using the at least one contraction area and the at least one adjacent dilatation area as an indication of a lateral boundary of the compacting or expanding region. 
     The invention is based on the insight gained by Applicant that a compacting or expanding subsurface region gives rise to a particular pattern of non-vertical (in particular horizontal) deformation at the earth&#39;s surface. The earth&#39;s surface can also be the sea floor in case of an offshore location. A compacting or expanding reservoir gives rise to a lateral contraction area on the surface, adjacent to a dilatation area. This signature is characteristic for a lateral edge of the reservoir. Detection of areas of contraction and dilatation can be far easier than conducting and interpreting seismic surveys, and it is also more sensitive to small changes. 
     In one embodiment, a non-deforming intermediate area is identified between the adjacent contraction and dilatation areas, and it is inferred that the lateral boundary is located underneath that intermediate area. In this way a good estimate of the lateral edges of the reservoir is obtained, without the need for complex geophysical, geomechanical and/or reservoir modelling. 
     It is also possible to identify an area of maximum strain gradient at the earth&#39;s surface, and it can be inferred that the lateral boundary is located underneath the area of maximum strain gradient. 
     When deformation in a particular zone on the earth&#39;s surface is monitored, a number of dilating or contracting areas can be identified, and this is indicative of the fact that a plurality of dilating and contracting zones are present in the subsurface formation underneath the monitored zone. 
     It is not uncommon that in the exploration stage of a hydrocarbon field a plurality of candidate reservoir regions are identified in a subsurface formation, but it is not always clear whether there is fluid connection between such individual regions. Using the present invention, connectivity can be inferred from the number of dilating or contracting areas. If all regions are connected, there will be only one contracting or expanding area on the surface in the case of contracting or expanding regions, respectively. If there is no fluid connectivity, several contracting and dilating areas can be distinguished at surface. 
     The expanding or contracting region of which the lateral boundary is identified can form part of a larger reservoir region, of which it may not be known whether there is fluid connectivity throughout the larger region. In such a case the method of the invention allows to identify a flow barrier in the larger reservoir region at the lateral boundary. 
     Advantageously the non-vertical deformation can be interpreted using a geomechanical and/or reservoir model of the subsurface formation. 
     There is also provided a method for producing hydrocarbons from a subsurface formation, wherein a lateral boundary of a compacting or expanding region in the subsurface formation is detected according to the method of detecting a lateral boundary. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       An embodiment of the invention will now be described in more detail and with reference to the accompanying drawings, wherein 
         FIG. 1  shows schematically the vertical displacement ( 1   a ), horizontal displacement ( 1   b ), and horizontal strain ( 1   c ) in the subsurface due to a compacting subsurface region; 
         FIG. 2  shows schematically areas of contraction and expansion on the surface, for three cases of compacting subsurface regions; 
         FIG. 3  shows calculations of the horizontal displacement and horizontal strain on the surface, for three cases of compacting subsurface regions; 
         FIG. 4  shows the horizontal strain ( 4   a ) and horizontal strain gradient ( 4   b ) at surface above an edge of a compacting thin horizontal subsurface region, for various ratios of width to depth of the region; 
         FIG. 5  shows schematically two arrangements of sensors on the sea floor. 
     
    
    
     Where the same reference numerals are used in different Figures, they refer to the same or similar objects. 
     DETAILED DESCRIPTION OF THE INVENTION 
     Reference is made to  FIG. 1 .  FIG. 1  shows three pictures of a vertical cross-section through a subsurface formation  1 , which is in this case underneath a sea bed  2 . A reservoir layer  5  is present at a distance under the sea floor  7 , which forms the earth&#39;s surface. 
       FIG. 1  displays the results of a geomechanical modelling of the subsurface formation  1 . The used model is based on a homogeneous isotropic linear poro-elastic half-space extending downwardly from the earth&#39;s surface, and containing a block-shaped reservoir subject to a uniform reduction in pore fluid pressure. The pore pressure change was selected to achieve a maximum of 1 m of compaction inside the reservoir. The shear modulus is 1 GPa and the Poisson&#39;s ratio is 0.25. We note the following conclusions drawn from these solutions are independent of the choice of shear modulus and Poisson&#39;s ratio. 
     All pictures in  FIG. 1  show shading. The shading scale is given at the right hand side, and the areas of positive and negative values are indicated by “+” and “−”, respectively. 
     The top picture,  FIG. 1   a , is shaded according to vertical displacement in response to a compaction of the reservoir, such as due to depletion by production of hydrocarbons from the reservoir through a well (not shown). Subsidence is counted as positive displacement. The strongest subsidence is observed in the overburden  11  just above the compacting reservoir. The sea floor  7  subsides strongest above the centre of the reservoir. The example also shows uplift in the underburden  12 . 
     The middle picture,  FIG. 1   b , maps the horizontal displacement in the subsurface formation  1  and on the sea floor  7  in the paper plane. Displacement to the right is counted positive. It was realized that a volume decrease of a subsurface reservoir does not only lead to vertical compaction, but is typically accompanied by a horizontal contraction of the reservoir. The contraction is minimum in the centre and strongest towards the lateral edges of the reservoir. As a result, contraction is also visible on the surface (sea floor) as a deformation. The contraction on the surface is strongest at and above the lateral edges  15 , 16  of the reservoir layer. 
     The bottom picture,  FIG. 1   c , displays horizontal strain in the subsurface formation, which is calculated as the derivative of the displacement in the middle picture with respect to the horizontal (x) co-ordinate in the paper plane. Dilatative strain is counted positive. It is found that the strain changes sign from compressive to dilatative, approximately above the lateral edges of the reservoir. Therefore, the presence of adjacent contracting and dilating areas can here be detected by determining the strain and identifying a change of sign. From the comparison of  FIGS. 1   b  and  1   c  it is clear, that adjacent contracting and dilating areas can also be detected by identifying an area of maximum horizontal deformation. 
     Reference is made to  FIG. 2 , schematically showing several situations of compacted reservoir regions in a subsurface formation, e.g. due to (partial) depletion. 
     In  FIG. 2   a , a single reservoir region  11  is present in the subsurface formation  12  underneath the surface  13 . Vertically above the reservoir region there is an area of contraction  15 , indicated by a waved line. Adjacent thereto are areas of dilatation  17   a ,  17   b , indicated by dashed lines. Intermediate between the contraction and dilatation areas are, at least within the measurement accuracy, substantially non-deforming areas  18   a    18   b , indicated by solid lines and indicative of the lateral edges  19   a ,  19   b  of the reservoir region  11  therebelow. Note that the non-deforming areas have (near-)zero strain, but can laterally shift, as visible for example in  FIG. 1   b.    
       FIG. 2   b  shows the situation of two laterally adjacent reservoir regions  21   a    21   b , both of which are compacting due to depletion, and between which there is no fluid communication. In this example, two areas of contraction  25   a    25   b  can be distinguished at the surface  22 , separated by an area of dilatation  26 , which is an indication at surface that the two reservoir regions are not in fluid communication with each other. Further areas of dilatation  27   a ,  27   b  and intermediate non-deforming areas  28   a ,  28   b ,  28   c ,  28   d  can also be distinguished. The intermediate areas are again indicative of the lateral boundaries  29   a ,  29   b ,  29   c ,  29   d , of the reservoir regions. It can be the case that the reservoir structure shown in  FIG. 2   b  is not distinguishable in seismic imaging from the single reservoir region  1 , because the boundaries  29   b  and  29   c  merely present a narrow flow barrier between compartments of a larger reservoir structure. 
       FIG. 2   c  shows a somewhat similar situation to that of  FIG. 2   b ; however, in this case the reservoir regions  31   a  and  31   b  are in fluid contact with each other, as indicated by the long dashed line  32 . The two reservoir regions behave similar to a single region during depletion, so the signature of contracting and dilating areas on surface is similar to that of  FIG. 2   a . A single contracting area  35  is surrounded by dilating areas  37   a ,  37   b , with intermediate non-deforming areas  38   a  and  38   b  therebetween. 
     Reference is now made to  FIG. 3 , which displays quantitative examples of the horizontal deformation at the earth&#39;s surface induced by reservoir compaction due to depletion, for different cases of connectivity within the reservoir region. Calculations were made for a reservoir that is 9 km wide, 100 m thick, and located 1 km below the earth&#39;s surface, and further using the same model assumptions as discussed for  FIG. 1 . In this example, the third reservoir dimension in the horizontal plane is equal to the horizontal dimension shown. Results are shown for a line passing above the centre of the reservoir. 
     Deformation is shown for a depletion corresponding to uniform depletion equivalent to a maximum of 1 m of reservoir compaction. 
     In  FIG. 3   a  there is uniform depletion throughout the reservoir  41 . Crosses  43  denote horizontal surface displacements D h ; positive displacements are oriented towards the right. The maximum absolute displacement is found approximately at the lateral edges  45 , 46  of the reservoir. The solid curve  48  denotes horizontal strain; positive strain corresponds to dilatation (elongation). The strain exhibits a zero-crossing at the maximums of the absolute displacement, i.e. where there is a transition from contraction to dilatation. 
     In  FIG. 3   b , the reservoir  51  has a flow barrier  52  preventing fluid communication between the left half  53  and the right half  54 . It is assumed that fluid is produced through a well (not shown) extending from surface into the left half  53 . The right half does not deplete due to the flow barrier  52 . This can be detected at surface. The horizontal deformation  56  and horizontal strain  58  have a signature corresponding to only the left half of the reservoir region compacting. The flow barrier  52  is detected as the right lateral edge of the compacting region  53 . 
     In  FIG. 3   c , finally, the reservoir region  61  has three compartments  62 ,  63 ,  64 . The central reservoir compartment  63  does not deplete due to flow barriers  66 ,  67 . These can again be detected by the characteristic signature of the horizontal deformation  68  and the horizontal strain  69  at the earth&#39;s surface above, at the hand of the transition between contracting and dilating deformation. 
     The assumed compaction in this example of 1 m is very substantial, and so is the magnitude of the deformation at the earth&#39;s surface. The deformation scales proportional to the amount of compaction. It shall be clear that much smaller effects such as compaction of the order of 1-5 cm, or even less can be detected, by detecting horizontal deformation in the same order of magnitude at surface, over distances of the order of a kilometre or more. 
       FIG. 4   a  shows the horizontal strain ε xx  as a function of the distance from the centre of a depleting block-shaped region. The horizontal distance is normalised by the half-width of the block such that its lateral boundary always occurs at x=1. In all cases the region is thin compared to its lateral extent, i.e. has a thickness of less than 20% of its width. Results are shown for the range of horizontal block sizes of 20% (curve  71   a ), 40% ( 72   a ), 60% ( 73   a ), 80% ( 74   a ) and 100% (curve  75   a ) of their depth below the earth&#39;s surface. In all cases a transition from contraction above the depleting reservoir to dilatation beyond the lateral edge is seen. The location of zero horizontal strain separating regions of contraction and elongation is a good indication of the lateral edge; however, it can be seen that it only correctly locates the edge of the depleting reservoir if the lateral extent of this region, w, is large compared to its depth below the earth&#39;s surface, z, i.e. w/z&gt;&gt;1. 
       FIG. 4   b  shows the horizontal derivative of the horizontal strain, dε xx /dx, with the curves  71   b ,  72   b ,  73   b ,  74   b ,  75   b  derived from curves  71   a ,  72   a ,  73   a ,  74   a ,  75   a  of  FIG. 4   a . The horizontal derivative is maximum at the lateral boundary of the depleting reservoir regardless of its lateral extent or depth. Therefore, locating a maximum of the strain gradient on the earth&#39;s surface is an even more accurate approach to determining the lateral edge. A derivative of strain such as the horizontal derivative of horizontal strain is referred to as strain gradient, in particular lateral strain gradient along the surface is of interest. 
     In practice, measurements will have a finite accuracy so that a zero strain, within the measurement accuracy, can be found in a certain area intermediate between contracting and dilating areas. 
       FIG. 4  also shows that edges of subsurface regions with a large w/z ratio can be better detected than smaller regions. The minimum lateral size of region detectable depends the precision of measurements available for the horizontal components of deformation induced at the earth&#39;s surface. The size of this seabed horizontal strain signal depends on the change in reservoir thickness and on the ratio of the lateral size of the reservoir to its depth. 
     Contraction corresponds to negative strain, and therefore maximum contraction corresponds to the local minima in the value of strain induced at the surface. The maximum magnitude of horizontal contraction of the earth&#39;s surface due to compaction of the reservoir is approximately equal to u/(3 πd), where u is reservoir compaction in meters and d is the depth of the reservoir in meters. 
     The ratio of maximum horizontal elongation to maximum horizontal contraction of the earth&#39;s surface for a unit compaction (1 m) is 1+3πd/w, where w is the width of the depleting reservoir. 
     In the Figures a compacting reservoir has been discussed. It will be clear that the case of an expanding subsurface region has an inverse (qualitatively a change of sign), but otherwise analogous, signature. 
     Examples will now be discussed which show how the non-vertical deformation of the earth&#39;s surface can be determined. 
     On land, known geodetic methods and equipment can be used, for example satellite based measurements such as geodetic use of global positioning satellite systems (e.g., GPS), Laser ranging to satellites, synthetic aperture radar interferometry from orbit, but also more traditional geodetic techniques such as levelling, precision tilt meters and/or gravity measurements. 
     An important application of the present method is also in conjunction with offshore production of hydrocarbons, and in order to apply the present method at an offshore location, the deformation of the sea floor is to be measured. 
     In one embodiment, determining non-vertical deformation of the sea floor comprises selecting a plurality of locations on the sea floor and determining the change in distance between at least one pair of the locations over the period of time. At each such location a sensor can be installed, permanently or periodically, and the distance between a pair of sensors at an initial time and at a later point in time can be compared. Preferably sensors are arranged in a grid or along a line. This allows mapping of displacements in a monitoring zone on the sea floor, and also distance measurements from one location to a plurality of other locations. 
     The expression ‘sensor’ is used herein to refer to any device used in determining a change of its location, and includes for example acoustic, electric or electromagnetic transmitters, receivers, transceivers, transponders, transducers; tilt meters, pressure gauges, gravity meters, etc. 
     The distance can for example be determined by means of acoustic transmitters/receivers placed at the plurality of locations, or by means of a fibre optic strain sensor coupled at a plurality of locations to the sea floor. 
     It can be advantageous to measure vertical displacement of the seafloor over the same period of time. In particular, depth sensors such as pressure or gravity sensors can be arranged at the same locations as for measuring non-vertical displacement. In case the vertical displacement is available as well, a relationship such as a ratio between horizontal and vertical displacements at a selected point, or more points if available, can be determined and used to estimate the lateral position of a centre of compaction or expansion in the subsurface formation. 
     In  FIGS. 5   a  and  5   b  two arrangements of a measurement network on the sea floor are sketched. At each location  31  an acoustic transmitter and/or receiver is arranged, suitably a transponder responding by an acoustic signal to a signal it receives from another transponder. Suitable acoustic transponders are for example manufactured by Sonardyne International Limited of Yateley, UK, and these are typically used for positioning of equipment on the sea floor. 
     By a linear arrangement as in  FIG. 5   a , an extended one-dimensional horizontal displacement profile can be measured, as e.g. in  FIG. 1  or  3 . The grid of  FIG. 5   b  allows mapping of the displacement in two dimensions. Also, distances from one of the locations  31  to several nearest neighbours and further neighbours can be determined, which allows to carry out consistency checks so as to increase the overall accuracy of measurements. Of course other grids are possible as well, and it is not required to adhere to a regular grid. More or less transponders can be installed. 
     A suitable distance between locations of adjacent transponders on the sea floor is from 10 to 100% of the reservoir depth, preferably between 20 and 60%, such as 40% of reservoir depth. 
     Using a pair of acoustic transponders an acoustic travel time can be determined, which can be converted to a distance between the respective locations using the speed of sound in sea water. Preferably, sound speed sensors are arranged on the sea floor as well, such as one at each transducer location, to be able to take fluctuations due to e.g. temperature or salinity changes into account, thereby increasing accuracy of the measurements. 
     Subsea transponders preferably operate wireless and are suitably equipped with a power supply such as batteries that allows extended operation of many months, preferably at least 6 months, more preferably several years. Data can be stored for days, weeks or months, and transmitted to a transducer on a buoy, ship, or platform. Because the underlying deformation is slow, in the order of few cm/year at maximum, an acoustic transducer network does not need to operate continuously which saves battery life. The transponders can be permanently installed, but also periodical installation at pairs of locations is possible, carried out by a remotely operated vehicle for example. A permanent installation is preferred, however, since repositioning errors are circumvented in this way. This is in fact an advantage of sub-sea acoustic lateral measurements over subsidence measurements by pressure sensors, which have insufficient long-term stability for accurate measurements in a permanent installation over periods of months, and need therefore regular calibration for which they need to be removed from the sea floor. 
     Alternatively, fibre optic strain sensors can be used for measurement of the non-vertical sea-floor deformation. Such sensors are for example manufactured by Sensornet Ltd. of Elstree, UK. A fibre optic strain sensor can monitor strain over extended distances of kilometres, and a strain profile with a resolution of about 1 m can be obtained. The sensor cable is to be anchored to the sea floor to provide sufficient coupling. 
     Another measurement option is through repeated imaging, such as sonar imaging, from moving vehicles with precise positioning. 
     Advantageously, vertical displacement may be monitored as well. In one embodiment involving a sea floor installation for monitoring deformation, sensors for detecting vertical displacement such as pressure and/or gravity sensors may be included. It becomes clear from  FIG. 2  that complementary information can be obtained from horizontal and vertical displacement. For example, the maximum horizontal displacement is observed above the lateral edges of the reservoir, and the ratio of vertical to horizontal displacement is a very sensitive indicator of the centre of the compacting or expanding reservoir, as vertical displacement is maximum there and horizontal displacement substantially zero.