The invention generally relates to an arrangement comprising as arrangement parts

a) a waveguide, being

i) capable of guiding a mechanical wave, and

ii) at least partially positioned in a borehole,

wherein the borehole

I) comprises an entrance in an Earth surface, and

II) extends into an Earth crust;

b) an injection site, being

i) positioned below the Earth surface by a vertical distance of at least 100 m in the borehole, and

ii) designed to inject a first fluid into the Earth crust;

c) a first sensor arrangement at least comprising a first sensor, wherein the first sensor is designed and arranged to measure the mechanical wave, wherein the mechanical wave is at least partially guided by the waveguide prior to being measured by the first sensor; and

d) a second sensor arrangement at least comprising a second sensor;

wherein the waveguide extends at least partially between the injection site and the entrance, wherein the first sensor arrangement and the second sensor arrangement are time- synchronised, and horizontally distanced from each other by a horizontal distance, wherein the horizontal distance is at least 10 % of the vertical distance. The invention further relates to a process for determining a location of a fracture event, or a size of a fracture generated by the fracture event, or both in an Earth crust; to a process for producing a fossil-fuel-based product; to a fossil-fuel-based product obtainable by the preceding process; to a process comprising storing a fluid in the Earth crust; to a process comprising injecting a fluid at a first temperature into the Erath crust and extracting the fluid at a further temperature from the Earth crust; to a product obtainable by any of the two preceding processes; and to a use of the arrangement ac cording to the invention for monitoring an operation.

Exploiting underground resources by for example extracting oil and gas, enhancing borehole productivity by fracking, circulating water in deep geothermal systems, or injecting waste wa ter is known to alter the pore water pressure level and to induce changes in the subsurface stress regime. This may trigger small to large earthquakes which release the tectonic stress on suitably oriented, pre-existing fault zones, or it may cause earthquakes along the induced stress changes. Most concern and public dispute was on potential damage of houses, infrastructure, and life lines, eventually causing structural failure of buildings with resulting casualties. On a more moderate level of concern, people feel threatened by the acoustic bang and perceivable ground shaking that smaller earthquakes will cause. Both situations are called here the“dam- age/threat” scenario.

The discussions on fracking, especially the danger of portable groundwater pollution by leak age of fracking fluid or contaminated reservoir water, shed light on another scenario that must be considered for save underground operations. A minor earthquake not recognized at surface may still affect the top seal layer which separates the hydraulics of upper layer ground water horizons from the reservoir of oil, gas, geothermal circulation, or waste water injection. In the reservoir salinar, contaminated reservoir water may circulate, and a top-seal-affecting earth quake might cause a new, highly permeable pathway along its rupture length to short circuit both hydraulic systems, or at least open pre-existing, sealed fractures supporting significant diffusion of reservoir water into drinking water aquifers. One way to evaluate the hazard of ground water pollution is to scale the potential earthquake rupture length against the thickness of the geological seal barriers, and to assume the worst case scenario of a rupture activating a near-vertical fault in the top seal layer. Just these near-vertical faults are hard to resolve in any 3D seismic survey, thus they can pose an unforeseeable threat to any subsurface injection or withdrawal operation. Said induced or triggered events may unpredictably happen at any time during or after frack expose. Mostly, one observes the largest event days or weeks after shut-in but for long-term and high-volume reservoir depletion or waste water injection, larger events may be delayed for years after start of operations. This is called here the“ground water pollu tion” scenario. It may be caused by fractures not recognized at surface, thus its seismic moni toring demands a significantly increased sensitivity than for the damage/threat scenario.

To complete the overview on reservoir-related seismicity there are also those minor fractures which indicate the intended growth of fracture systems during fracking operations. This growth is directly linked to the applied hydrostatic overpressure intended to crack the ground around a packered interval of perforated tubing or in an open section of the borehole. These microseismic events will neither be recognized at surface, nor will they question the integrity of caprock sealing. Their appearance in space and time is directly related to the overpressure application. We will call a survey of this situation the diagnostic scenario“ of earthquake monitoring aiming for improved process control during the creation of fracture networks.

In principle, the seismicity of the three described scenarios may be monitored by prior art seismic networks, however with at least the drawbacks discussed below. The different magni tudes of expected earthquakes demand specifically tuned solutions for each scenario in instru ment selection, spatial station coverage, and matching processing algorithms. The most sensi tive approach is required for the diagnostic scenario of monitoring microseismic events during fracking. In principle, this approach may be used to record any stronger event. But the required calculation of Richter magnitude for larger events demands unclipped seismograms containing the full frequency range of radiated energy. Thus, a well suited diagnostic network of short- period geophones would require an upgrade by broadband seismometers to monitor the dam age/threat or the groundwater pollution scenario. Solutions further differ by the required de mands on observed time periods. For the diagnostic scenario of mapping fracture network growth, operational windows of a few days just around the known fracking times may be suf- ficient due to the predictable signal appearance. Monitoring for the damage/threat or the groundwater pollution scenarios, however, may, preferably, start weeks to months before un derground operations start to estimate the unbiased background seismicity in any tectonic re gime. It may, preferably, also extent weeks to months after operations stopped to consider the release of earthquakes after the shut-in and any still continuing subsurface pressure diffusion. Seismic monitoring may, preferably, continue even years after operations stopped for the high- volume activities of fluid depletion, fluid circulation, and fluid injection.

Seismic monitoring can rely on a large variety of sensors, layout schemes, and related pro- cessing software. The selected options influence the size of the monitored area, the achieved sensitivity, the accuracy of earthquake locations, and any further extraction of earthquake source parameters; they also determine the efforts for installation, operations, and mainte nance. The monitoring options are grouped by Joswig (First Break, vol. 26, June 2008, 121- 128) into three principal approaches of microseismic networks, nanoseismic monitoring, and passive seismic.

Microseismic networks and passive seismic are seismic monitoring schemes which are known in the prior art. Microseismic networks have matured over decades to record tectonic earth quakes at local (< 100 km) or regional (< 3,000 km) distances placing at least five to ten sta- tions around the seismic source region. The processing demands signal amplitudes well above the ambient seismic noise for a reliable phase picking. Microseismic networks for reservoir monitoring may rely on surface stations or borehole instruments. Borehole instruments may be at shallow depth for reduced ambient noise, or more costly at reservoir level to also improve the determination of earthquake depth. Borehole sites may be instrumented by geophone strings as downhole arrays to exploit beamforming. The other principle approach, called pas sive seismic uses massive sensor arrays in the orderregime of several thousand sensors placed at surface. Based on this mass of information, it can apply the proven processing steps of stacking and migration used in any active seismic survey for hydrocarbon exploration. Passive seismic is able to resolve radiated seismic energy well below the ambient ground noise level, and may compete in sensitivity with a borehole instrument at reservoir level.

Nanoseismic monitoring fills the performance gap between microseismic networks and passive seismic for surface-based surveillance. In its standard configuration, it is also prior art and was developed in the framework of disarmament control to achieve maximum sensitivity by just a few surface stations. Nanoseismic monitoring reaches this goal by upgrading every network station by a small, tripartite array which results in the additional measurement of back-azimuth and apparent velocity per station. Further necessary improvements are an adaptive signal dis play tool (SonoYiew) for fast visual inspection, and an interactive, constraint-based location software (HypoLine) to support the reasoning on plausibility for candidate solutions, where candidate solutions for a single earthquake location may result from ambiguities in phase pick ing due to low signal -to-noise ratios. The station sensor arrays may also be realized in shallow boreholes for permanent installations.

Comparing the sensitivity demands for the three principal situations in monitoring induced seismicity, i.e., the damage/threat scenario, the groundwater pollution scenario, and the diag nostic mapping scenario to the inherent capabilities of microseismic networks, nanoseismic monitoring, and passive seismic, one finds simple rules for association. Common to all cases and different to natural seismicity, the raised level of ambient ground noise around operational reservoirs must be considered.

Rule (1): The diagnostic fracture mapping can only be performed by passive seismic or bore hole sensor arrays close to reservoir depth. The close-distance records of these small magni tude events feature high frequency content which can well be measured by short period geo phones. Due to superior sensitivity, this approach may also fulfil the demands of both of the hazard assessment scenarios but must eventually be complemented by strong motion sensors for unclipped seismograms and by broadband seismometers for unbiased magnitude calcula tion. The inherent disadvantages of passive seismic and borehole instrumentation are the ex- cessive installation, operational and maintenance costs, especially for long-term monitoring or eventual relocation of sensor sites.

Rule (2): The damage/threat scenario is at the other end of the sensitivity demands, and it can be performed by any of the three seismic monitoring approaches. Established prior art is the monitoring by microseismic networks.

Rule (3): The groundwater pollution scenario poses a new challenge. Here, the sensitivity of microseismic networks is not sufficient to ensure proper operations. Even the densification to twenty or more surface sites will not decrease the source-to-sensor distance below the mini mum distance of source depth to surface, which defines the limit for improving signal-to-noise ratio by decreasing distance. Thus individual phase pickings of weak earthquakes remain un certain, leaving the processing of relevant seismicity out of reach. Approaches of passive seis mic or deep borehole stations could work but have at least the disadvantages of high costs and effort for installation and maintenance. From the known monitoring schemes of the prior art, nanoseismic monitoring would be the best match to capture weak, caprock-relevant ruptures at minimum operation efforts. However, the increased level of seismic ground noise by proxi mate borehole operations, and its amplification in thick sedimentary basins of hydrocarbon production require various improvements even for this best matching approach of prior art.

The present invention improves the monitoring and localization of small earthquakes near boreholes. It does so by producing an additional information to the phase picking or stacking of seismograms measured by prior art. This additional information is gained by measuring the propagation of radiated earthquake waves which are at least partially guided, for example along the borehole tubing or casing. The measurement may be performed by a sensor attached to the head of the borehole. Calibration events of known origin and/or source time within the borehole allow for adjustment of the observed travel times to true depth information. Addi tionally or alternatively, a sensor close to the borehole head may be used since the guided wave along the borehole tubing or casing will radiate a body wave to this sensor, where the constant time delay to the b orehol e-attached sensor can be determined by one calibration event. At least in terms of installation and maintenance efforts, however, the bore-hole at tached sensor is preferred here. The additional information - which may, for example, be gained by the borehole-attached sensor or the sensor close to the borehole head - will improve earthquake depth determination performing as an extra least-squares criterion in the error min imization procedure of prior art. It is independent of any assumption on subsurface velocity models due to the calibration procedure. The additional information derived by this invention compares to deep borehole observations, and thus it is beneficial to any kind of seismic moni toring by surface or shallow borehole stations, i.e., it improves monitoring by microseismic networks, nanoseismic monitoring, and passive seismic. It is a low-cost information gained by minimum operational efforts due to using an existing borehole. Finally, the presented inven tion ideally complements the high-sensitivity, low-cost approach of nanoseismic monitoring for complete acquisition of all caprock-relevant fracture processes to document groundwater integrity for regulatory requirements.

Generally, it is an object of the present invention to at least partly overcome a disadvantage arising from the prior art. It is an object of the invention to provide an arrangement and a pro cess which improve the monitoring and localization of small earthquakes near boreholes. Fur ther, it is an object of the invention to provide the above arrangement and process, wherein both are suited to monitor small earthquakes relevant for the groundwater pollution scenario at minimal installation and maintenance efforts. Further, it is an object of the invention to provide the above arrangement and process, wherein both are characterized by a high level of reliabil ity of operation. Further, it is an object of the invention to provide the above arrangement and process, wherein the both utilize as few sensors as possible. Further, it is an object of the in vention to provide the above arrangement and process, wherein both are capable of long term monitoring. Further, it is an object of the invention to provide the above arrangement and pro cess, wherein both do not comprise seismic sensors deep below the Earth surface at or near reservoir level. A contribution to at least one of the above objects is given by the independent claims. The de pendent claims provide preferred embodiments of the present invention which also serve solv ing at least one of the above mentioned objects.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of an arrangement comprising as arrangement parts

a) a waveguide, being

i) capable of guiding a mechanical wave, and

ii) at least partially positioned in a borehole,

wherein the borehole

I) comprises an entrance in an Earth surface, and

II) extends into an Earth crust;

b) an injection site, being

i) positioned below the Earth surface by a vertical distance of at least 100 m, preferably at least 300 m, more preferably at least 500 m, more preferably at least 750 m, even more preferably at least 1 km, most preferably at least 1.2 km, in the borehole, and

ii) designed to inject a first fluid into the Earth crust;

c) a first sensor arrangement at least comprising a first sensor,

wherein the first sensor is designed and arranged to measure the mechanical wave, wherein the mechanical wave is at least partially guided by the waveguide prior to being measured by the first sensor; and

d) a second sensor arrangement at least comprising a second sensor;

wherein the waveguide extends at least partially between the injection site and the entrance, wherein the first sensor arrangement and the second sensor arrangement are

A) time-synchronised, and

B) horizontally distanced from each other by a horizontal distance,

wherein the horizontal distance is at least 10 %, preferably at least 30 %, more preferably at least 50 %, more preferably at least 75 %, more preferably at least 100 %, even more prefera- bly at least 150 %, most preferably at least 200 %, each of the vertical distance. A preferred entrance of the borehole is a wellhead. Generally, the first sensor arrangement, in particular the first sensor, may be attached to the waveguide or positioned at a horizontal distance from the entrance of the borehole of less than 10 %, preferably less than 7 %, more preferably less than 5 %, even more preferably less than 3 %, most preferably less than 1 %, in each case of the vertical distance. In a particularly preferred embodiment, the first sensor, more preferably the first sensor arrangement is attached to the waveguide. In another preferred embodiment, the first sensor, more preferably the first sensor arrangement, is positioned horizontally distanced from the entrance of the borehole by less than 10 %, preferably less than 7 %, more preferably less than 5 %, even more preferably less than 3 %, most preferably less than 1 %, in each case of the vertical distance. In a further preferred embodiment, the first sensor, preferably the first sensor arrangement, is positioned 5 to 100 m, preferably 2 to 50 m, more preferably 1 to 20 m, in each case horizontally away from the entrance of the borehole. The arrangement of the in vention may, in the alternative to the above, comprise a sensor, preferably a sensor arrange ment, which is attached to the waveguide and, in addition, a sensor, preferably a sensor ar rangement, which is positioned at a horizontal distance from the entrance of the borehole of less than 10 %, preferably less than 7 %, more preferably less than 5 %, even more preferably less than 3 %, most preferably less than 1 %, in each case of the vertical distance. In that case, the sensor, preferably the sensor arrangement, which is attached to the waveguide is referred to herein as the first sensor, preferably the first sensor arrangement, whereas the sensor, prefera bly the sensor arrangement, which is positioned at the above horizontal distance from the en trance of the borehole is referred to as auxiliary sensor, preferably auxiliary sensor arrange ment.

In an embodiment 2 of the arrangement according to the invention the arrangement is designed according to its embodiment 1, wherein the injection site is positioned in a spatially limited volume of the Earth crust, wherein the spatially limited volume is capable of storing a further fluid. In some embodiments of the invention the first fluid may be identical with the further fluid, and in other embodiments of the invention the further fluid may be different from the first fluid. If the first fluid comprises an acid, the further fluid is preferably a hydrocarbon. If the first fluid is a liquid to be deposited into the spatially limited volume, preferably waste wa ter, or a gas to be deposited into the spatially limited volume, preferably methane or a carbon oxide such as carbon dioxide, the first fluid is preferably identical with the further fluid. If the first fluid is to be injected into the spatially limited volume, heated and then extracted from the spatially limited volume, the further fluid is preferably the heated first fluid.

In an embodiment 3 of the arrangement according to the invention the arrangement is designed according to its preceding embodiments, wherein the waveguide is one selected from the group consisting of a drill string, a borehole casing, a cement, a tubing and a sucker rod or a combi nation of at least two thereof.

In an embodiment 4 of the arrangement according to the invention the arrangement is designed according to any of its embodiments 1 to 3, wherein the first sensor is mechanically connected to the waveguide by a connection, wherein the connection is capable of transmitting the me chanical wave from the waveguide to the first sensor. Preferably, the connection is mechani cally rigid.

In an embodiment 5 of the arrangement according to the invention the arrangement is designed according to any of its preceding embodiments, wherein the second sensor arrangement is po sitioned at least 100 m, preferably at least 150 m, more preferably at least 200 m, more prefer ably at least 300 m, most preferably at least 500 m, horizontally away from the entrance of the borehole, wherein the arrangement further comprises 1 to 100, preferably 1 to 75, more prefer ably 1 to 50, more preferably 1 to 25, more preferably 1 to 15, more preferably 1 to 10, more preferably 1 to 5, more preferably 1 to 3, most preferably 1, further sensor arrangement(s), wherein each further sensor arrangement comprises at least one, preferably at least 2, more preferably at least 3, most preferably at least 4, further sensor(s), wherein each further sensor arrangement is positioned at least 100 m, preferably at least 150 m, more preferably at least 200 m, more preferably at least 300 m, most preferably at least 500 m, horizontally away from the entrance of the borehole, wherein each further sensor arrangement is time-synchronised with the first sensor arrangement or the second sensor arrangement or both. In some cases, each further sensor arrangement is time-synchronised with the first sensor arrangement and the second sensor arrangement. Thus, it is preferred that all sensors of the arrangement are time- synchronised. The arrangement can also comprise more sensor arrangements which do not meet the above criteria.

In an embodiment 6 of the arrangement the arrangement is designed according to its embodi ment 5, wherein the second sensor arrangement and each further sensor arrangement are azi- muthally equidistantly arranged around the entrance of the borehole. Preferably, the second sensor arrangement and each further sensor arrangement are arranged with equidistantly spaced azimuthal coverage around the entrance of the borehole. Here,“around the borehole” refers to a spatial distribution of the sensor arrangements. This does not imply that the second sensor arrangement or the further sensor arrangements have to be close to the borehole. In- stead, said sensor arrangements can in some cases be distanced from the borehole by several km.

In an embodiment 7 of the arrangement according to the invention the arrangement is designed according to any of its preceding embodiments, wherein the second sensor arrangement is ar- ranged not further below the Earth surface than the vertical distance, preferably than 90 % of the vertical distance, more preferably than 80 % of the vertical distance, more preferably than 70 % of the vertical distance, more preferably than 60 % of the vertical distance, more prefera bly than 50 % of the vertical distance, more preferably than 40 % of the vertical distance, more preferably than 30 % of the vertical distance, more preferably than 20 % of the vertical dis- tance, even more preferably than 10 % of the vertical distance, most preferably than 5 % of the vertical distance. Additionally or alternatively preferred, each further sensor arrangement is arranged not further below the Earth surface than the vertical distance, preferably than 90 % of the vertical distance, more preferably than 80 % of the vertical distance, more preferably than 70 % of the vertical distance, more preferably than 60 % of the vertical distance, more prefera- bly than 50 % of the vertical distance, more preferably than 40 % of the vertical distance, more preferably than 30 % of the vertical distance, more preferably than 20 % of the vertical dis tance, even more preferably than 10 % of the vertical distance, most preferably than 5 % of the vertical distance. Preferably, the second sensor arrangement is arranged vertically above the spatially limited volume. Additionally or alternatively preferred, each further sensor arrange ment is arranged vertically above the spatially limited volume.

In an embodiment 8 of the arrangement according to the invention the arrangement is designed according to any of its preceding embodiments, wherein the second sensor arrangement is hor- izontally distanced from the injection site by not more than the vertical distance, preferably by not more than 90 % of the vertical distance, more preferably by not more than 80 % of the ver tical distance, more preferably by not more than 70 % of the vertical distance, more preferably by not more than 60 % of the vertical distance, more preferably by not more than 50 % of the vertical distance, more preferably by not more than 40 % of the vertical distance, more prefer- ably by not more than 30 % of the vertical distance, more preferably by not more than 20 % of the vertical distance, even more preferably by not more than 10 % of the vertical distance, most preferably by not more than 5 % of the vertical distance. Additionally or alternatively preferred, each further sensor arrangement is horizontally distanced from the injection site by not more than the vertical distance, more preferably by not more than 90 % of the vertical dis- tance, more preferably by not more than 80 % of the vertical distance, more preferably by not more than 70 % of the vertical distance, more preferably by not more than 60 % of the vertical distance, more preferably by not more than 50 % of the vertical distance, more preferably by not more than 40 % of the vertical distance, more preferably by not more than 30 % of the ver tical distance, more preferably by not more than 20 % of the vertical distance, even more pref- erably by not more than 10 % of the vertical distance, most preferably by not more than 5 % of the vertical distance.

In an embodiment 9 of the arrangement according to the invention the arrangement is designed according to any of its preceding embodiments, wherein the arrangement further comprises an auxiliary sensor arrangement, wherein the auxiliary sensor arrangement comprises at least one, preferably at least 2, more preferably at least 3, most preferably at least 4, auxiliary sensor(s), wherein the auxiliary sensor arrangement is positioned horizontally distanced from the en trance of the borehole by less than 10 %, preferably less than 7 %, more preferably less than 5 %, even more preferably less than 3 %, most preferably less than 1 %, of the vertical distance, wherein the auxiliary sensor arrangement is time-synchronised with the first sensor arrange ment or the second sensor arrangement or both. Preferably, the auxiliary sensor arrangement is time-synchronised with the first sensor arrangement and the second sensor arrangement. In another preferred embodiment, the auxiliary sensor arrangement is positioned 5 to 100 m, preferably 2 to 50 m, more preferably 1 to 20 m, each horizontally away from the entrance of the borehole.

In an embodiment 10 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein one selected from the group consisting of the first sensor arrangement, the second sensor arrangement, each further sensor arrangement, and the auxiliary sensor arrangement, or a combination of at least two thereof is positioned vertically less than 300 m, preferably less than 200 m, more preferably less than 100 m, even more preferably less than 50 m, most preferably less than 10 m, away from the Earth surface. In a preferred design of the embodiment 10 one selected from the group consist- ing of the first sensor arrangement, the second sensor arrangement, each further sensor ar rangement, and the auxiliary sensor arrangement, or a combination of at least two thereof is positioned at the Earth surface. In another preferred design of the embodiment 10 one selected from the group consisting of the first sensor arrangement, the second sensor arrangement, each further sensor arrangement, and the auxiliary sensor arrangement, or a combination of at least two thereof is positioned below the Earth surface in a further borehole.

In an embodiment 11 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein the second sensor arrangement is a second sensor array, wherein the second sensor array further comprises, preferably at least 3, array sensors, wherein each sensor of the second sensor array is positioned inside a sphere having a diameter of not more than 20 %, preferably not more than 15 %, more preferably not more than 10 %, most preferably not more than 5 %, of the vertical distance. In a preferred embodiment, each sensor of the second sensor array is positioned inside a sphere having a di ameter of not more than 300 m, preferably not more than 200 m, more preferably not more than 100 m, most preferably not more than 50 m.

In an embodiment 12 of the arrangement according to the invention the arrangement is de signed according to its embodiment 11, wherein the second sensor is a central sensor of the second sensor array, wherein the array sensors are satellite sensors, wherein the satellite sen sors of the second sensor array are positioned horizontally or vertically or both around the cen tral sensor of the second sensor array. Preferably, the satellite sensors are horizontally posi tioned around the central sensor for optimum azimuthal coverage.

In an embodiment 13 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 5 to 12, wherein each further sensor arrangement is a further sensor array, wherein each further sensor array further comprises at least 2, prefer ably at least 3, further array sensors, wherein for each further sensor array at least holds that each further sensor of the further sensor array is positioned inside a sphere having a diameter of not more than 20 %, preferably not more than 15 %, more preferably not more than 10 %, most preferably not more than 5 %, of the vertical distance. In a preferred embodiment, each sensor of each further sensor array is positioned inside a sphere having a diameter of not more than 300 m, preferably not more than 200 m, more preferably not more than 100 m, most pref erably not more than 50 m.

In an embodiment 14 of the arrangement according to the invention the arrangement is de signed according to its embodiment 13, wherein each further sensor is a further central sensor of a further sensor array, wherein the array sensors of each further sensor array are further sat ellite sensors, wherein the further satellite sensors of each further sensor array are positioned horizontally or vertically or both around the further central sensor of the further sensor array. Preferably, the further satellite sensors of each further sensor array are horizontally positioned around the further central sensor of the same further sensor array for optimum azimuthal cov erage.

In an embodiment 15 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein the second sensor or each fur ther sensor or both is a 3 -component sensor. Herein, a 3 -component sensor is designed for measuring 3 dimensions of a measure such as displacement, acceleration or velocity.

In an embodiment 16 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 11 to 15, wherein each array sensor or each further array sensor or both is a 1-componenet sensor. Herein, a 1 -component sensor is designed for measuring 1 dimension of a measure such as displacement, acceleration or velocity.

In an embodiment 17 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein one selected from the group consisting of the first sensor, the second sensor, each further sensor, and the auxiliary sensor, or a combination of at least two thereof is one selected from the group consisting of a dis placement pick up sensor, an acceleration pick up sensor, and a velocity pick up sensor, or a combination of at least two thereof.

In an embodiment 18 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 11 to 17, wherein the second sensor array is char acterised by a horizontal distance of each satellite sensor of the second sensor array to the cen tral sensor of the second sensor array, or at least one further sensor array is characterised by the horizontal distance of each further satellite sensor of the further sensor array to the further central sensor of the further sensor array, or both, wherein the horizontal distance is at least 30 m, preferably at least 50 m. In an embodiment 19 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein one selected from the group consisting of the first sensor arrangement, the second sensor arrangement, each further sensor arrangement, and the auxiliary sensor arrangement, or a combination of at least two thereof is connected to a recording unit by a data connection, wherein the data connection is designed to transmit data, wherein the recording unit comprises a time-synchronising device, wherein the time-synchronising device is designed to provide a time base. A preferred recording unit is a data logger. A preferred time-synchronising device is a GPS-receiver.

In an embodiment 20 of the arrangement according to the invention the arrangement is de signed according to its embodiments 19, wherein the recording unit is characterised by a sam pling rate in the range from 200 to 2000 Hz. A preferred sampling rate is 100 Hz or 500 Hz. Another preferred sampling rate is 1000 Hz. Another preferred sampling rate is 2000 Hz.

In an embodiment 21 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein one selected from the group consisting of the second sensor arrangement, each further sensor arrangement, and the auxilia ry sensor arrangement, or a combination of at least two thereof is designed and arranged to measure a seismic wave at least partially transmitted through the Earth crust. Preferably, said seismic wave is transmitted directly from a position of an event through the Earth crust to said second or further or second and further sensor arrangement. It is further preferred that the aux iliary sensor arrangement is arranged and designed for measuring a seismic wave being trans mitted along a path from the position of the event to said auxiliary sensor arrangement, where in the seismic wave is guided by the waveguide along a first part of the path and is transmitted through the Earth crust along a further part of the path. Herein, the further part of the path is preferably arranged downstream the first part of the path in direction from the position of the event to the auxiliary sensor arrangement. In an embodiment 22 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 2 to 21, wherein the spatially limited volume com prises at least 500 t, preferably at least 1000 t, of a hydrocarbon.

In an embodiment 23 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 2 to 21, wherein the spatially limited volume com prises at least 500 1, preferably at least 1000 t, of saline water.

In an embodiment 24 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 2 to 23, wherein the spatially limited volume com prises one selected from the group consisting of sandstone, claystone, shale, a sedimentary rock, coal, and limestone, or a combination of at least two thereof. Preferably, the spatially limited volume comprises one selected from the group consisting of sandstone, claystone, shale, a sedimentary rock, coal, and limestone, or a combination of at least two thereof to an amount of at least 30 wt.-%, preferably at least 50 wt.-%, more preferably at least 70 wt.-%, of the total weight of the spatially limited volume. Preferably, the spatially limited volume is a reservoir or a deposit, wherein the reservoir material or the deposit material consists of the aforementioned.

In an embodiment 25 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 2 to 24, wherein a sealing layer of the Earth crust is positioned at least partially vertically above the spatially limited volume, wherein, excluding the borehole, the sealing layer is impermeable for the first fluid or for the further fluid or for both.

In an embodiment 26 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 2 to 25, wherein the waveguide is connected to a pressure unit, wherein the pressure unit is designed to increase a pressure in the spatially lim- ited volume. A preferred pressure is a fluid pressure, more preferably a pressure of the first fluid or the further fluid or both. In one aspect of this embodiment it is preferred that the waveguide is the casing.

In an embodiment 27 of the arrangement according to the invention the arrangement is de signed according to any of its preceding embodiments, wherein vertically between the Earth surface and the injection site a ground water is present. Additionally or alternatively preferred, the ground water is present vertically between the Erath surface and the spatially limited vol ume. Preferably, the ground water is present between the Earth surface and the sealing layer. Further, preferably the ground water is present in form of a ground water layer. For the use throughout this document ground water is water which is positioned vertically below the Earth surface. A preferred ground water is saline water. Another preferred ground water is drinking water.

In an embodiment 28 of the arrangement according to the invention the arrangement is de signed according to any of its embodiments 11 to 27, wherein the second sensor array is char acterised by a further vertical distance of each satellite sensor of the second sensor array from the central sensor of the second sensor array, or at least one further sensor array is character ised by the further vertical distance of each further satellite sensor of the further sensor array from the further central sensor of the further sensor array, or both, wherein the further vertical distance is at least 10 m, more preferably at least 30 m, most preferably at least 50 m.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a process 1 for determining a location of a fracture event, or a size of a fracture generated by the fracture event, or both in an Earth crust, comprising the process steps of

a) detecting a first wave generated by the fracture event by a first sensor or by an aux iliary sensor or both, thereby obtaining a first piece of information;

wherein the first wave is at least partially guided by a waveguide in a borehole; b) detecting a further wave generated by the fracture event by a further sensor, thereby obtaining a further piece of information,

wherein the further wave is propagated from the location to the further sensor through the Earth crust; and

c) comparing the first piece of information to the further piece of information.

A preferred size of the fracture is a length of the fracture. A preferred first wave is guided over at least 10 %, more preferably at least 20 %, most preferably at least 30 %, of a path of the first wave from the location of the fracture event to the first sensor by the waveguide. Herein, pro cess steps a) and b) may be performed consecutively, overlapping in time or simultaneously.

In an embodiment 2 of the process 1 according to the invention the process is designed accord ing to its embodiment 1, wherein the waveguide is one selected from the group consisting of a drill string, a borehole casing, a cement, a tubing and a sucker rod or a combination of at least two thereof.

In an embodiment 3 of the process 1 according to the invention the process is designed accord ing to its embodiments 1 or 2, wherein prior to process step c) the process further comprises detecting an auxiliary wave generated by the fracture event by the auxiliary sensor, thereby obtaining an auxiliary piece of information, wherein the auxiliary sensor is horizontally dis tanced from an entrance of the borehole by a distance in the range from 5 to 100 m, preferably 2 to 50 m, more preferably 1 to 20 m; wherein in process step c) the auxiliary piece of infor mation is compared to the first piece of information, or the further piece of information, or to both. Preferably, the auxiliary wave is a wave which has been radiated from the waveguide through the Earth crust.

In an embodiment 4 of the process 1 according to the invention the process is designed accord ing to any of its embodiments 1 to 3, wherein the fracture event is located

a. in one selected from the group consisting of i) a spatially limited volume of the Earth crust, wherein the spatially limited volume is capable of storing a fluid, wherein the spatially limited volume is positioned vertically below an Earth surface by at least 100 m;

ii) a sealing layer, wherein the sealing layer is positioned vertically above the spatially limited volume,

wherein the sealing layer is, excluding the borehole, impermeable for the fluid; and

iii) a bedrock, wherein the bedrock is located vertically below the spatially lim ited volume;

iv) or a combination of at least two of i) to iii);

b. or between or within two or more of a. i) to a. iii);

c. or both of a. and b.

In an embodiment 5 of the process 1 according to the invention the process is designed accord- ing to any of its embodiments 1 to 4, wherein prior to process step a) the first sensor or the further sensor or both is/are calibrated by the process steps

A) generating a first calibration event of known location within the Earth crust;

B) detecting a first calibration wave A by the first sensor, thereby obtaining a first piece of calibration information A;

wherein the first calibration wave A is

i) generated by the first calibration event, and

ii) at least partially guided by the waveguide;

C) detecting a further calibration wave A by the further sensor, thereby obtaining a further piece of calibration information A,

wherein the further calibration wave A is

i) generated by the first calibration event, and

ii) at least partially propagated from the known location of the first calibration event within the Earth crust to the further sensor through the Earth crust; and D) comparing the first piece of calibration information A to the further piece of cali bration information A.

Herein, process steps B) and C) may be performed consecutively, overlapping in time or sim ultaneously. The first calibration wave A is preferably at least partially guided by the wave- guide in such a way that it is guided by the waveguide over at least a part of its way from the location of the first calibration event to the first sensor.

In an embodiment 6 of the process 1 according to the invention the process is designed accord ing to its embodiments 5, wherein prior to process step a) the auxiliary sensor is calibrated by the process steps

A. detecting an auxiliary calibration wave A by the auxiliary sensor, thereby obtaining an auxiliary piece of calibration information A,

wherein the auxiliary calibration wave A is

i) generated by the first calibration event, and

ii) at least partially propagated from the known location of the first calibration event within the Earth crust to the auxiliary sensor through the Earth crust; and

B. comparing the auxiliary piece of calibration information A to the first piece of calibra tion information A, or to the further piece of calibration information A, or to both.

Herein, process steps A., B) and C) may be performed consecutively, overlapping in time or simultaneously. Further, the process steps B. and D) may be performed consecutively, over lapping in time or simultaneously. The embodiment 6 of the process 1 preferably allows for a sub-calibration of the auxiliary sensor which permits switching from the first sensor to the aux iliary sensor during a measurement. Further, the auxiliary calibration wave A may be partially propagated from the known location of the first calibration event within the Earth crust to the auxiliary sensor by being guided by the waveguide.

In an embodiment 7 of the process 1 according to the invention the process is designed accord ing to any of its embodiments 1 to 6, wherein prior to process step a) the first sensor or the auxiliary sensor or both is/are calibrated by the process steps A] detecting a first calibration wave B by the first sensor or by the further sensor, thereby obtaining a first piece of calibration information B,

wherein the first calibration wave B is

i) generated by a further calibration event within the Earth crust, and ii) at least partially propagated from a location of the further calibration event within the Earth crust to the first sensor by being guided by the waveguide, or from the location of the further calibration event within the Earth crust to the further sensor through the Earth crust, or both;

B] detecting a further calibration wave B by the auxiliary sensor, thereby obtaining a further piece of calibration information B,

wherein the further calibration wave B is

i) generated by the further calibration event, and

ii) at least partially propagated from the location of the further calibration event within the Earth crust to the auxiliary sensor through the Earth crust; and

C] comparing the auxiliary piece of calibration information B to the first piece of cali bration information B.

Herein, process steps A] and B] may be performed consecutively, overlapping in time or sim ultaneously. The first calibration wave B is preferably at least partially guided by the wave- guide in such a way that it is guided by the waveguide over at least a part of its way from the location of the further calibration event to the first sensor or the further sensor. In one embod iment of the process 1, the further calibration event is identical to the first calibration event. In another embodiment of the process 1, the further calibration event is different from the first calibration event. Here, it is not mandatory to know the location of the further calibration event within the Earth crust. Further, the further calibration event may be generated on purpose or it may be an event, preferably a fracture event, which happens without being generated on pur pose. Further, the further calibration wave B may be partially propagated from the location of the further calibration event within the Earth crust to the auxiliary sensor by being guided by the waveguide. In an embodiment 8 of the process 1 according to the invention the process is designed accord ing to any of its embodiments 5 to 7, wherein the first calibration event of known location is one selected from the group consisting of a perforation shot, a ball drop, a detonation and a sleeve opening or a combination of at least two thereof.

In an embodiment 9 of the process 1 according to the invention the process is designed accord ing to any of its embodiments 1 to 8, wherein the fracture size is a length of the fracture in the range from 1 to 100 m, preferably from 3 to 50 m, more preferably from 5 to 40 m, most pref erably from 10 to 30 m. A preferred fracture is a fluid pathway.

In an embodiment 10 of the process 1 according to the invention the process is designed ac cording to any of its embodiments 1 to 9, wherein process step a) is performed within a time interval from 3 years prior to a start of an operation to 3 years after an end of the operation, wherein the operation is one selected from the group consisting of a fluid injection into the Earth crust, preferably into a spatially limited volume of the Earth crust; a fluid extraction from the Earth crust, preferably from a spatially limited volume of the Earth crust; a fluid cir culation into and from the Earth crust, preferably into and from a spatially limited volume of the Earth crust; or a combination of at least two thereof. In a preferred embodiment, the pre ceding time interval is from 3 weeks prior to the start of the operation to 3 weeks after the end of the operation, more preferably from 2 weeks prior to the start of the operation to 2 weeks after the end of the operation.

In an embodiment 11 of the process 1 the process is designed according to any of its embodi ments 1 to 10, wherein the process is performed using the arrangement according to any of its embodiments 1 to 28. A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a process 2 for producing a fossil-fuel-based product comprising the process steps of:

I. performing the process 1 according to any of its embodiments 1 to 11;

II. extracting a fossil fuel from the Earth crust via the borehole; and

III. processing the fossil fuel, thereby obtaining the fossil-fuel-based product.

Preferably, the fossil fuel is extracted from the spatially limited volume according to the ar rangement according to the invention in process step II. Herein, process steps I. and II. may be performed consecutively, overlapping in time or simultaneously.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a fossil-fuel -based product obtainable by the process 2 according to its embodiment 1.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a process 3 comprising the process steps of:

I. performing the process 1 according to any of its embodiments 1 to 11; and

II. storing a fluid in the Earth crust via the borehole.

Herein, process steps I. and II. may be performed consecutively, overlapping in time or simul taneously.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a product obtainable by the process 3 according to its embodiment 1. Here, a preferred product is a deposit in the Earth crust, wherein the deposit comprises the fluid. A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a process 4 comprising the process steps of:

I. performing the process 1 according to any of its embodiments 1 to 11;

II. injecting a fluid at a first temperature into the Earth crust via the borehole; and

III. extracting the fluid at a further temperature from the Earth crust via the borehole; wherein the first temperature is different from the further temperature, preferably by at least 10 °C, more preferably at least 20 °C, more preferably at least 30 °C, more preferably at least 40 °C most preferably at least 50 °C. Preferably, the further temperature is more than the first temperature, wherein the aforementioned values apply more preferably. Herein, the process steps I. and II. may be performed consecutively, overlapping in time or simultaneously. Prefer ably, in the process 4 the process steps II. and III. are repeated in multiple succession, thereby circulating the fluid through the Earth crust. Herein, process steps I. and II., or I. and III, or both may be performed consecutively, overlapping in time or simultaneously.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a product obtainable by the process 4 according to its embodiment 1. Here, a preferred product is a heat, preferably in form of a heated fluid, wherein the heated fluid is preferably hot water or steam or both.

A contribution to the solution of at least one of the above objects is made by an embodiment 1 of a use of the arrangement according to any of its embodiments 1 to 28 for monitoring an op eration selected from the group consisting of a fluid injection into the the Earth crust, prefera bly into a spatially limited volume of the Earth crust; a fluid extraction from the Earth crust, preferably from a spatially limited volume of the Earth crust; a fluid circulation into and from the Earth crust, preferably into and from a spatially limited volume of the Earth crust; or a combination of at least two thereof. A preferred fluid injection is a storing of gas, most prefer ably CO2, or a liquid, most preferably a waste water injection, or both. A preferred fluid ex traction is an oil production or a gas production or both. A further preferred fluid injection is an injection of one selected from the group consisting of hot water having a temperature of at least 40°C, more preferably at least 50°C, more preferably at least 60°C, most preferably at least 70°C, steam, and an acid or a combination of at least two thereof. In a preferred fluid in jection the fluid is injected into the spatially limited volume at a pressure. Entities which are preferred in a certain category of the invention such as the arrangement or the process, are to be understood as preferred in an embodiment of the other categories of the invention respectively. sensor

As sensors of the invention any sensor which is known to the skilled person and which the skilled person deems suitable for the purpose of the invention comes into consideration. Ex emplary sensors are seismometers or geophones or both. A preferred seismometer is designed for measuring one selected from the group consisting of an acceleration, a velocity and a dis placement, or a combination of at least two thereof. For the use in this document, measuring a mechanical wave means preferably measuring a physical parameter of the mechanical wave, such as displacement, acceleration or velocity. A preferred sensor arrangement includes a re cording means for recording measurement data obtained from measuring the mechanical wave. injection site

As the injection site of the invention an injection site of an arrangement for any geological or geophysical or both operation, known to the skilled person, comes into consideration. A pre ferred geological or geophysical or both operation comprises an injection of a fluid into the Earth crust, or an extraction of a fluid from the Earth crust, or a circulation of a fluid through the Earth crust, or a combination of at least two thereof. Therein, the injection is preferably the site at which the fluid is injected into, extracted from or circulated through the Earth crust. A preferred injection site is an injection site of one selected from the group consisting of a frack ing arrangement, a geothermal circulation operation arrangement, and an arrangement for in jecting a fluid into a geological deposit. Preferably, the injection site is a spatially limited vol ume within the borehole, more preferably within a tubing in the borehole, wherein a pressure in this spatially limited region is higher than a pressure in adjacent regions in the borehole, more preferably within the tubing in the borehole. Further preferably, the injection site is a spatially limited volume within the borehole, more preferably within a tubing in the borehole, wherein this spatially limited volume is sealed in a fluid tight manner from adjacent regions of the borehole, more preferably of the tubing in the borehole. Typically, in a geological or geo physical or both operation, such as for example a fracking operation, or an injection operation into a geological deposit, the position of the injection site is recorded in the documentation of the regulatory authority. The injection site may be positioned vertically below the entrance of the borehole or horizontally distanced from the entrance of the bore hole by several 10 m or several 100 m up to several km, but typically not more than 20 km. spatially limited volume

A preferred spatially limited volume is a geological reservoir or a deposit or both. Preferably, the spatially limited volume is positioned vertically below the Earth surface by at least 100 m, preferably at least 150 m, more preferably at least 200 m, more preferably at least 300 m, most preferably at least 500 m. fluid

If not stated otherwise, the following applies to every fluid mentioned in the context of the invention, in particular to the first and the further fluid. For the use throughout this document a fluid is one selected from the group consisting of a gas, a liquid and a granulate or a combina tion of at least two thereof. A preferred gas is one selected from the group consisting of a hy drocarbon gas, a carbon oxide, steam, petroleum gas, natural gas, methane and FE or a combi nation of at least two thereof. A preferred carbon oxide is CO2. A preferred liquid is a liquid hydrocarbon, oil, an acid and water or a combination of at least two thereof. A preferred oil is one selected from the group consisting of bitumen, petroleum, mineral oil, and crude oil, or a combination of at least two thereof. A preferred water is one selected from the group consist ing of a waste water, a contaminated water and a saline, or a combination of at least two there of. A preferred granulate is a proppant. The first fluid preferably comprises one selected from the group consisting of water, preferably waste water, contaminated water, or a saline; a car bon oxide; and an acid; or a combination of at least two thereof. The further fluid preferably comprises one selected from the group consisting of a hydrocarbon gas, a carbon oxide, steam, petroleum gas, natural gas, methane, FE, a liquid hydrocarbon, oil, and water, or a combination of at least two thereof. proppant

In the context of the invention any proppant which the skilled person knows and which he deems suitable to be used for the purpose of the invention comes into consideration. Prefera bly, the proppant is present as a granulate, which may be natural or synthetic or both. A pre ferred granulate is a sand. Therein, the sand may be natural or synthetic or both. entrance of the borehole

In the context of the invention, the entrance of the borehole preferably, but not restrictively, describes an end of a tubing, casing, or production liner (acting as the wave guide) that is or was accessible for drilling operations, and may now be terminated by a well head. This end may be placed on the (former) drill site at surface, or underground in a mining environment. waveguide

For the use throughout this document a waveguide is a body which is capable of guiding a me chanical wave over a distance of at least 30 m such that the mechanical wave is still detectable by the first sensor arrangement. A preferred waveguide is a rigid body. Preferably, the wave guide extends over at least 30 %, preferably at least 40 %, more preferably at least 50 %, more preferably at least 60 %, more preferably at least 70 %, more preferably at least 80 and most preferably at least 90 %, of a length of the borehole. Therein, the length of the borehole in cludes its vertical and horizontal extension. hydrocarbon

A hydrocarbon is an organic compound consisting of hydrogen and carbon and optionally functional groups. Preferred hydrocarbons are those classified by the IUPAC in“A Guide to

IUPAC Nomenclature of Organic Compounds”, R. Panico, W.H. Powell, J.-C. Richer (Eds.), Blackwell Scientific Publications Ltd., Oxford, UK (1993). calibration event

If not stated otherwise, the following applies to the first and the further calibration event. A preferred calibration event is a geological or geophysical or both event, more preferably a frac ture event. In the context of the process according the invention, the first calibration event is an event of known location which is capable of producing a first calibration wave which can be detected by the first sensor after the first calibration wave has travelled a distance from the location to the first sensor; and of producing a further calibration wave which can be detected by the further sensor after the further calibration wave has travelled a distance from the loca tion to the further sensor. A particularly preferred first calibration event is one selected from the group consisting of a perforation shot, a ball drop, a detonation and a sleeve opening or a combination of at least two thereof. In the context of the process according the invention, the further calibration event is an event which is capable of producing a first calibration wave which can be detected by the first sensor or the further sensor or both after the first calibration wave has travelled a distance from the location of the further calibration event to the first sen- sor or the further sensor or both; and of producing a further calibration wave which can be de tected by the auxiliary sensor after the further calibration wave has travelled a distance from the location of the further calibration event to the auxiliary sensor. The location of the further calibration event may be known or not. A particularly preferred further calibration event is one selected from the group consisting of a fracture event, a perforation shot, a ball drop, a detona- tion and a sleeve opening or a combination of at least two thereof. Above, a preferred first cal ibration wave and a preferred further calibration wave is a mechanical wave, respectively. A preferred mechanical wave is a seismic wave. fossil-fuel

A preferred fossil fuel is a material which is at least 1000 years old and which burns exother mically. Preferably, the fossil fuel is gaseous or liquid or both. A preferred liquid fossil fuel is oil. A preferred gaseous fossil fuel is petroleum gas or natural gas or both. fossil-fuel-based product

A preferred fossil-fuel based product comprises a polymer, obtained from the fossil-fuel. fracture event

For the use in this document the fracture event may be any geological or geophysical or both fracture event which the skilled person knows and deems appropriate in the context of the in vention. A preferred fracture event is one selected from the group consisting of an earthquake, a crack formation in the Earth crust, and a movement of regions of the Earth crust relative to each other, or a combination of at least two thereof. In the context of the invention, the fracture event may be induced or natural or both.

TEST METHODS

In absence of a test method, the ISO test method for the feature to be measured being closest to the earliest filing date of the present application applies. In absence of distinct measuring con ditions, standard ambient temperature and pressure (SATP) as a temperature of 298.15 K (25 °C, 77 °F) and an absolute pressure of 100 kPa (14.504 psi, 0.986 atm) apply.

EXAMPLES

The present invention is now explained in more detail by examples and drawings given by way of example which do not limit it.

A detailed description of exemplary designs or embodiments is discussed in the context of figures 1 to 6, for simplicity, for the situation of induced seismic events during fracking opera tions of a conventional hydrocarbon reservoir by one single borehole. Therein, the fracking operation can be directed to enhance the production of crude oil or particularly preferably to the production of gas. The application may also be used for other situations, e.g. CCh seques- tration, hydraulic stimulation of geothermal reservoirs, fracking of unconventional reservoirs, e.g., for shale gas exploitation, or waste water disposal by injection boreholes. Therefore, the specific features and characteristics may be combined in any practical manner in one or more designs or embodiments, which does not limit the invention.

The figures show

1 a scheme of an arrangement according to the invention;

2 a flow diagram of a process for determining a location of a fracture event, or a size of a fracture generated by the fracture event, or both in an Earth crust ac cording to the invention;

3 a flow diagram of another process for determining a location of a fracture event, or a size of a fracture generated by the fracture event, or both in an Earth crust according to the invention;

4 a flow diagram of a process for producing a fossil-fuel-based product according to the invention;

5 a scheme of a fossil-fuel-based product according to the invention; and

6 a flow diagram of monitoring a fracking operation in accordance with the inven tion.

Figure 1 shows a scheme of an arrangement 100 according to the invention. A seismic moni- toring network consisting of two seismic small arrays (second sensor array 130 and further sensor array 130) and two additional sensors (first sensor 131 and auxiliary sensor 132) at a wellhead 123 and at a drilling site, comprising a rig 120, are installed at an Earth surface 101 in order to detect and locate seismicity in and around a gas or crude oil containing reservoir 104 before, during and after a fracking operation. Here, the reservoir 104 is positioned 3.5 km vertically below the Earth surface 101. The seismic small arrays 130 are installed each 2 km horizontally distanced from the wellhead 123. As much as local site and noise conditions al low, the small arrays 130 are distributed around the wellhead 123 with equal azimuthal gap. The sensor 131 is attached to a casing 121 of a borehole 123 at the wellhead 123, and the aux iliary sensor 132 is installed at the drill site 50 m horizontally off the wellhead 123. Each small array 130 consists of seismometers from Lennartz electronic GmbH, Tubingen, Germany (www.1 ennartz-el ectroni c . de) : one short-period, three-component sensor LE-3Dlite Mkll per- forms as central sensor 130a, while three short-period, one-component seismometers LE-IDV Mkll seismometers act as satellite stations 130b arranged around the central sensor 130a with optimum azimuthal coverage, e.g., as tripartite small array with 100 m radius and 120 degree inter-station angle for the minimum of three external sensors 130b. All sensors per small array 130 are connected to a multi-channel data logger Summit M Hydra from DMT GmbH, Essen, Germany (see www.dmt.de). The two sensors 131 and 132 at wellhead 123 and drilling site are LE-IDV Mkll seismometers connected to one Summit M Hydra data logger. All data loggers have an external GPS-sensor for time synchronisation, an external battery for power supply, and operate in continuous mode at 1,000 Hz sampling rate. Recorded data are sent to a central data server via mobile network connection. The casing 121 of the borehole 123 extends from its entrance at the Earth surface 101 through a top layer with ground water aquifer 102, a seal ing layer 103 which except the borehole 123 is impermeable for the gas or crude oil, and the reservoir 104 in which the gas or crude oil is stored. Vertically below the reservoir 104 a bed rock 105 is present. Further, a pressure unit 124 is connected to the casing 121, wherein the pressure unit 124 is a pump which pumps fracking fluid via the borehole 123 into the Earth crust 106, thereby increasing a fluid pressure in the reservoir 104. About 3.5 km vertically be low the Earth surface 101 a tubing in the borehole 123 comprises an open hole section 122, which is designed to inject a fracking fluid from the tubing into the reservoir 104. Accordingly, the open hole section 122 is an injection site 122 according to the invention. Figure 2 shows a flow diagram of a process 200 for determining a location of a fracture event 110 - 112, or a size of a fracture generated by the fracture event 110 - 112, or both in an Earth crust 106 according to the invention. The process 200 is performed using the arrangement 100 according to figure 1 in the context of the fracking operation being directed to a production of natural gas. In a process step a) 201 of the process 200 a first wave 141, 142 generated by the fracture event 110 - 112 is detected. Therein, the fracture event 110 - 112 may be an earth quake 110 in the sealing layer 103, a fracture event 111 in the reservoir 104 or an earthquake 112 in the bedrock 105. The fracture event 110 - 112 generates a seismic wave 141 (first wave) in the Earth crust 106 which propagates through the Earth crust 106 and couples to the waveguide 121 which is the casing 121. Guided by the casing 121, the seismic wave 142 (first wave) propagates to the first sensor 131 which is mechanically connected to the casing 121. Hence, the first sensor 131 detects the first wave 142, thereby obtaining a first piece of infor mation about the fracture event 110 - 112. The first piece of information comprises a time of arrival of the first wave 142 at the first sensor 131 on a synchronised time base and an ampli- tude of the first wave 142. The fracture event 110 - 112 generates a further wave 140 which propagates as a body wave 140 through the Earth crust and in a process step b) 202 is detected by the sensors 130a and 130b of the two seismic small arrays (second sensor array 130 and further sensor array 130), thereby obtaining a further piece of information about the fracture event 110 - 112. The further piece of information comprises a time of arrival of the further wave 140 at the sensors 130a and 130b on the synchronised time base and an amplitude of the further wave 140. In a process step c) 203 the first piece of information is compared to the fur ther piece of information in order to discover the fracture event 110 - 112, to distinguish it from natural noise signals (wind gusts, thunderstorms etc.) and anthropogenic sources and ac tivities (e.g. traffic, industry, explosions, sonic bangs etc.), and to determine its position, time, magnitude, and mechanism. Here, the analysis software HypoLine (see“First Break”, volume

26, June 2008, pages 117 to 124 by Manfred Joswig; download source: http://nano.geophys.uni-stuttgart.de/) is used.

Figure 3 shows a flow diagram of another process 200 for determining a location of a fracture event 110 - 112, or a size of a fracture generated by the fracture event 110 - 112, or both in an Earth crust 106 according to the invention. The process 200 comprises process steps A) 301, B) 302, C) 303, D) 304, a) 201, b) 202 and c) 203. Therein, the process steps a) 201 to c) 203 are the process steps a) 201 to c) 203 of the process 200 according to figure 2. By performing the process steps A) 301 to D) 304 prior to the steps a) 201 to c) 203, the process 200 accord- ing to figure 2 is calibrated. Therefore, process step A) 301 comprises generating a calibration event 113 of known location within the Earth crust 106. Here, a perforation shot 113 is in duced in the casing 121 being located in the reservoir 104. Thereby, a first calibration wave is generated which is coupled to the casing 121 and guided along the casing to the first sensor 131 which is connected to the casing 121 at the wellhead 123. In process step B) 302 the first sensor 131 detects the guided first calibration wave. Thereby, a first piece of calibration infor mation is obtained which comprises a time of arrival of the first calibration wave at the first sensor 131 on the synchronised time base and an amplitude of the first calibration wave. Fur ther, a further calibration wave is generated by the perforation shot 113. Said further calibra tion wave propagates as a body wave through the Earth crust without being guided. In process step C) 303 the further calibration wave is detected by the sensors 130a and 130b of the two seismic small arrays (second sensor array 130 and further sensor array 130), thereby obtaining a further piece of calibration information which comprises a time of arrival of the further cali bration wave at the sensors 130a and 130b on the synchronised time base and an amplitude of the further calibration wave. As a location of the perforation shot 113 which has been induced is known, by comparing the first piece of calibration information to the further piece of cali bration information in process step D) 304 the process 200 can be calibrated. Further, for cali brating the auxiliary sensor 132 of the arrangement 100 according to figure 1 a constant delay time is set between onsets at the auxiliary sensor 132 versus the first sensor 131 due to a con stant path for the auxiliary wave 143 from the waveguide 121 from which the auxiliary wave 143 is radiated to the auxiliary sensor 132.

Figure 4 shows a flow diagram of a process 400 for producing a fossil-fuel-based product 500 according to the invention. The process 400 comprises a process step I. 401 of performing the process 200 according to figure 2, thereby monitoring a fracking operation by which crude oil is extracted from the Earth crust 106 via the borehole 123 in a process step II. 402 which con sequently overlaps in time with process step I. 401; and a process step III. 403 of processing the crude oil, thereby obtaining polyethylene terephthalate (PET) from which the fossil-fuel- based product 500, which is the plastic bottle 500 of figure 5, is produced. Figure 5 shows a scheme of a fossil-fuel-based product 500 according to the invention. The fossil-fuel-based product 500 is a plastic bottle 500 which can be obtained by the process 400 according to figure 4.

Figure 6 shows a flow diagram of monitoring a fracking operation in accordance with the in vention. A reservoir 104 may be bound by an underlaying bedrock 105 and one or more seal ing layers 103 on top eventually intermixed with additional porous sedimentary strata, and finally some portable groundwater layers 102 on top. The reservoir 104 is accessed by a bore- hole 123 which may be prepared for fracking by connection to a suited pressure unit 124. Top seals 103 integrity shall be preserved to prevent groundwater pollution by diffusion of fracking fluid or contaminated /salinar water from the reservoir 104 or other permeable layers in the top seals 103. In order to verify the integrity of top seals 103 the following steps are performed according to the invention: In a step 601 surface sensor arrays are prepared. Therein, a seismic monitoring equipment consisting of one or several small sensor arrays 130 each consisting of at least one 3 -component sensor 130a and three outer 1-component sensors 130b for ground motion, ground velocity, or ground acceleration sited at surface 101 or in boreholes are in stalled. These sensors are intended to measure seismic wave radiation 140 from seismic body and surface waves. Therefore, these sensors are installed close to vertically above an injection site 122 of the fracking operation, i.e. at least within a horizontal radius which equals a vertical distance of the injection site 122 below the Earth surface 101. In a step 602 one or more like wise sensors 131 attached to a borehole casing 121 of one or more boreholes reaching reser voir level are installed at surface 101 or in cementation. The sensors 131 are intended to meas ure guided waves 142 traveling along the borehole casing 121. In a step 603, eventually auxil- iary sensors 132 are installed close to, but not attached to the borehole casing 121. These sen sors 132 are intended to measure seismic waves 143 radiated from the guided waves 142 trav eling along the casing 121. Only if the signal-to-noise conditions permit, sensors 132 will also measure seismic waves 140. In a further step 604 one or more perforation shots 113 are meas ured at the casing sensors 131 to recognize a signal signature of guided waves 142 from impul- sive events originated in or near the borehole 123. If the auxiliary sensors 132 exist, a constant delay time is calibrated between onsets at the sensors 132 versus 131 due to a constant path for the wave 143. If the perforation shot 113 is strong enough to be measured at the surface arrays 131, a known source location can be derived to calibrate the velocity model of the subsurface layers 102 to 105 for hypocenter determination accordingly. In a step 605 continuous monitor ing is started/performed by measuring ground vibration at all sensors. It performs visualization by sonograms, determination of apparent velocities at array sites, and sonification to audio signals to recognize and distinguish between fracture events 110 to 112 originated in the vicin ity of the reservoir 104 and noise bursts from surface sources, e.g. near a rig 120 or pumps 124. In a step 606 candidate events from the analysis of the array stations 130 are correlated with event signatures at the casing instruments 131 to further narrow down the selection of earthquake signals. If the auxiliary sensors 132 exist, their information may re place/complement the information of 131. Further, in a step 607 a decision is made on earth quake/fracture events versus noise bursts in order to continue the analysis. If no earth- quake/fracture event is found (n), the monitoring continues with a loop back to step 605. How ever, if an earthquake/fracture event is found (y), the processing continues with a step 608. Therein, a hypocenter location, origin time, and magnitude is determined from the array sta tions according to the principles of jack-knife evaluation using the software HypoLine (see “First Break”, volume 26, June 2008, pages 117 to 124 by Manfred Joswig). An uncertainty of depth determination is reduced by comparing to travel times of phases at the casing sensors 131, given the known propagation speed of the guided waves 142 along the casing 121. In a subsequent step 609, a location result of step 608 is evaluated with respect to its siting in the bedrock 105, the reservoir 104 or the sealing layers 103 by previous knowledge, e.g. past events, local stress field, geo-mechanical models, reservoir characterization, interpreted seis- mic sections. Further, a rupture length is determined from a magnitude. A decision on a hazard potential of the event is made. If the event 110 reaches the sealing layer 103, and exceeds a critical rupture length related to the thickness of top seal layers 103 (y), information is provid ed to an external traffic light system in a step 610 for further decision on predefined steps to reduce or stop extraction, injection, circulation, or fracking. In case of an event 111 with source location and rupture length in the reservoir 104 (n), information for further analysis of production pathways is collected and the monitoring continues with a loop back to step 605. If the event 112 lays in bedrock 105 (n), information is provided to an external seismic hazard estimation module evaluating the potential effect of pore pressure diffusion for triggering a significantly larger earthquake at pre-existing faults in the bedrock 105 instead of fracturing the weaker, sedimentary layers 103. In this case too, the monitoring continues with a loop back to step 605.

LIST OF REFERENCES arrangement according to the invention

Earth surface

top layer with groundwater aquifer

sealing layer / top seal

spatially limited volume of the Earth crust capable of storing a fluid / reser voir

bedrock

Earth crust

fracture event / earthquake in sealing layer

fracture event in spatially limited volume of the Earth crust capable of storing a fluid / reservoir

fracture event / earthquake in bedrock

calibration event / perforation shot

rig

waveguide / casing of borehole

injection site / open hole section

borehole / wellhead

pressure unit / pumps

second sensor arrangement / second sensor array; further sensor arrangement / further sensor array

a second sensor / central sensor of second sensor arrangement / second sensor array; further sensor / further central sensor of further sensor arrangement / further sensor array

b array sensors / satellite sensors of second sensor arrangement / second sensor array; further array sensors / further satellite sensors of further sensor ar rangement / further sensor array

first sensor arrangement / first sensor auxiliary sensor arrangement / auxiliary sensor

further wave / body wave

mechanical wave / seismic wave / first wave prior to coupling to waveguide mechanical wave / seismic wave / first wave guided by waveguide auxiliary wave

process for determining a location of a fracture event, or a size of a fracture generated by the fracture event, or both in an Earth crust

process step a)

process step b)

process step c)

process step A)

process step B)

process step C)

process step D)

process for producing a fossil-fuel-based product

process step I.

process step II.

process step III.

fossil-fuel-based product / plastic bottle

steps of an exemplary monitoring of a fracking operation