WO2022231436A1

WO2022231436A1 - Hydrocarbon exploration method

Info

Publication number: WO2022231436A1
Application number: PCT/NO2022/050095
Authority: WO
Inventors: Svend ØSTMO; Vegard Muribø BERG; Thomas RØSTE
Original assignee: Equinor Energy As
Priority date: 2021-04-30
Filing date: 2022-04-27
Publication date: 2022-11-03
Also published as: GB202106208D0; NO20231109A1; GB2606705A; GB2606705B

Abstract

A method of exploring for hydrocarbons in a region comprises obtaining seismic data for the region. The seismic data comprises seismic data measured at two or more different times (e.g. dates). The method further comprises comparing the seismic data measured at two or more different times, wherein comparing the seismic data measured at two or more different times comprises determining a time shift between the seismic data measured at two or more different times. The method further comprises assessing, based on the comparison of the seismic data measured at two or more different times, whether there is likely to be hydrocarbons in the region. If it is assessed that there is likely to be hydrocarbons in the region, the method further comprises assessing whether the hydrocarbons are likely to be oil or gas.

Description

Hydrocarbon exploration method

The present invention relates to the field of hydrocarbon exploration. In particular, it relates to a method of exploring for hydrocarbons by analysing seismic data collected at different times (e.g. dates).

Hydrocarbon exploration is typically a costly endeavour which involves much time spent looking for new locations of hydrocarbons. Thus, it would be desirable to find a better method of exploring for hydrocarbons. In particular, it would be desirable to find an improved method of exploring for hydrocarbons which involves making a determination of whether potential hydrocarbons are likely to be oil or gas.

According to one aspect, there is provided a method of exploring for hydrocarbons in a region, the method comprising: obtaining seismic data for the region, the seismic data comprising seismic data measured at two or more different times; comparing the seismic data measured at two or more different times, wherein comparing the seismic data measured at two or more different times comprises determining a time shift between the seismic data measured at two or more different times; assessing, based on the comparison of the seismic data measured at two or more different times, whether there is likely to be hydrocarbons in the region; and if it is assessed that there is likely to be hydrocarbons in the region, assessing whether the hydrocarbons are likely to be oil or gas.

There exists a great deal of seismic data collected about the regions around existing wells, e.g. for well-monitoring purposes. Much of this seismic data has been collected over a long time period such as a number of years. The present invention provides a way to exploit such data (or other, e.g. new data) to look for potential new locations of hydrocarbons within regions perhaps covered by existing data, but where (i.e. at (new) locations within the region(s)) it was not previously known that hydrocarbons were present. As such, the step of assessing, based on the comparison of the seismic data measured at two or more different times, whether there is likely to be hydrocarbons in the region, may comprise finding or identifying a new location or locations of hydrocarbons within the region, e.g. based on the comparison. A new location of hydrocarbons preferably means a location of a source of hydrocarbons whose existence (i.e. the existence of the source of hydrocarbons) was not previously known. As such, preferably, a new location of hydrocarbons is not just an updated/shifted location of a previously known source of hydrocarbons. Thus, preferably, the method comprises finding or identifying a new or further source of hydrocarbons in a region, wherein the existence of the new or further source of hydrocarbons was preferably not previously known.

In addition, the present invention provides a method of assessing whether potential hydrocarbons, e.g. as found in this method, are likely to be oil or gas.

In regions where, or close to where, there are hydrocarbon productions taking place, over time there is typically a decrease in the pressure of any hydrocarbons remaining in that region, i.e. which have not (yet) been extracted, and whose existence may not previously have been known. Such a pressure drop (which may typically be around 5 - 10 bar) may spread over a distance of tens of kilometres, for example. When such a pressure drop occurs, this can cause various effects to occur such as gas cap expansion and gas coming out of (oil) solution.

Hydrocarbons in a gas phase are usually more clearly visible in seismic data than hydrocarbons in a liquid phase. Thus, if either of the above effects (e.g. gas cap expansion or gas coming out of solution) occurs, and can be seen in seismic data, then this could be an indication of a possible location of hydrocarbons, which may have not previously been known. Such hydrocarbons could, for example, be in a location close to, but a distance away from, an existing well. Looking for hydrocarbons in such regions, i.e. close to an existing well, can be more economically viable than looking in other regions because there can be existing infrastructure already present in or close to the region which may be utilised.

Thus, the present invention provides a way of looking for such effects in seismic data for a region corresponding to two or more different times (two or more different dates), to determine (e.g. by looking for an indicator of a possible source of hydrocarbons) whether there may be a (e.g. further) source of hydrocarbons in the region.

A region may be a subsurface volume corresponding to which seismic data (e.g. a seismic data set corresponding to a seismic survey) has been (or is) obtained. The region may comprise one or more previously known and/or unknown sources of hydrocarbons, for example. The method comprises obtaining seismic data for the region corresponding to (or measured at) two or more different times (two or more different dates).

Preferably, the two or more different times are at least around 1, 2, 3, 4 or 5 or 10 years apart. If the times are closer than this, a relevant effect or change may not be noticeable or present in the data.

Some or all of the seismic data may comprise existing seismic data (e.g. without the need to perform a new seismic survey). Such existing seismic data may be “vintage” seismic data, as it is often referred to in this field. A vintage of seismic data refers to a previously recorded seismic data set, i.e. which was recorded (for a region) in the past. In some cases, the seismic data for a region corresponding to two or more different times (two or more different dates) may comprise two or more vintages of seismic data, e.g. seismic data which has been recorded in the past at two or more different times (two or more different dates).

The two or more vintages of seismic data, e.g. seismic data which has been recorded in the past at two or more different times (two or more different dates), need not necessarily both or all cover exactly the same region. For example, it may be sufficient for the two or more vintages of seismic data, e.g. seismic data which has been recorded in the past at two or more different times (two or more different dates), to cover a common or overlapping region, which could, for example, be smaller than a total region covered by one or more of the two or more vintages of seismic data.

Such existing seismic data as described above may be obtained or recovered from a memory (e.g. an archive), i.e. a location where it has (previously) been stored.

Alternatively or additionally, in some cases, a (e.g. new) seismic survey may be performed to obtain (e.g. some) of the seismic data (e.g. corresponding to at least one (later) time). Such seismic data may then be compared to older, existing seismic data, such as described above.

Thus, the step of obtaining seismic data for the region corresponding to two or more different times (two or more different dates) may comprise obtaining that, or some of that (e.g. corresponding to at least one time), seismic data from one or more memories, and/or it may comprise performing one or more seismic surveys to obtain seismic data corresponding to at least one, or two or more, time(s).

The seismic data for the region corresponding to two or more different times preferably comprises four-dimensional seismic data. This is because four- dimensional seismic data comprises seismic data measured at at least two (i.e. at two or more) different times in a sufficiently similar way (e.g. with the same equipment, and/or set up in the same way/positions) that the seismic data measured at different times can be easily and/or meaningfully compared, e.g. without the need for significant or substantial preconditioning.

“Four-dimensional seismic data” may also sometimes be referred to as “time lapse seismic data” or “repeat seismic data”. The term “four dimensional seismic data” refers to seismic data (which is usually three-dimensional seismic data) which has been or is acquired at different times (e.g. different dates, and at regular or irregular intervals) over a same area or region. Typically, in the prior art, this is done in order to assess changes in a producing hydrocarbon reservoir over time. Four-dimensional seismic data is typically acquired for a constant area or region, where source and receiver positions are ideally steered and/or controlled in such a way that the geometrical deviations between e.g. two different seismic acquisitions (surveys) are as small as operationally possible, e.g. to within 10-20 m. For example, a baseline survey is typically acquired where source and receiver locations are positioned as close as possible to predefined locations and where follow-up monitor surveys are acquired to repeat the baseline survey source and receiver locations as closely as possible. Thus, four-dimensional seismic data may be seismic data measured for or over a same region at two or more different times in a same or similar way (as described above). Four-dimensional seismic data may be stored in memory as a single data set, for example.

However, the seismic data for the region corresponding to two or more different times (two or more different dates) need not necessarily comprise such four-dimensional seismic data as described above.

The seismic data for the region corresponding to two or more different times (two or more different dates) may additionally or alternatively (to the four dimensional seismic data described above) comprise two- or three-dimensional seismic data. In contrast to four-dimensional seismic data as described above, such two or three-dimensional seismic data may not necessarily have been recorded for exactly the same area or region, and/or for the purpose for reservoir monitoring of producing hydrocarbon fields. However, at least some of the area or region should be a common area or region for all seismic data sets. In addition, such two or three-dimensional seismic data may not necessarily have been recorded with sources and/or receivers for the seismic data acquisition process in fixed positions and/or towing paths/directions. It is preferable that the seismic data is recorded with sources and/or receivers for the seismic data acquisition process in as close to the same positions and/or towing paths/directions as is operationally possible. However, if this is not the case, or not possible, then the (or some of the) seismic data may be preconditioned such that it can be compared with the rest of (or some of the rest of) the seismic data, e.g. seismic data recorded at a different time. This is described in more detail below.

Seismic data for the region corresponding to one time (e.g. one date) may be referred to as a set of seismic data. Thus, the seismic data for the region corresponding to two or more different times (two or more different dates) may comprise at least a first seismic data set corresponding to a first time and a second seismic data set corresponding to a second time. The method may thus be said to comprise obtaining two or more sets of seismic data for the region corresponding to two or more different times (two or more different dates).

The method may comprise preconditioning at least one of the first and second seismic data sets, e.g. such that the first and second seismic data sets can be (or more easily/usefully/meaningfully be) compared. Such preconditioning can allow the sets of seismic data corresponding to two or more different times to be (or more easily/usefully/meaningfully be) compared. For example, a first set of seismic data corresponding to a first time may be preconditioned, or transformed, (e.g. to make it more similar to a second set of seismic data corresponding to a second time), such that it can be compared with a second set of seismic data corresponding to a second time. Thus, the preconditioning may turn (or transform) at least one of the at least two sets of seismic data into the same (or a similar or comparable) format as the other set(s) of seismic data, such that they can be compared. For example, preconditioning may comprise equalising one or more variables such as amplitude levels and/or a spectral bandwidth of the seismic data set(s). Such preconditioning can help to resolve issues with the seismic data sets not having been recorded in exactly the same way, such as receivers not being in exactly the same positions and/or sources not having the same towing path/direction. Preconditioning may be performed as in the prior art of four dimensional processing and data matching.

However, preferably, the seismic data for the region corresponding to two or more different times (two or more different dates) are measured in the same or a sufficiently similar way, e.g. such that they can be compared. As such, preconditioning as described above may not be required. Measuring the seismic data corresponding to two or more different times in the same or a sufficiently similar way may comprise: towing a vessel for performing a seismic survey to obtain the seismic data in a same or similar direction and/or along a same or similar path; and/or using receivers located in the same or similar positions for detecting and recording the seismic data, such that, for example, source and receiver positions are ideally steered and/or controlled in such a way that the geometrical deviations between e.g. two different seismic acquisitions (surveys) are as small as operationally possible, e.g. to within 10-20 m. The receiver(s) may in some cases be located in fixed positions in or on the subsurface. In such cases, the source(s) is (are) preferably towed in as similar a manner as possible, e.g. with regards to the receivers, to measure the seismic data corresponding to two or more different times.

The seismic data for the region corresponding to two or more different times preferably comprises at least a first seismic data set corresponding to (measured at) a first time and a second seismic data set corresponding to (measured at) a second time. If four-dimensional seismic data is used, the first seismic data set may be a sub-set of the four-dimensional seismic data measured at a first time, and the second seismic data set may be a further sub-set of the four-dimensional seismic data measured at a second time.

In the method, by comparing seismic data for a region measured at two or more different times, an assessment can be made about whether there is likely to be hydrocarbons in the region and whether such hydrocarbons are likely to be oil or gas.

The method comprises, comparing the seismic data measured at two or more different times and assessing, based on the comparison of the seismic data measured at two or more different times, whether there is likely to be hydrocarbons in the region (e.g. new or previously unknown sources of hydrocarbons as discussed above). Comparing the seismic data measured at two or more different times preferably comprises looking for any changes in the seismic data measured at two or more different times, for example by comparing seismic signal strength. For example, changes in the seismic data (such as amplitude changes and/or time shifts, as described herein) may indicate that gas cap expansion and/or gas coming out of solution has occurred. As discussed above, this, in turn, can indicate a possible presence of hydrocarbons. It can be difficult to detect effects such as gas cap expansion and/or gas coming out of solution in isolation, i.e. by looking at two (or more) sets of seismic data (measured at different times) separately or individually, as such effects tend to result in only relatively small changes in the seismic data. However, determining a difference between the seismic data corresponding to two or more different times can allow such effects to be more noticeable or apparent.

Assessing, based on the comparison of the seismic data measured at two or more different times, whether there is likely to be hydrocarbons in the region (e.g. new or previously unknown sources of hydrocarbons as discussed above) may comprise performing such an assessment by eye, for example by looking at features in the seismic data (or, preferably, in the comparison of the seismic data) and deciding whether the difference may be consistent with gas cap expansion and/or gas coming out of solution. Any such assessment may be validated (e.g. confirmed or contradicted) by making a model (e.g. a computer model) of fluid changes and/or movement in a layered or structural subsurface in order to make synthetic (simulated) seismic data that resembles the observed changes.

Changes in the seismic data may correspond to an amplitude change (e.g. determined by subtracting data measured at one time from data measure at another time).

Amplitude changes refer to a change in the seismic amplitude, typically measured at or with respect to a particular point in space.

Changes in the seismic data preferably correspond to a time-corrected or time-aligned difference. For example, monitor seismic data (i.e. seismic data recorded at a later time or date) may be time-aligned with base seismic data, (i.e. seismic data recorded at an earlier time or date) such that corresponding seismic reflection events, i.e. from the same layers in the subsurface, are time-aligned.

Thus, when taking the difference between such time-aligned seismic data, only the amplitude difference remains.

Changes in the seismic data may additionally or alternatively correspond to a time shift (which may also be referred to as a seismic travel time delay or speedup). A time shift refers to a change (e.g. increase) in the seismic travel time taken for a seismic signal or wavefield to be reflected back to a receiver. A time shift is preferably determined from seismic data relating to corresponding seismic reflection events measured at the two or more different times. Specifically, and as is known in this field, a time shift may be determined (indirectly) by comparing seismic events (i.e. seismic data) from the same (corresponding) subsurface reflections, and deducing, e.g. using a known mathematical formula, the corresponding speedup or delay (time shift). The time shift may be determined in this way with a typical accuracy of fractions of milliseconds. The deduced time shift may vary as a function of position, e.g. laterally and/or vertically. Such calculated time shifts may in turn be converted into estimates of location and quantity of velocity variations in the layers of the subsurface, which may in turn be compared with models, from which comparison(s) conclusions may be drawn on the presence and state of any potential hydrocarbons.

Thus, the method preferably comprises determining whether there are any changes in the seismic data which may be indicative of the presence of hydrocarbons, e.g. new or previously unknown sources of hydrocarbons as discussed above. Changes in the seismic data which are indicative of the presence of hydrocarbons may comprise changes which are indicative of gas coming out of solution (from an oil phase) and/or gas cap expansion.

Determining a time shift (e.g. as a function of position) between the seismic data measured at two or more different times may be particularly useful in making an assessment about whether a likely source of hydrocarbons is oil or gas. For example, assessing whether the hydrocarbons are likely to be oil or gas may be based at least partly (or possibly wholly) on a determined time shift.

Preferably, if a determined time shift (e.g. at a location or sub-region of the region) is greater than a predetermined value, it is assessed that the hydrocarbons (at that location or sub-region of the region) are likely to be oil. This is because the presence of a significant time shift indicates the likely situation of gas coming out of solution.

Preferably, if the determined time shift (e.g. at a location or sub-region of the region) is less than a predetermined value (threshold), it is assessed that the hydrocarbons (at that location or sub-region of the region) are likely to be gas (or that an oil column, if present, only has a thin thickness, e.g. less than 20 m). This is because the presence of an insignificant time shift indicates the likely situation of gas cap expansion, or the presence of only a thin oil column.

The predetermined value (threshold) of the time shift is preferably greater than the noise in the seismic data.

The predetermined value of the time shift may be around 0.5 to 3 ms, or more preferably around 0.5 to 1.5 ms, for example. Thus, if the determined time shift is greater than around 0.5 to 1.5 ms, it may be assessed that the hydrocarbons are likely to be oil (or more likely to be oil than gas). On the other hand, if the determined time shift is less than around 0.5 to 1.5 ms, it may be assessed that the hydrocarbons are likely to be gas (or more likely to be gas than oil). These values follow from fluid substitution using the well-known Gassmann equation, under the assumption that the combined fluid stiffness is given by the Reuss average. For gas cap expansion, an assumption is made that for a pressure depletion of 10-20 bars, the gas cap will typically expand by not more than 5-10 m, for which the mentioned fluid substitution predicts time shifts of less than 0.5 to 1 ms. For gas out of solution in oil, the depletion of 10-20 bars, and for oil columns larger than e.g. 20 m, the fluid substitution will result in time shifts typically larger than 0.5 to 1 ms. As such, the threshold values of the time shift specified above may be used in the method as described to assess whether the hydrocarbons are likely to be oil or gas.

In a preferred embodiment, the predetermined value (threshold) of the time shift is around 1 ms.

The predetermined value (threshold) of the time shift that is used may vary from case to case depending, for example, on reservoir properties. For example, if it is known or suspected that there may be gas cap expansion in a region, this may be used to determine what predetermined value (threshold) of the time shift should be used.

Utilising time shifts in this way may enable the discrimination between oil and gas accumulations. The inventors have found that four-dimensional modelling shows that the change in elastic properties of rocks can be similar for gas cap expansion and gas out of solution in oil, due to the nonlinear behaviour of the fluid stiffness for small changes in gas saturation when changing from zero gas saturation, under the assumption that the combined fluid stiffness is given by the Reuss average. This might therefore induce similar four-dimensional amplitude changes for gas and oil accumulations. However, as pressure propagates more easily than fluids, the thickness of the affected area can be expected to be larger for a case with gas out solution, which could manifest itself as larger time shifts, since time shifts are cumulative in depth.

It is noted that gas out solution in residual oil (e.g. 20% oil volume saturation), and gas out of solution directly from a saturated water column might both occur when there is a regional pressure drop. Under the assumption that the combined fluid stiffness is given by the Reuss average, the effect of various depletion scenarios on the stiffness have been modelled by the inventors, who found that whilst gas directly out of solution from the water seems unlikely (at pressure depletions of less than around 50 bar) to produce an noticeable effect in seismic data measured at two different times, gas out of solution from residual oil in the water showed changes in elastic properties of a comparable magnitude to gas out of solution in the oil, albeit lower. This indicates that under the provided assumptions, gas out of solution in residual oil could not be confidently excluded as a potential result.

Comparing the seismic data measured at two or more different times preferably further comprises determining an amplitude change (e.g. as a function of position) between the seismic data measured at two or more different times. Assessing whether there is likely to be hydrocarbons in the region is preferably based, at least partly, on the determined amplitude change. For example, if the determined amplitude change (e.g. at a location or sub-region of the region) is larger than a predetermined value (threshold), it may be determined that there are likely to be hydrocarbons (at that location or sub-region of the region) in the region. The predetermined value (threshold) of the amplitude change may be around 10- 20%, e.g. 15%.

As described above, the seismic data for the region corresponding to two or more different times may comprise at least a first seismic data set corresponding to a first time and a second seismic data set corresponding to a second time. Comparing the seismic data measured at two or more different times preferably comprises subtracting (at least some of) the data of the first seismic data set from (at least some of) the (corresponding) data of the second seismic data set to determine a difference between the data of the first and second seismic data sets.

For example, as described above, an amplitude difference and/or a time shift between the first seismic data set and the second seismic data set may be determined.

Preferably, the seismic data for the region corresponding to two or more different times is compared as a function of position, e.g. in two or three- dimensions.

In a preferred embodiment, the method involves: determining amplitude changes and time shifts in seismic data for a region corresponding to two or more different times, preferably as a function of position; assessing, based on the amplitude changes, whether there are likely to be hydrocarbons in the region (e.g. as a function of position); and, if it is assessed that there are likely to be hydrocarbons in the region, assessing, based on the time shifts, whether they are likely to be oil or gas.

The method may comprise graphically displaying a result or results of comparing the seismic data measured at two or more different times. For example, an amplitude change between the seismic data measured at two or more different times may be displayed graphically, e.g. as a function of position. A time shift between the seismic data measured at two or more different times may alternatively or additionally be displayed graphically, e.g. as a function of position. In general, a change or difference in the seismic data corresponding to two or more different times may be displayed on a graph whose axes correspond to a vertical and a horizontal direction. Graphically displaying a result or results of comparing the seismic data measured at two or more different times can allow the existence of any significant difference(s) to be identified more easily and e.g. noted or recorded.

The method may further comprising graphically displaying (e.g. as a function of position): a result of the assessment of whether there is likely to be hydrocarbons in the region; and/or a result of the assessment of whether the hydrocarbons are likely to be oil or gas. Such a display may be useful for future decision making, for example.

If it is assessed that there is likely to be hydrocarbons in the region, the method may comprise making a decision about whether to explore (e.g. physically explore, for example with one or more drills or drilling means) for the likely hydrocarbons. Such a decision may depend on a number of factors such as whether there is any existing infrastructure (and, if so, its state), and/or the possible amount of hydrocarbons that may be present.

Making a decision about whether to (e.g. physically) explore for the likely hydrocarbons may also be based on the assessment of whether the hydrocarbons are likely to be oil or gas.

Thus, the method may further comprise exploring (e.g. by drilling) for the likely hydrocarbons.

The method may comprise, prior to comparing the seismic data measured at two or more different times, deciding whether a region is a candidate for further analysis. This means that the further analysis may only be performed in cases (for regions) where there is suitable seismic data available and/or a likelihood of being able to observe an effect such as gas cap expansion and/or gas coming out of solution, should there be hydrocarbons in that region. This can help to avoid analyses being performed which are unlikely to be successful or helpful.

Deciding whether a region is a candidate for further analysis may comprise checking whether there is suitable seismic data on which the further analysis can be performed and/or checking whether the analysis would be likely to be able to identify a change or relevant effect such as gas cap expansion and/or gas coming out of solution.

For example, deciding whether a region is a candidate for further analysis may comprise:

(i) checking whether there is seismic data recorded at two or more different times for the region;

(ii) checking whether there is a sufficient amount of time (e.g. at least 1 , 2, 3, 4 or 5 years) between the two or more different times;

(iii) checking whether the seismic data recorded at two or more different times is comparable, or may be preconditioned or transformed such that it is comparable;

(iv) checking whether an estimated initial pressure of the region is sufficiently close to an estimated bubble point pressure;

(v) checking whether there is a sufficient pressure depletion in the region; and/or

(vi) checking whether a gas cap may be present in the region.

Checks (i)-(iii) above relate to checking whether there is suitable seismic data available for the analysis to be performed on.

Checking whether the seismic data recorded at two or more different times is comparable may comprise checking whether the seismic data are measured in the same or a sufficiently similar way, e.g. as described above. Alternatively or additionally, this step may comprise checking whether it is possible to precondition (e.g. as described above) at least some of the seismic data (e.g. corresponding to one time) such that it can be compared to other seismic data (e.g. corresponding to another time). As such, the data as measured need not necessarily be comparable (although this is preferred), provided that the data (or some of the data) can be preconditioned or transformed such that it can be compared, e.g. in order to calculate time shifts preferably to the accuracy of the predetermined value (threshold) as described above. Checks (iv)-(vi) relate to checking whether or not it would likely be possible to see a relevant effect such as gas cap expansion and/or gas coming out of solution.

For example, it may be required that the initial pressure of the region must be close enough to a bubble point (an estimated bubble point pressure) that a pressure drop which occurs in the region is sufficient to move the pressure of the region to below the bubble point, e.g. such that an effect of gas coming out of solution may be observed/occur. Throughout this text, references to a “bubble point” refer to a bubble point in oil.

The initial pressure of the region may be an initial pore pressure of the hydrocarbon fluid(s) in the region, which may be obtained from data from nearby wells, where this is estimated while/after drilling.

The estimated bubble point pressure may be determined from laboratory measurements on hydrocarbon fluid samples obtained in nearby wells.

Alternatively or additionally, it may be required that the pressure drop is sufficiently large such that a gas cap expansion may be observed (e.g. a gas cap expansion is sufficiently large that it may be observed, e.g. on a graph).

In some cases, a pressure drop of between 5 and 15 bars may be sufficient to observe an effect such as gas coming out of solution, or gas cap expansion, or, in some cases, a larger pressure drop may be required.

The method may further comprise assigning to a region an indicator indicating how good a candidate for further analysis the region is. This could be a colour or number indicator, for example. The indicator could be based for example, on one or more (and preferably all) of checks (iv)-(vi) above, for example.

The method may then further comprise displaying the indicator graphically, e.g. on a map. This can allow possible regions for further analysis to be viewed graphically and it may then be easier to make a decision about which region(s) to analyse.

The above method is preferably, at least partially, performed on a computer or computer system.

A further aspect relates to a computer program product comprising computer readable instructions that, when run on a computer, is configured to cause one or more processers to perform the method described herein (optionally with any of its optional or preferred features). A further aspect relates to a system for exploring for hydrocarbons, the system comprising one or more software elements arranged to perform the method described herein (optionally with any of its optional or preferred features).

A system may comprise one or more memories and one or more processors configured to perform the method(s) as described above. The one or more memories may store data used as an input to the method (e.g. seismic data) and/or data output from the method. The one or more processors may be programmed with software (e.g. computer program(s)) which causes them to perform the method of the present invention. The system may comprise one or more screens and/or data input means, e.g. for a user to control the performing of the method and/or view an output of the method on a screen.

For greater speed and efficiency, the method, or at least part of the method, is preferably performed on, or implemented by, a computer.

The methods in accordance with the present invention may be implemented at least partially using software e.g. computer programs. It will thus be seen that when viewed from further aspects, the present invention provides computer software specifically adapted to carry out the methods herein described when installed on data processing means (e.g. one or more processors), a computer program element comprising computer software code portions for performing the methods herein described when the program element is run on data processing means, and a computer program comprising code means adapted to perform all the steps of a method or of the methods herein described when the program is run on a data processing system. The data processor may be a microprocessor system, a programmable FPGA (field programmable gate array), etc.

The invention also extends to a computer software carrier comprising such software which when used to operate a processor or microprocessor system comprising data processing means causes in conjunction with said data processing means said processor or system to carry out the steps (or one or more of the steps) of the methods of the present invention. Such a computer software carrier could be a physical storage medium such as a ROM chip, RAM, flash memory, CD ROM or disk, or could be a signal such as an electronic signal over wires, an optical signal or a radio signal such as to a satellite or the like.

It will be appreciated that in some embodiments, not all steps of the methods of the invention need be carried out by computer software and thus from a further broad aspect the present invention provides computer software and such software installed on a computer software carrier for carrying out at least one of the steps of the methods set out herein.

The present invention may accordingly suitably be embodied as a computer program product for use with (or within) a computer system. Such an implementation may comprise a series of computer readable instructions fixed on a tangible medium, such as a non-transitory computer readable medium, for example, diskette, CD ROM, ROM, RAM, flash memory or hard disk. It could also comprise a series of computer readable instructions transmittable to a computer system, via a modem or other interface device, either over a tangible medium, including but not limited to optical or analogue communications lines, or intangibly using wireless techniques, including but not limited to microwave, infrared or other transmission techniques. The series of computer readable instructions embodies all or part of the functionality previously described herein.

Those skilled in the art will appreciate that such computer readable instructions can be written in a number of programming languages for use with many computer architectures or operating systems. Further, such instructions may be stored using any memory technology, present or future, including but not limited to, semiconductor, magnetic, or optical, or transmitted using any communications technology, present or future, including but not limited to optical, infrared, or microwave. It is contemplated that such a computer program product may be distributed as a removable medium with accompanying printed or electronic documentation, for example, shrink wrapped software, pre-loaded with a computer system, for example, on a system ROM or fixed disk, or distributed from a server or electronic bulletin board over a network, for example, the Internet or World Wide Web.

Preferred embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings, in which:

Fig. 1 is a flow chart illustrating the key steps of an embodiment of the method;

Fig. 2A is a chart illustrating a simulated gas cap expansion scenario;

Fig. 2B is a chart illustrating amplitude differences in simulated four dimensional seismic data for the scenario of Fig. 2A;

Fig. 2C is a chart illustrating time shifts in simulated four-dimensional seismic data for the scenario of Fig. 2A;

Fig. 3A is a chart illustrating a simulated gas out of oil solution scenario; Fig. 3B is a chart illustrating amplitude differences in simulated four dimensional seismic data for the scenario of Fig. 3A; and

Fig. 3C is a chart illustrating time shifts in simulated four-dimensional seismic data for the scenario of Fig. 3A.

The present invention provides a method of exploring for hydrocarbons by analysing seismic data for a region collected at different times.

Fig. 1 is a flow chart illustrating an embodiment of a method of the present invention. The method comprises five steps 1-5 as shown in the chart.

At step 1 , it is determined whether a particular region is a candidate for further analysis. If it is determined that the region is a candidate, then the further steps of the method are performed. If not, then the method stops at step 1 in such a case.

At step 2, the seismic data set(s) on which the analysis is to be performed is (are) obtained. The data (or some of the data) could be obtained from memory or it could be measured (e.g. if not already present in a memory).

At step 3, seismic data from the seismic data set(s) corresponding to two or more different times is compared and one or more comparison plots of the seismic data is (are) produced.

At step 4, the comparison plot(s) is (are) analysed and it is determined:

(a) whether the plot(s) indicate(s) the possibility of the presence of hydrocarbons (e.g. new or previously unknown sources of hydrocarbons as discussed above); and

(b) if the plot(s) indicate(s) the possibility of the presence of hydrocarbons, whether the hydrocarbons are likely to be oil or gas.

At step 5, based on the outcome of step 4 (and possibly further studies or checks), it is decided whether to physically explore and/or drill for hydrocarbons in the region.

Each of the steps 1-5 will now be described in more detail.

Step 1 involves determining whether a particular region is a candidate for further analysis.

Step 1 involves a number of sub-steps.

First, step 1 involves checking whether there is (suitable) seismic data recorded at two or more different times for the region. The seismic data ideally comprises four-dimensional seismic data spanning a (sufficiently long) time period. Four-dimensional seismic data is typically recorded in the same way over a period of time (or at separate discrete times over a period of time). As such, parts of the four-dimensional seismic data recorded at different times may be compared.

However, in alternative embodiments, the seismic data comprises four dimensional seismic data and three-dimensional seismic data recorded at a different time to the four-dimensional seismic data, or two or more three- dimensional seismic data sets (seismic surveys), i.e. taken at different times. If such seismic data comprising three-dimensional seismic data is found, then it is checked whether the seismic data recorded at different times are comparable, i.e. whether the seismic data recorded at different times are measured in the same or a sufficiently similar way, such that their data can be meaningfully and easily compared. For example, it may be required that source and receiver positions are steered and/or controlled in such a way that the geometrical deviations between e.g. two different seismic acquisitions (surveys) are as small as operationally possible, e.g. to within 10-20 m.

If a region is found which fulfils these criteria (i.e. for which there is seismic data recorded at two or more different times which may be compared), then it is also determined whether there is a sufficient likelihood of there being a signal indicating the presence of hydrocarbons following a further step(s) of the method.

In order to determine this (i.e. whether there is a sufficient likelihood of there being a signal indicating the presence of hydrocarbons), it can be checked whether the initial pressure (or an estimated pressure) of the region at the time (or close to the time) at which the earlier/earliest seismic data was recorded is close to the estimated bubble point pressure in oil.

The initial pressure of the region is an initial pore pressure of the hydrocarbon fluid(s) in the region, which may be obtained from data from nearby wells, where this is estimated while/after drilling.

The estimated bubble point pressure is determined from laboratory measurements on hydrocarbon fluid samples obtained in nearby wells.

The pressure difference (e.g. drop) between the times of the later and earlier seismic data is also determined or estimated (e.g. from sources such as exploration wells, pressures in different, but close fields etc.). The greater the pressure difference or drop, the more likely a signal could be obtained from analysis of the seismic data.

If the difference between the pressure corresponding to the time of the earlier/earliest seismic data and the pressure of bubble point is relatively small, e.g. when compared to the pressure difference (drop) between the times of the later and earlier seismic data, then this would indicate the possibility of gas coming out of solution. If the possibility of gas coming out of solution is indicated, then this would suggest that it would be worthwhile performing the analysis of the seismic data sets of the region.

The pressures referred to above can be obtained or estimated from exploration (e.g. from prospect information), Petec (Petroleum Technology) or production history and well logs, for example.

As an alternative, or in addition to checking whether the pressure of a region is close to its bubble point, it can be checked whether there is a gas cap present, e.g. by looking at or analysing the initial seismic data. If such a gas cap is present, then a reduction in pressure would result in an increase in the size of the gas cap, and this could indicate the presence of hydrocarbons.

Thus, a region may be indicated as being a candidate for further analysis if it has a pressure (e.g. a pressure at the time of the earlier/earliest seismic data) close to its bubble point (e.g. sufficiently close that the effect of gas coming out of solution may occur given the pressure drop), an initial gas cap, or both.

In order to illustrate how it may be decided whether a region is a candidate for further analysis, three examples are presented below. In these examples, _mtis the estimated initial pressure of the hydrocarbons in the region, P_{bubbie point} is the estimated bubble point pressure, and the pressure depletion is the difference in the estimated pressure of the region between the earliest and latest (or earlier and later) data sets.

Example 1 :

(i) Pinit ^— Pbubble point ⁼ 5 bar

(ii) Pressure depletion = 10 bar

(iii) No gas cap present

In this example, although there is no gas cap present and the pressure depletion is not that high, the initial pressure is relatively close to the bubble point pressure so the region is indicated as being a (good) candidate for further analysis. Example 2:

(ί) Pinit ^— Pbubble point ⁼ 50 bar

(ii) Pressure depletion = 10 bar (iii) No gas cap present

In this example, the initial pressure is not that close to the bubble point pressure, the pressure depletion is not that high and there is no gas cap present. As such, this region is not indicated as being a candidate for further analysis. Example 3:

(i) Pinit ^— Pbubble point ⁼ 50 bar

(ii) Pressure depletion = 3 bar

(iii) Gas cap present

In this example, the initial pressure is not that close to the bubble point pressure and the pressure depletion is not that high but there is a gas cap present. As such, this region is indicated as being a (possible) candidate for further analysis.

In one embodiment, regions are assigned an indicator such as a colour- code (e.g. green for good candidates, yellow for possible candidates and red for not being a candidate) to indicate whether they are a candidate further analysis. The colour-coded or otherwise indicated regions may be displayed on a map for ease of reference.

If a region is indicated as being a candidate for further analysis, as determined at step 1 described above, then, at step 2, the seismic data set(s) on which the analysis is to be performed is (are) obtained.

The seismic data set(s) (or some of the data set(s)) could be obtained from memory or it could be measured (e.g. if new or newer seismic data is required).

As described above, the seismic data ideally comprises four-dimensional seismic data spanning a (sufficiently long) time period. However, in alternative embodiments, the seismic data comprises four dimensional seismic data and three-dimensional seismic data recorded at a different time to the four-dimensional seismic data, or two or more three- dimensional seismic data sets (seismic surveys), i.e. taken at different times.

For example, the seismic data sets could be two (or more) separate three- dimensional seismic data sets. Such sets could all be obtained from memory (i.e. be previously recorded data) or the latest data set could be measured, e.g. for the method of the present invention to be performed.

The seismic data sets could comprise seismic data measured from any known or standard method, for example. In some cases, the seismic data could be recorded with air guns.

In some embodiments where one or more three-dimensional seismic data sets are used, such data sets are preconditioned before they are analysed. Such preconditioning can help to ensure that the data sets being used are comparable with each other or other (e.g. four-dimensional) data sets. Preconditioning can entail equalising one or more variables such as amplitude levels and/or a spectral bandwidth of the seismic data set(s).

After the seismic data corresponding to two or more different times has been obtained, at step 3, the seismic data corresponding to two or more different times is compared by determining the change(s) or difference(s) between the later and earlier seismic data, e.g. by subtracting the later seismic data from the earlier seismic data in relation to one or more attributes, or vice versa, and a comparison plot(s) of the seismic data (i.e. showing this (these) difference(s)) is (are) produced.

Two attributes of seismic data are seismic amplitude and seismic travel time.

The seismic data corresponding to two or more different times is compared in two ways:

(i) by determining the difference between the amplitude of the later and earlier seismic data;

(ii) by determining the difference between the seismic travel time of the later and earlier seismic data (the “time shift”).

Comparison plots showing these different are created for each of these attributes of the seismic data (amplitude and time). Such plots are illustrated, for two different simulated scenarios, in Figs. 2B, 2C, 3B and 3C, which are described below.

Fig. 2A is a chart illustrating a simulated gas cap expansion scenario. This chart (as in all of the charts in Figs. 2A-3C) has depth on the vertical axis and horizontal position on the horizontal axis. Different components are indicated by different regions on the chart. Region 1 is reservoir rock filled with gas, region 2 is reservoir rock filled with oil, and region 3 is reservoir rock filled with water. The remaining areas of the chart are the various rocks above and below the reservoir rock. As indicated by the four arrows pointing downwards in Fig. 2A, this chart illustrates a “gas cap expansion” scenario, in which the region of gas 1 (or the “gas cap”) expands. In this case, the gas cap expands downwards by 5 m due to a change (decrease) in pressure in the region in which it is located.

Seismic data for this scenario is simulated at times before and after the 5 m gas cap expansion.

The amplitude difference in the seismic data between these two times is depicted in Fig. 2B as a function of vertical (depth) and horizontal position. As indicated at the side of the chart, positive amplitude differences (i.e. increases, so- called “hardening”, related to the increased total stiffness of the saturated rock) are indicated with black or darker tones, and negative amplitude differences (i.e. decreases, so-called “softening”, related to the decreased total stiffness of the saturated rock) are indicated with white or lighter tones.

The time shift in the seismic data between these two times is depicted in Fig. 2C as a function of vertical (depth) and horizontal position. As indicated at the side of the chart, a speeding up (i.e. a decrease in seismic travel time) is indicated with white or lighter tones, and a slowing down (i.e. an increase in seismic travel time) is indicated with black or darker tones.

Fig. 3A is a chart illustrating a simulated gas out of solution scenario. As with Fig. 2A, different components are indicated by different regions on the chart. Region 11 is reservoir rock filled with gas, region 12 is reservoir rock filled with oil, and region 13 is reservoir rock filled with water. The remaining areas of the chart are the various rocks above and below the reservoir rock. In this scenario, the oil region 12 is an oil column with a thickness of 20 m. Gas is dissolved in the oil in region 12. During the simulation of this scenario, due to a regional decrease in pressure, 10% of the gas dissolved in the oil in region 12 comes out of solution.

Seismic data for this scenario is simulated at times (different dates) before and after the pressure drop causing the gas to come out of solution.

The amplitude difference in the seismic data between these two times is depicted in Fig. 3B as a function of vertical (depth) and horizontal position. As indicated at the side of the chart, positive amplitude differences (i.e. increases) are indicated with black or darker tones, and negative amplitude differences (i.e. decreases) are indicated with white or lighter tones

The time shift in the seismic data between these two times is depicted in Fig. 3C as a function of vertical (depth) and horizontal position. As indicated at the side of the chart, a speeding up (i.e. a decrease in seismic travel time) is indicated with white or lighter tones, and a slowing down (i.e. an increase in seismic travel time) is indicated with black or darker tones.

Next, at step 4, the comparison plots (e.g. as illustrated in Figs. 2B and 2C, or 3B and 3C) are analysed, e.g. by eye and/or numerically, and it is determined:

(b) if the plot(s) do (does) indicate(s) the possibility of the presence of hydrocarbons, whether the hydrocarbons are likely to be oil or gas.

In the gas cap expansion scenario, there is a noticeable amplitude difference (as shown in Fig. 2B) but there is only a small or negligible time shift (as shown in Fig. 2C).

In the gas out of solution scenario, there is a smaller amplitude difference (as shown in Fig. 3B) and there is a fairly large time shift (as shown in Fig. 3C).

In other words, an amplitude difference may indicate the presence of hydrocarbons (oil or gas). However, if this amplitude difference is accompanied by no or negligible time shift, then this is more likely caused by gas cap expansion (i.e. a situation with an accumulation of hydrocarbon gas). On the other hand, if this amplitude difference is accompanied by a noticeable or large time shift, then this is more likely caused by a gas out of solution scenario (i.e. a situation with an accumulation of oil).

Thus, by looking at changes in seismic travel time, or time shifts, this can facilitate the discrimination between a gas cap expansion scenario (a situation with an accumulation of hydrocarbon gas), and a gas out of solution in oil scenario (a situation with an accumulation of oil).

As such, step 5 comprises checking whether there is a significant difference in amplitude (e.g. a 25% relative change in the waveform peak of an event) and, if there is a significant difference in amplitude, checking whether there is a significant time shift.

If there is a significant difference (e.g. a 25% relative change) in amplitude but an insignificant time shift then it is determined that this is likely caused by gas cap expansion or that there is only a thin oil column (e.g. less than around 20 m).

If there is a significant difference or a slightly less significant difference (e.g. a 15% relative change) in amplitude and a significant time shift then it is determined that this is likely caused by gas coming out of solution (in the case of a sufficiently thick oil column, e.g. around 20-50 m or greater).

A significant time shift could be a time shift of greater than around 1.5 ms, for example. An insignificant time shift could be less than around 0.5 or 1.5 ms, for example. The noise in seismic data time measurements is typically around 0.5 - 1 ms.

Finally, at step 5, based at least partially on the outcome of step 4, it is decided whether to physically explore (e.g. by or involving drilling) for hydrocarbons in the region. This may, for example, be based on other factors as well as the outcome of step 4, such as the presence or lack of any existing infrastructure, and the size of the region concerned.

Physically exploring for hydrocarbons may then take place, based (depending) on the outcome of step 5.

Alternatively or additionally, before performing step 5, any observed effect (e.g. suggesting the presence of gas coming out of solution in oil or gas cap expansion) is ideally studied and it would be attempted to formulate a hypothesis as to why such an effect (e.g. as observed in a difference plot or a time shift plot) is observed. Based on that, an assessment of whether the observed effect is a likely hydrocarbon indicator may be performed.

Claims

1. A method of exploring for hydrocarbons in a region, the method comprising: obtaining seismic data for the region, the seismic data comprising seismic data measured at two or more different times; comparing the seismic data measured at two or more different times, wherein comparing the seismic data measured at two or more different times comprises determining a time shift between the seismic data measured at two or more different times; assessing, based on the comparison of the seismic data measured at two or more different times, whether there is likely to be hydrocarbons in the region; and if it is assessed that there is likely to be hydrocarbons in the region, assessing whether the hydrocarbons are likely to be oil or gas.

2. A method as claimed in claim 1 , wherein assessing whether the hydrocarbons are likely to be oil or gas is based at least partly on the determined time shift.

3. A method as claimed in claim 2, wherein: if the determined time shift is greater than a predetermined value, it is assessed that the hydrocarbons are likely to be oil; and/or if the determined time shift is less than a predetermined value, it is assessed that the hydrocarbons are likely to be gas.

4. A method as claimed in claim 3, wherein the predetermined value of the time shift is around 0.5 to 1.5 ms.

5. A method as claimed in any preceding claim, wherein comparing the seismic data measured at two or more different times further comprises determining an amplitude change between the seismic data measured at two or more different times, and assessing whether there is likely to be hydrocarbons in the region is based at least partly on the determined amplitude change.

6. A method as claimed in claim 5, wherein if the determined amplitude change is larger than a predetermined value, it is determined that there is likely to be hydrocarbons in the region.

7. A method as claimed in any preceding claim, wherein the seismic data for the region corresponding to two or more different times comprises four dimensional seismic data.

8. A method as claimed in any preceding claim, wherein the seismic data for the region corresponding to two or more different times comprises at least a first seismic data set corresponding to a first time and a second seismic data set corresponding to a second time.

9. A method as claimed in any preceding claim, wherein the seismic data for the region corresponding to two or more different times are measured in a sufficiently similar way such that the seismic data for the region corresponding to two or more different times can be compared.

10. A method as claimed in any preceding claim, wherein the seismic data for the region corresponding to two or more different times comprises at least a first seismic data set corresponding to a first time and a second seismic data set corresponding to a second time, and wherein comparing the seismic data measured at two or more different times comprises subtracting data of the first seismic data set from data of the second seismic data set or subtracting data of the second seismic data set from data of the first seismic data set to determine a difference between the data of the first and second seismic data sets.

11. A method as claimed in any preceding claim, further comprising graphically displaying a result or results of comparing the seismic data measured at two or more different times.

12. A method as claimed in any preceding claim, further comprising graphically displaying: a result of the assessment of whether there is likely to be hydrocarbons in the region; and/or a result of the assessment of whether the hydrocarbons are likely to be oil or gas.

13. A method as claimed in any preceding claim, further comprising, if it is assessed that there is likely to be hydrocarbons in the region, making a decision about whether to explore for the likely hydrocarbons.

14. A method as claimed in claim 13, wherein making a decision about whether to explore for the likely hydrocarbons is also based on the assessment of whether the hydrocarbons are likely to be oil or gas.

15. A method as claimed in claim 13 or 14, further comprising exploring for the likely hydrocarbons.

16. A method as claimed in any preceding claim, further comprising, prior to comparing the seismic data measured at two or more different times, deciding whether a region is a candidate for further analysis.

17. A method as claimed in claim 16, wherein deciding whether a region is a candidate for further analysis comprises:

(ii) checking whether there is a sufficient amount of time between the two or more different times;

(vi) checking whether a gas cap may be present in the region.

18. A computer program product comprising computer readable instructions that, when run on a computer, is configured to cause one or more processers to perform the method of any preceding claim.

19. A system for exploring for hydrocarbons, the system comprising one or more software elements arranged to perform the method of any of claims 1 to 18.