Pore pressure measurement in low-permeability and impermeable materials

Abstract

A method for determining pore pressure in a porous formation having unconnected pore spaces, the method comprising: Processing a first signal as a function of pore pressure at a first position in the formation where the pore spaces are not substantially connected to each other; Processing a second signal as a function of pore pressure at a second position in the formation where the pore spaces are substantially interconnected; Inducing a known change in pressure at the second position; Processing a third signal as a function of the pore pressure at the second position under the induced pressure change; and Determining a pore pressure associated with the first position based at least in part on a comparison including the first, second, and third processed signals and the known pressure change.

Description

background

[0001] One of the most significant issues in the investigation of shale gas (SG) formations is the in-situ gas pressure. This parameter is proportional to the amount of gas that can be extracted from the formation and thus has important economic implications. Conventional methods, such as withdrawing fluid at known pressure differentials using a sampling tool, are not effective in cases where permeability is too low, such as in shale gas and other formations where the pores are generally not interconnected. Currently, no method is available to perform this measurement either in the wellbore or in the laboratory. Brief description

[0002] This Summary is intended to introduce a selection of the concepts that are explained in more detail below in the Detailed Description. This Summary is neither intended to identify key features or essential features of the claimed subject matter nor should it be understood to limit the scope of the claimed subject matter.

[0003] According to some embodiments, a method is described for determining pore pressure in a porous formation, such as shale gas or trapped gas with substantially unconnected pore spaces. The method includes: processing a first signal as a function of pore pressure at a first location in the formation where the pore spaces are not substantially connected; processing a second signal as a function of pore pressure at a second location in the formation where the pore spaces are substantially connected; inducing a known change in pressure (e.g., by injecting fluids) at the second location while processing a third signal as a function of pore pressure; and determining the pore pressure associated with the first location based on a comparison including the first, second, and third measured signals and the known pressure change.

[0004] According to some embodiments, a nuclear magnetic resonance device is used to measure the signals, from which the gas peak intensity can be calculated and compared to facilitate the calculation of the gas pressure at the first location. According to some embodiments, the signal measurements are performed using a downhole tool, such as an NMR logging tool, nuclear logging tool, or sonic logging tool, deployed in a borehole. The downhole tool may in such cases be deployed using, for example, a wireline or a drill string. In a borehole, the second location may be artificially disturbed, such as by drilling activity, to form a plurality of microcracks connecting the pore spaces.

[0005] According to some embodiments, when using a downhole tool, the tool may be of a type that allows for multiple exploration depths while positioned at a single position in the borehole. The measurement at the second (disturbed) position may, in such cases, be taken at shallower depths that exhibit drilling-induced microfractures, and the first (undisturbed) position may be at greater depths that do not exhibit such fractures. According to other embodiments, the tool uses a single exploration depth and is moved to multiple positions (depths) within the borehole to obtain the measurements used for the pore pressure calculation.

[0006] The induced pressure change and measurement are used, according to some embodiments, to derive a relationship between pore pressure and the measured signal, which is then used as a calibration curve to determine the pore pressure. According to some other embodiments, the pressure is increased to obtain a matching or equivalent value based on the measurements.

[0007] According to some embodiments, a system for determining pore pressure in a porous formation, such as shale gas or trapped gas with substantially unconnected pore spaces, is described.The system includes a downhole logging tool, such as an NMR tool, a nuclear tool, or a sonic tool, configured to measure pore pressure dependent signals at locations in the formation including a first location that is undisturbed and has substantially unconnected pore spaces, and a second location that is disturbed and has a plurality of fractures interconnecting at least some of the pore spaces; a pressure induction means, such as a gas injection system, configured to induce a known pressure change at the second location; and a processing system programmed and configured to calculate a pore pressure associated with the first location based at least in part on a comparison of values ​​derived from processing at the first and second locations and the known induced pressure change.

[0008] According to some embodiments, a method for determining pore pressure within a porous material having substantially unconnected pore spaces is described.The method includes: processing a first signal as a function of pore pressure in an undisturbed portion of the porous material where the pore spaces are predominantly unconnected; processing a second signal as a function of pore pressure in a disturbed portion of the porous material where a plurality of fractures interconnect at least some of the pore spaces; inducing a known change in pressure in the disturbed portion of the porous material; processing a third signal as a function of pore pressure in the disturbed portion of the material while under the induced pressure change; and determining a pore pressure associated with undisturbed porous material based at least in part on a comparison including the first, second, and third measured signals and the known pressure change.The method, according to some embodiments, is performed in one or more surface facilities, and the porous material is a core sample of a subterranean formation that has been brought to the surface.

[0009] An example of a porous formation having substantially unconnected pore spaces is, according to some embodiments, a formation material having a permeability below 0.1 millidarcy. Short description of the drawings

[0010] The present disclosure will be further understood from the following detailed description with reference to the several drawings by way of non-limiting examples of embodiments of the present disclosure, in which like reference numerals represent like parts throughout the several views of the drawings, and wherein: Fig. 1 is a flow diagram illustrating aspects of using NMR properties of a shale gas formation to determine gas pressure, according to some embodiments; Fig. 2A and Fig. 2B illustrates an NMR tool with multiple exploration downhole shrouds used in a wellbore to determine gas pressure in a shale gas formation according to some embodiments; Fig. 3 is a graphical representation showing amplitude versus T2 or T1 plots for a shallow sheath and a deep sheath according to some embodiments; Fig. 4 is a plot showing an example of a derived calibration curve relating gas peak intensity to gas pressure, according to some embodiments; Fig. 5 is a graphical representation showing plots of gas peak intensity versus exploration depth according to some embodiments; Fig. 6 shows an implementation of an injection-metering approach for delivering gas to a downhole location according to some embodiments; Fig. 7 is a flow diagram illustrating aspects of deriving the connate gas pressure of the subterranean formation material from a sample of the formation brought to the surface, according to some embodiments; Fig. Figure 8 is a diagram showing the use of 2D plots to separate the NMR peak into its components; Fig. 9 shows a system for determining gas pressure in a low permeability subterranean formation, such as shale gas, according to some embodiments; Fig. 10 is a flow diagram illustrating aspects of a method for determining gas pressure in low permeability subterranean formations, such as shale gas, according to some embodiments. Detailed description

[0011] The specifics shown herein are exemplary and illustrative only of embodiments of the present disclosure and are presented only to provide what is believed to be the most useful and understandable description of the principles and conceptual aspects of the invention. In this regard, no attempt is made to show structural details of the present disclosure in more detail than necessary for a basic understanding of the present disclosure, but the description, taken in conjunction with the drawings, will show those skilled in the art how the various forms of the invention may be practiced. Further, like reference numerals and designations in the various drawings indicate like elements.

[0012] Fig. 1 is a flowchart illustrating aspects of using NMR properties of a shale gas formation to determine gas pressure, according to some embodiments. In block 110, an NMR tool is positioned in a wellbore within a shale gas formation. The NMR tool, according to some embodiments, is of a type that provides multiple exploration depths from a single tool position in the wellbore. For example, according to some embodiments, a multi-frequency NMR tool such as the Schlumberger MR scanner is used to provide multiple exploration depths. In block 112, the NMR tool is used to take measurements of the gas peak of the shale at a depth and position that has not been disturbed by the drilling process. According to various embodiments, any combination of T2, T1, or diffusion may be used, as these depend on gas pressure.The dependence of the gas peak intensity on the gas pressure is usually not yet known, and the pressure therefore cannot yet be estimated. In block 114, according to some embodiments, the same NMR measurement used in block 112 is performed at shallower depths of investigation (DOI), where some of the gas has escaped, for example, as a result of the drilling process. The disturbance due to drilling can, for example, be induced microcracks. In the shallower DOI, where the formation has been disturbed, the gas pressure will normally be reduced, resulting in lower gas peak intensity in the NMR measurement. In block 116, gas is then induced into the formation at a known pressure(s), and the NMR measurement is repeated. The gas peak in shale samples exhibiting microcracks will increase as a function of the gas pressure.Since both the gas pressure and the gas peak intensity in the shallower DOI mantle(s) are known, a calibration curve can be developed and used to estimate the connate gas pressure in the shale formation, as shown in block 118.

[0013] In shales, the relaxation time (T1 or T2) is short compared to conventional formations. This is due to the following reasons: (1) Porosity can be low in shale gas formations (1-15 pu), forcing gas molecules into close contact with the pore wall and relaxing more rapidly; (2) the pore wall contains a larger amount of clay, and clays are known to have a relatively high concentration of paramagnetic ions, which causes T2 to decay more rapidly than in conventional formations (high relaxivity); and (3) in some shales, the hydrocarbon source (kerogen) is embedded in the pores, and some of the gas is trapped inside the kerogen but is in dynamic equilibrium with the gas filling the pores. Kerogen itself has a very short relaxation time, which causes the magnetization of adsorbed or trapped gas to decay rapidly.

[0014] Although the gas relaxation time in shale gas formations is shorter than normal, it is still a measurable amount using NMR logging tools. The gas peak can also be separated from the bound water peak. Although separating the gas and water peaks is not required for the successful implementation of many of the embodiments described here, a measurable signal according to NMR logging tools is still desirable, as it eliminates the need for NMR tools with shorter interecho times (TE).

[0015] The T2 peak for gas is not typically used to estimate gas pressure because the drilling process tends to create microcracks in the shale layer adjacent to the borehole wall, allowing some gas to escape. Furthermore, there is no calibration curve relating the gas peak to gas pressure. As previously mentioned, the gas peak may overlap with the water peak, for example, and in some embodiments described herein, it is desirable to avoid separating these peaks.

[0016] According to some embodiments, an NMR logging tool with at least two depths of investigation (DOIs) is used, as in Fig. 1. The deeper DOI can be used to sample shale gas that has not yet been disturbed by the drilling process and contains gas at connate pressure. The shallow DOI, on the other hand, can be used to sample shale gas that has been disturbed by the drilling process and has lost at least some of its gas. The methods described herein, according to many embodiments, rely on microcracks formed in the shallow sample to inject gas back into the SG and measure its NMR response.

[0017] Fig. 2A and Fig. 2B show a multi-depth NMR tool used in a wellbore to determine gas pressure in a shale gas formation according to some embodiments. In Fig. 2A, NMR tool 226 is shown deployed in a wellbore 210 penetrating a subterranean shale gas formation 202. The NMR tool 226 is a wireline-delivered tool in this case, although an LWD-delivered tool may be used according to other embodiments. The tool 226 is a Schlumberger MR scanner tool according to some embodiments. For example, the MR scanner tool has a shell 222 with a 4" (10.16 cm) exploration depth ("Shell 4") and another shell 220 with a 1.5" (3.81 cm) exploration depth (Shell 1). The shale gas in the investigation area of ​​shell 220 (Shell 1) lies within a disturbed zone 204 near the borehole wall 212. Zone 204 is expected to be at least partially damaged by the drilling process. The resulting microcracks provide a pathway for the gas to escape from zone 204.However, the shale gas in the study area of ​​jacket 222 (shell 4) lies outside the disturbed zone 204, and no gas loss is expected here because this region is sufficiently distant from the borehole wall 212 and drilling damage, if any, is not significant. As a result, jacket 222 (shell 4) should provide a larger gas peak than jacket 220 (shell 1). Assuming that the gas peak in jacket 220 (shell 1) is significantly affected by the drilling process and jacket 222 (shell 4) is not, the method described here can be used to calculate the gas pressure in the position of jacket 222 (shell 4) that lies outside the disturbed zone 204. It should be noted that although the boundary of the disturbed zone 204 is shown in the . Fig. 2A and Fig. 2B is shown sharply for clarity, in practice the boundary is more irregular and in some areas less well defined. Fig. Figure 2B is a cross-sectional view along line AA' in Fig. 2A of the NMR tool 226 deployed in the borehole 210.

[0018] Fig. 3 is a graphical representation showing amplitude versus T2 or T1 plots for a shallow cladding and a deep cladding according to some embodiments. For example, the shallow and deep cladding plots 410 and 412 may be the results of measurements of claddings 220 and 222, respectively, as shown in FIGS. Fig. 2A and Fig. 2B are shown.

[0019] The gas peak under connate conditions in the deep mantle (such as mantle 222 in the Fig. 2A and Fig. 2B) provides a measurement that can be used to estimate gas pressure. However, the gas peak depends heavily on the formation and structure of the shale, including factors such as the type and concentration of clays, the amount and properties of kerogen, etc., which are generally unknown. As a result, it is difficult to relate gas peak intensity to gas pressure. This is true even when the contribution of other peaks to the gas peak has been removed. The techniques described herein, according to some embodiments, provide a method for generating a calibration curve that relates the gas peak to gas pressure without having to consider the overlapping peaks, type and amount of clays and kerogen.

[0020] The techniques described in accordance with some embodiments utilize the microfractures induced by the drilling process that are the reason why at least a portion of the gas has escaped from the shallow mantle. Gas can be injected into the shale to replace the lost gas from that portion of the shale gas formation that falls within the shallow mantle exploration depth (such as mantle 220 in the Fig. 2A and Fig. 2B). While monitoring the gas peak with the NMR tool, the gas pressure can be varied until the gas peak is drawn from the flat jacket (jacket 220 into the Fig. 2A and Fig. 2B) becomes equal to that from the deeper mantle (mantle 222 in Fig. 2A and Fig. 2B). The pressure of the gas is known in this case and equal to the pressure of the connate shale gas. Although the use of shells 1 and 4 of the Schlumberger MR scanner tool has been described here for demonstration purposes, other logging tools may be used according to other embodiments. It should be noted that the peak intensity for different shells may not have the same sensitivity and may need to be calibrated to eliminate the effect. In particular, once the spectra are reported in porosity units, the effect of different DOIs on the NMR intensity has already been removed. Furthermore, according to some embodiments, one way to compare the peaks is to compare the area under these peaks.

[0021] Fig. 4 is a plot showing an example of a derived calibration curve according to some embodiments relating gas peak intensity to gas pressure. Calibration curve 410 is shown. The gas pressure is incrementally increased according to some embodiments, and the corresponding gas peak is measured. Using this data, a calibration curve can be generated by plotting these parameters. The gas pressure is increased according to such embodiments to a sufficiently high level such that at least one data point has a gas pressure higher than the connate pressure. Calibration curve 410 may be linear, but generally deviates from linearity. The derived calibration curve, as in Fig. 4, has further applications. According to some embodiments, this curve can be used during the production phase, for example, to estimate the gas reserve. Therefore, if a new NMR measurement is performed at any time during the production phase, the gas peak intensity in Fig. 4 can be used to estimate the current gas pressure.

[0022] To determine that the DOIs of the deeper NMR mantle samples were indeed located at positions where the gas was in its connate state, the mantles of the intermediate depths can be advantageously used. Fig. Figure 5 is a graphical representation showing plots of gas peak intensity versus exploration depth according to some embodiments. When gas peak intensity is plotted against the DOI of the mantles, it is expected that smaller peak intensities will be shown at shallower mantles and larger peak intensities at deeper mantles. In the case of Fig. 5, the gas peak intensity is plotted for four depths, 510, 512, 514, and 516. The connate DOI is where this curve approaches an asymptotic constant value. In the Fig. The example shown in Figure 5 clearly shows that the DOI 4 plotted at point 516 is at connate gas pressure. In general, NMR tools with larger DOIs can be used to meet this requirement. If experience shows that, for example, a DOI of 4 inches (10.16 cm) is insufficient, the DOI can be increased by reducing the frequency of the operation, as is well known from the design of NMR logging tools. Any reduction in the signal-to-noise ratio can be compensated for by a site log, where a signal averages the NMR signal over a longer period of time.

[0023] Fig. Figure 6 shows an implementation of an injection-measurement approach for delivering gas to a downhole location according to some embodiments. In this case, two packers 610 and 612 are placed in the wellbore 210 above and below the zone of interest. The packers 610 and 612 allow both the NMR tool 226 and a gas line 620 to be located in the zone of interest. Initially, the NMR tool 226 measures in several casings as a function of depth into the formation 202. The data is used to establish at least one casing with connate gas pressure. Next, gas is injected at a known pressure (e.g., using a pressure gauge 622), and NMR measurements are taken and recorded while maintaining the gas pressure. The process is then repeated at other higher pressures and continues until the casings with shallower DOI yield the same or higher intensities.

[0024] Care should be taken not to apply excessive gas pressure, which could cause new microcracks in the formation. However, after the measurements are completed and a satisfactory gas pressure has been measured according to some embodiments, the gas pressure is further increased sufficiently above the connate gas pressure to induce fracturing of the formation, if desired. The process is carried out in stages according to some embodiments, and an NMR measurement is performed at each step to learn about the behavior of shale gas under high pressures and / or to generate a correlation between such mechanical events and the NMR signal.

[0025] Fig. 7 is a flowchart illustrating aspects of deriving the connate gas pressure of the subterranean formation material from a sample of the formation brought to the surface, according to some embodiments. In block 708, an NMR measurement is taken downhole at a DOI that is considered undisturbed. The gas pressure from this measurement is compared to laboratory measurements. In block 710, a core may be obtained from a borehole or the sidewall and brought to the surface. The core plug may be cut out in block 712 and placed in a high-pressure and temperature container so that it can be pressurized with a desired gas pressure while maintaining the pressure and temperatures downhole in the core plug. The container should be constructed of materials that allow the NMR measurement to be performed while maintaining the high pressure.Materials such as fiberglass or PEEK, or any other suitable non-conductive material, can be used for this purpose. In block 714, an NMR measurement is performed on the core plug with different applied gas pressures, and the gas peak intensity is monitored to determine whether it matches the corresponding intensity found downhole. Alternatively, the gas pressure can be varied in steps, and a calibration curve similar to the one shown in [Figure 714] is generated. Fig. 4. In block 716, the measurements and / or the calibration curve are used to estimate the connate gas pressure. In this approach, the measurement should be performed at the same temperature and pressure as those found downhole. If the laboratory instrument used for NMR measurement is different from the instrument deployed downhole, a sensitivity calibration should also be performed between the two instruments so that the two data sets can be meaningfully compared.

[0026] According to some other embodiments, a combination of T2, T1, and diffusion measurements is used. These parameters can be used in parallel to complement each other. For example, T1 from the shallow cladding and the deep cladding are compared as a function of gas pressure to determine a connate gas pressure. The process is performed in the same way at T2, and the results are compared to provide confidence.

[0027] The techniques described here are particularly useful when some mud filtrate has entered or penetrated the pore space of the shale gas formation. In this case, the contribution of the water peak to the apparent gas peak is uneven between different mantles. The mantle with the shallowest DOI may be more affected. In such cases, separating the apparent gas peak from the water and gas components eliminates the confounding effect of the intruding water and connate water and improves the accuracy of gas pressure prediction. This well-known separation technique, for example, uses two-dimensional plots of D-T2. Fig. Figure 8 is a diagram illustrating the use of 2D plots to separate the apparent gas peak into its components. Diffusion is measured using MMR and plotted on the vertical axis, while T2 is also measured and plotted on the horizontal axis. In the upper part of the diagram, lines 810, 812, and 814 are the normal water line, normal gas line, and normal oil line, respectively, as is well known in the art. Since diffusion data are available, the 2D mappings can be used. The added diffusion axis, in this example, separates the peak intensity into its components, in this case, gas, water, and kerogen. The differences between the diffusion constants of water and gas separate the overlapping peaks, from which individual components can be measured and subtracted from the apparent peak.This known method can also be used to separate the T2 or T1 peaks of gas, kerogen, and water. In the method described in . Fig. In the example shown in Figure 8, the lower part of the plot shows peaks 830, 832, and 834, which are the water, gas, and kerogen peaks, respectively. In cases where this separation process is performed in the shallow mantle, the same process should be performed as in the deep mantle to ensure meaningful comparison of peak intensities as described here. Once the gas contribution to the peak has been separated, its intensity can be directly monitored as a function of gas pressure without any contamination from other fluids in the pore.

[0028] Fig. Figure 9 illustrates a system for determining gas pressure in a low-permeability subterranean formation, such as shale gas, according to some embodiments. At well site 900, there is a wireline truck 920 deploying an NMR tool 226 into well 210 (as shown in more detail in Figures Fig. 2A and Fig. 2B). The tool performs NMR measurements in a shale gas formation 202 that has a disturbed zone 204 (also shown in more detail in the Fig. 2A and Fig. 2B). According to some embodiments, the deployment location of the NMR tool 226 is isolated by packers and a gas line is present (as in Fig. 6), although in Fig. 9, for the sake of simplicity and clarity, the packers and the gas line are not shown. The measurement 910 from the NMR tool 226 at the undisturbed position and at the disturbed position under two or more known pressures is transmitted to a data processing center 950, which may be located on the wireline truck 920 or at another location, local to or remote from the well site 900. The data may alternatively be processed downhole by a microprocessor, which may be provided or located in the NMR tool. The processing unit 950 includes a storage system 942, communication and input / output modules 940, a display 946 for the user, and a user input system 948. The data processing unit 950 is programmed and configured to perform the calculations as described with respect to block 118 in Fig. 1, and thereby results in the connate pore pressure 914.

[0029] In another embodiment of the present disclosure, the disturbed and undisturbed zones may be located at different depths along the length of the wellbore instead of radially into the formation. Fig. 10 is a flowchart illustrating aspects of a method for determining gas pressure in low-permeability subterranean formations, such as shale gas, according to some embodiments. According to these embodiments, the pressure of the shale gas can be determined using NMR tools using a single exploration depth. In block 1010, the NMR tool is positioned in the wellbore within the shale gas formation. In block 1012, NMR measurements are taken at a number of different positions (depths), and in block 1014, the gas peaks are analyzed for positions that are likely to be disturbed (have a less intense gas peak due to gas loss through microfractures) and undisturbed (have a more intense gas peak because the gas is in connate form).If no suitable positions have yet been found, further measurements and gas peak analysis are performed in block 1016 to locate suitable positions. If positions of both disturbed and undisturbed material have been found, then in block 1018, gas with known pressures is injected into the formation at the disturbed position while the gas peak measurements are repeated. In block 1020, the undisturbed pressure is calculated based on the known pressure changes and the gas peak intensities, as described herein (e.g., block 118 of ). Fig. 1). For example, the pressure can be increased until the gas peaks of the perturbed position match those of the undisturbed position, or alternatively, a calibration curve can be developed to estimate the connate gas pressure. It should be noted that if no undisturbed position can be found or conveniently used, according to some embodiments, gas pressure alone or other techniques can be used to induce microcracks.

[0030] It is possible that cases may occur where all of the mantles in an NMR tool exhibit the same gas peak intensity. In this case, it is not immediately obvious whether the mantles are undisturbed at all or whether all of them are disturbed to the same extent. According to some embodiments, the gas peak intensity as a function of the applied gas pressure is used to decide whether a formation is disturbed or not. According to one embodiment already described previously, the DOI of an NMR mantle(s) is increased until the deeper mantles exhibit a constant gas peak intensity. However, if the gas peak intensity does not increase even at deeper DOIs, this may be due either to the fact that even the shallow mantles are undisturbed or that the undisturbed DOI is too deep. These two cases can be explained by the behavior of a calibration curve as in Fig. 4. According to some embodiments, in the case where the formation is undisturbed, microcracks can be induced by applying high gas pressures. While monitoring the gas peak intensity, the gas pressure is increased, and a calibration curve is obtained. If microcracks are not already present, the initial gas pressures have no effect on the gas peak intensity until relatively high gas pressures are present. Fig. Figure 11 is a graphical representation of a calibration curve according to another exemplary embodiment. Calibration curve 1110 is an example showing no dependence on the initial gas pressure and is characteristic of an undisturbed formation. After higher gas pressure has been used to induce microfractures, the gas pressure can be removed, and the above method is used to generate a calibration curve of the Fig. 4 is applied and used to estimate the connate gas pressure.

[0031] In the alternative case where all sheaths have similar gas peak intensities and the calibration curve curve 410 of Fig. 4 instead of curve 1110 of Fig. 11, then all mantles are disturbed and it is necessary to determine an undisturbed gas peak intensity. This can be done, according to some embodiments, by shifting the DOI of the NMR tool until the peak does not change. Alternatively, an attempt can be made to find a higher gas peak intensity by measuring at adjacent depths along the borehole to find a specific depth(s) where the formation is undisturbed and which lie within the DOI of the NMR instrument. Even if these attempts fail, the calibration curve, such as curve 410 of Fig. 4, is still useful because it provides a lower limit to the true gas pressure.

[0032] According to some embodiments, non-NMR measurement types are used or are combined with the techniques described herein to determine pore pressure in low-permeability materials. In general, suitable measurement types are those that are influenced by gas pressure and have exploration depths that are likely to reach at least some undisturbed positions. For example, according to some embodiments, sonic measurements may be used. In these embodiments, the sonic measurement is used in an analogous method to that used in Fig.10 for the NMR tool with a single DOI. In particular, numerous sonic measurements are taken to locate positions for disturbed or undisturbed shale. Injecting gas while taking sonic measurements in a disturbed position, comparing them to an undisturbed position, and calculating pore pressure using either a calibration curve or direct matching are described here. Other examples of suitable measurement techniques and / or tools include: nuclear logging (neutrons and gamma radiation), which is common in oil well logging. The measurements from these two techniques can cross over in a gas zone, and the intensities can be used to quantify gas pressure.

[0033] According to some embodiments, the techniques described herein are applied to materials other than shale gas formations. Pore pressures in other low-permeability formations, such as other shale formations or tight gas formations, can be determined, for example, using the injection / measurement techniques described herein. Although many of the embodiments described herein pertain to gas pressures, the techniques generally work for any pore pressure determination. The techniques described herein can also be readily applied to applications outside the oilfield to measure pore pressure in any material with low or no permeability. According to some embodiments, one such material is foam materials, such as closed-cell rigid foam.

[0034] Although the present disclosure has been described by the above embodiments, those skilled in the art will understand that modifications and variations may be made to the illustrated embodiments without departing from the inventive concepts disclosed herein. Furthermore, although the preferred embodiments have been described in connection with various illustrative structures, those skilled in the art will recognize that the system may be embodied using a variety of specific structures. Accordingly, the present disclosure should not be considered limited except by the scope and spirit of the appended claims.

Claims

[1] A method for determining pore pressure in a porous formation having unconnected pore spaces, the method comprising: Processing a first signal as a function of pore pressure at a first position in the formation where the pore spaces are not substantially connected to each other; Processing a second signal as a function of pore pressure at a second position in the formation where the pore spaces are substantially interconnected; Inducing a known change in pressure at the second position; Processing a third signal as a function of the pore pressure at the second position under the induced pressure change; and Determining a pore pressure associated with the first position based at least in part on a comparison including the first, second, and third processed signals and the known pressure change. [2] The method of claim 1, wherein the porous formation is a shale gas formation. [3] The method of claim 1, wherein the porous formation is a gas-entrained formation. [4] The method of claim 3, wherein the trapped gas formation is a carbonate formation. [5] The method of claim 1, wherein the determined pore pressure is a gas pressure. [6] The method of claim 1, wherein the first, second and third signals are all of the same type. [7] The method of claim 6, wherein the first, second and third signals are based on measurements using a nuclear magnetic resonance tool. [8] The method of claim 1, wherein the induced pressure change is a pressure increase. [9] The method of claim 8, wherein inducing the known pressure change comprises injecting fluids at known pressures. [10] The method of claim 1, wherein the first, second and third signals are based on measurements taken using a downhole tool deployed into a borehole. [11] The method of claim 10, wherein the second position is disturbed to form a plurality of cracks so as to interconnect at least some of the pore spaces. [12] The method of claim 11, wherein the second position is artificially disturbed as a result of a drilling process. [13] The method of claim 10, wherein the first, second and third signals are based on measurements taken using a tool at a single location within the wellbore, and wherein the first location is at a different depth in the formation than the second location. [14] The method of claim 10, wherein the first and second positions are accessed by the downhole tool while it is at different positions within the borehole. [15] The method of claim 10, wherein the downhole tool is a wireline deployed NMR tool. [16] The method of claim 10, wherein the downhole tool is a LWD tool. [17] The method of claim 6, wherein determining includes generating a relationship between the pore pressure and the type of signal of the first, second and third signals, and the determined pore pressure is based in part on the generated relationship. [18] The method of claim 1, wherein the induced pressure change includes inducing a pressure change such that the third signal is equivalent to the first signal. [19] The method of claim 1, further comprising calculating the gas peak intensity for each of the first, second and third signals, and wherein comparing the first, second and third signals includes comparing the calculated gas peak intensity for the first, second and third signals. [20] The method of claim 19, wherein the calculated gas peak intensities are raw gas peak intensities. [21] A method according to claim 19, wherein the calculated gas peak intensities are corrected for the presence of one or more other fluids. [22] The method of claim 1, further comprising estimating the remaining gas reserves of the formation based in part on the determined pore pressure. [23] A system for determining pore pressure in a porous formation with unconnected pore spaces, comprising: a downhole logging tool configured to measure pore pressure dependent signals at locations in the formation, including a first location that is undisturbed and has substantially unconnected pore spaces, and a second location that is disturbed and at least some of the pore spaces are interconnected; a pressure induction means configured to induce a known pressure change at the second position; and a processing system programmed and configured to determine a pore pressure associated with the first position based at least in part on a comparison of values ​​derived from measurements at the first and second positions and the known induced pressure change. [24] The system of claim 23, wherein the downhole logging tool is an NMR tool. [25] The system of claim 23, wherein the porous formation is a shale gas formation and the determined pore pressure is a gas pressure. [26] The system of claim 23, wherein the pressure induction means includes a fluid injection system. [27] The system of claim 23, wherein the second position is artificially perturbed. [28] The system of claim 23, wherein the downhole logging tool is a sonic tool. [29] The system of claim 23, wherein the downhole logging tool is a nuclear logging tool. [30] A method for determining the pore pressure within a porous material having unconnected pore spaces, the method comprising: Processing a first signal as a function of the pore pressure in an undisturbed section of the porous material where the pore spaces are predominantly not connected to each other; Processing a second signal as a function of pore pressure in an undisturbed portion of the porous material in which at least some of the pore spaces are connected; Inducing a known change in pressure in the disturbed portion of the porous material; Processing a third signal as a function of the pore pressure in the disturbed portion of the material while under the induced pressure change; and Determining a pore pressure associated with undisturbed porous material based at least in part on a comparison including the first, second, and third processed signals and the known pressure change. [31] The method of claim 30, further comprising inducing the disturbance of the undisturbed portion of the material so as to produce the disturbed portion of the material. [32] The method of claim 31, wherein inducing the change in pressure is used to induce the disturbance of the undisturbed portion of the material. [33] The method of claim 30, wherein the porous material is from a core sampling process conducted in a borehole, the porous material being a core sample of a subterranean formation, and the processing, inducing and determining are performed in one or more surface facilities. [34] The method of claim 33, wherein the subterranean formation is a shale gas formation. [35] The method of claim 30, wherein the porous material is a closed-cell solid foam.

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