Method of Stimulating Hydrocarbon Production

Abstract

A method is presented for predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase in oil relative permeability when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest. The method comprises: (a) obtaining one or more parameter values for the region of interest; (b) inputting the one or more parameter values into a model which predicts changes in oil relative permeability for the region of interest for different seismic wave or wave pulse shapes and/or amplitudes; (c) repeating step (b) one or more times for different seismic wave or wave pulse shapes and/or amplitudes; and (d) determining which seismic wave or wave pulse shape and/or amplitude causes an increase or the greatest increase in oil relative permeability based on the output of the model.

Claims

1. A method of predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase in oil relative permeability, or a decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest, the method comprising: a. obtaining one or more parameter values for the region of interest; b. inputting the one or more parameter values into a model which predicts changes in oil and/or water relative permeability for the region of interest for different seismic wave or wave pulse shapes and/or amplitudes; c. repeating step b one or more times for different seismic wave or wave pulse shapes and/or amplitudes; and d. determining which seismic wave or wave pulse shape and/or amplitude would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, based on the output of the model.

2. The method as claimed in claim 1, wherein the model is based on wave-induced two-phase fluid-flow and/or the contact angle hysteresis effect.

3. The method as claimed in claim 1, wherein the parameter values comprise one or more of: the Young's modulus, Poisson's ratio, crack length, initial aspect ratio, Skempton's coefficients for oil and/or water phases, oil-water interface tension, advancing and receding contact angles or wettability, and minimum effective stress.

4. The method as claimed in claim 1, wherein the different seismic wave or wave pulse shapes and/or amplitudes comprise seismic wave or wave pulses with varying polarity and/or amplitude.

5. The method as claimed in claim 4, wherein step d comprises determining which seismic wave or wave pulse polarity and/or amplitude causes an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, based on the output of the model.

6. The method as claimed in claim 1, wherein the different seismic wave or wave pulse shapes and/or amplitudes comprise wave pulse shapes and/or amplitudes.

7. The method as claimed in claim 6, wherein determining which seismic wave pulse shape causes the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, based on the output of the model comprises determining which polarity wave pulse shape would cause the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, based on the output of the model.

8. The method as claimed in claim 1, wherein the method is performed on a computer and the method comprises displaying a result of the method on a screen.

9. A method of stimulating hydrocarbon production comprising: a. predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest; and b. applying a seismic wave or wave pulse with the predicted shape and/or amplitude to the region of interest thereby stimulating hydrocarbon production.

10. The method as claimed in claim 9, further comprising recovering hydrocarbons from the region of interest.

11. The method as claimed in claim 9, wherein step a comprises performing the method of claim 1.

12. A method of stimulating hydrocarbon production comprising applying a seismic wave pulse to a region of interest to increase oil relative permeability, and/or decrease water relative permeability, for the region of interest and thereby stimulate hydrocarbon production.

13. The method as claimed in claim 12, further comprising performing the method of any of claim 1 in order to determine a shape and/or amplitude of the seismic wave pulse applied.

14. The method as claimed in claim 12, further comprising recovering hydrocarbons from the region of interest.

15. A system for stimulating hydrocarbon production comprising: at least one seismic source; and means for predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest; wherein the system is arranged such that the at least one seismic source can be controlled to emit seismic waves or wave pulses with a shape and/or amplitude determined by the means for predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest.

16. The system as claimed in claim 15, wherein the at least one seismic source is arranged to emit seismic wave pulses.

17. The system as claimed in claim 16, wherein the seismic wave pulses can have positive or negative polarity.

18. The system as claimed in claim 15, wherein the means for predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest is arranged to perform the method of claim 1.

19. The system as claimed in claim 15, wherein the means for predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest comprises one or more processors arranged to predict which shape and/or amplitude of seismic wave or wave pulse would cause an increase in oil relative permeability, and/or a decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest.

20. The system as claimed in claim 15, comprising a controller arranged to cause the at least one seismic source to emit a seismic wave or wave pulse with a shape and/or amplitude for increasing oil relative permeability, and/or decreasing water relative permeability, based on an output of the means for predicting which shape and/or amplitude of seismic wave or wave pulse would cause an increase or the greatest increase in oil relative permeability, and/or a decrease or the greatest decrease in water relative permeability, when a seismic wave or wave pulse with that shape and/or amplitude is applied to a region of interest.

Description

[0126] Preferred embodiments of the invention will now be described by way of example only and with reference to the accompanying drawings, in which:

[0127] FIG. 1 is a flow diagram illustrating a method of stimulating hydrocarbon production;

[0128] FIG. 2 is a schematic illustration of a dual porosity model;

[0129] FIG. 3 is a schematic cross-sectional illustration of apparatus for seismic stimulation of a sub-surface region of interest;

[0130] FIGS. 4(a)-(c) are examples of seismic wave or wave pulse shapes; and

[0131] FIG. 5 is a cross-sectional illustration of the contact angle hysteresis effect.

[0132] FIG. 1 is a flow diagram illustrating a method of stimulating hydrocarbon production for a particular region of interest.

[0133] The method has four main steps: 1, 2, 3 and 4.

[0134] At step 1, required parameter values for the region of interest are obtained.

[0135] At step 2, the obtained parameter values are input into a model which predicts which wave pulse shape and amplitude for stimulating the region of interest would result in an increase in oil relative permeability.

[0136] At step 3, wave pulses with the predicted shape and amplitude for increasing oil relative permeability are applied to the region of interest.

[0137] At step 4, hydrocarbons are extracted from the region of interest.

[0138] Each of these steps will now be described in more detail.

[0139] At step 1, parameter values for the region of interest are obtained.

[0140] In some embodiments, step 1 comprises measuring the required parameter values. The measurements may be made directly from the region of interest itself and/or they may be made in a laboratory, e.g. from rock samples taken from the region of interest.

[0141] In other embodiments, step 1 comprises obtaining the required parameter values from, for example, a database or other record of the parameter values.

[0142] In some embodiments, one or more parameter values are measured and one or more are obtained from a database or other record.

[0143] Some parameter values are determined (e.g. calculated or estimated) from other parameter values.

[0144] The parameter values comprise values of the Young's modulus, Poisson's ratio, crack length, initial aspect ratio, the Skempton's coefficients for each of oil and water phases, oil-water interface tension, advancing and receding contact angles, and minimum effective in situ stress, for the region of interest

[0145] An example of the input parameters used in one case is presented below: [0146] Young's modulus and Poisson's ratio (of rock matrix): 30 GPa and 0.3 [0147] Characteristic crack length and initial aspect ratio: 2e.sup.−3 m and 0.001 [0148] The Skempton’ coefficients for oil and water phases: 0.4 and 0.6, respectively [0149] Oil-Water Interface tension: 0.033 Pa*m [0150] Advancing and receding contact angles: 37° and 30°. [0151] Minimum effective stress in the formation: 5 MPa

[0152] The initial (most-stable) contact angle is calculated from the advancing and receding contact angles (see, e.g. Ruiz-Cabello, 2014).

[0153] At step 2, the parameter values are used in a model to predict which wave pulse shape and amplitude for stimulating the region of interest would result in an increase in oil relative permeability. Specifically, the model calculates the change of relative permeabilities to oil and water in the region of interest for different pulse shapes and amplitudes. The calculated changes in relative permeabilities to oil and water in the region of interest for different pulse shapes are then compared to determine which pulse shape and amplitude provides an increase or the greatest increase in oil relative permeability. This is then selected for use in step 3.

[0154] The calculations are performed in the low frequency limit, where capillary forces dominate over viscous forces during WITPFF.

[0155] Table 1 (below)) shows an example, of how different input parameters (e.g. characterising different “imaginary” regions of interest) were found, from the model, to affect the sign (direction) of the relative oil permeability (and hence oil mobility) change following the application of compressional and extensional pulses (i.e. seismic wave pulses with opposite polarities). The contact angles are defined (measured) through the water phase. θ.sub.r is the receding contact angle, θ.sub.a is the advancing contact angle, K.sub.water is the Skempton's coefficient for water and K.sub.oil is the Skempton's coefficient for oil.

TABLE-US-00001 TABLE 1 Input parameters, sensitive to the sign of relative permeability change by compressional and extensional pulses. Water wet: 0° < Oil-wet: 90° < θ.sub.r < θ.sub.a < 90° θ.sub.r < θ.sub.a < 180° K.sub.water > K.sub.oil K.sub.water < K.sub.oil K.sub.water > K.sub.oil K.sub.water < K.sub.oil Compressive Decreased Increased Increased Decreased pulse Oil mobility Oil mobility Oil mobility Oil mobility Extensive Increased Decreased Decreased Increased pulse Oil mobility Oil mobility Oil mobility Oil mobility

[0156] As can be seen from Table 1, for some combinations of input parameters a compressive pulse (wave pulse of a first polarity) was found to cause increased oil mobility, whereas for other (or opposite) combinations of input parameters, an extensive pulse (i.e. a wave pulse of a second, opposite polarity) was found to cause increased oil mobility.

[0157] This demonstrates that the polarity of wave pulse required should be determined for each region of interest with its own particular input parameters.

[0158] When performing step 2, a representative elementary volume (REV) of the region of interest with a partially saturated crack is considered. A wave pulse signal with a particular shape is applied to the REV and changes in parameters are determined as follows:

[0159] The initial parameters are far-field normal stress, fluid pressure in the water or oil phase, initial contact angle and the crack saturation. Application of a seismic wave induces changes to these initial parameters, and causes deformation of the rock and two-phase fluid flow between the matrix and the crack. Non-linear effects, produced by the contact angle hysteresis effects, lead to either an increase or a decrease in oil saturation inside the crack when wave pulses are applied. Changes in the relative permeabilities of the crack are calculated from changes of these parameters using the methodology presented in (Rozhko, 2016; Rozhko and Bauer, 2018). Changes of matrix saturation in the dual porosity model are negligibly small compared to changes of crack saturation. Although crack porosity can be a small fraction of total porosity, the crack permeability can have a significant or dominant impact on the total permeability of the rock. Thus, changes of crack relative permeability affect the overall response of a partially saturated rock to the wave pulse.

[0160] Direct measurements of the input parameters may not always be available. In such cases, these parameters are calculated indirectly from other parameters or measurements.

[0161] According to Table 1, rock wettability and Skempton's coefficients are the most important input parameters for the model. Other input parameters do not change the polarity of the wave pulse required for an increase in oil relative permeability. Other input parameters change only the amplitude of the oil relative permeability change for a given wave pulse polarity and amplitude.

[0162] It may not be always feasible to generate a wave pulse at the depth of the region of interest consisting of only one crest. Several minor crests of different polarities may accompany one major crest. In this case, all input parameters of the model should be considered to determine the resulting effect of such a wave pulse on the oil relative permeability.

[0163] The wave pulse shape is the pulse shape of a wave from a seismic source such as a vibrator. A wave pulse is a special non-periodic waveform that typically has one major crest. In some cases, it is accompanied by several minor sub-harmonic crests, in which cases it is called a wave packet.

[0164] The wave pulse shape could be compressional, as shown in FIG. 4(b), or extensional, as illustrated in FIG. 4(c). In other words, the wave pulse could have positive or negative polarity. The particular properties (fluid and rock properties) of the region of interest will determine whether a compressional or an extensional wave pulse (i.e. which polarity wave pulse) will cause an increase in oil relative permeability.

[0165] The wave pulse will also have an amplitude.

[0166] It has been found that a periodic wave, e.g. a sinusoidal wave as shown in FIG. 4(a), is not as effective as a wave pulse at increasing oil relative permeability and stimulating hydrocarbon production.

[0167] The model used in step 2 is a dual porosity model based on a combination of two mechanisms: [0168] the wave-induced two-phase fluid flow (WITPFF) between adjacent pores of different compliances; and [0169] the contact angle hysteresis effect.

[0170] These two mechanisms lead to a significant change in crack saturation during WITPFF, and changes in crack saturation affect the relative permeabilities of the crack.

[0171] Together, the above two effects or mechanisms work like a semi-permeable membrane for the oil and water phases during wave-induced crack deformation (e.g. widening or narrowing).

[0172] FIG. 2 is a schematic illustration of a dual porosity model in which the subsurface region of interest is modelled as a matrix of stiff pores 5 with compliant pores or cracks 6 located at positions within the matrix of stiff pores 5. The cracks 6 are imperfectly bonded grain (pore) contacts. The cracks 6 and the matrix of stiff pores 5 are connected in three dimensions.

[0173] WITPFF is brought about by adjacent pores 5 and cracks 6 having different compliances. Stimulation of the matrix with a seismic wave can cause the cracks 6 to open or close (wave-induced crack opening or closure), thereby affecting crack saturation and the relative permeabilities of the crack.

[0174] The contact angle hysteresis effect is illustrated in FIG. 5. This figure shows a drop of liquid 10 (e.g. oil or water) on an inclined surface 11. The surface 11 has an inclination angle α. As indicated in FIG. 5, the drop 10 has two different contact angles θ.sub.1 and θ.sub.2 to the surface 11 at its upper and lower ends, respectively. At some critical angle, a, the droplet will start to slip. The highest possible contact angle that can be achieved for a given wetting system is called the advancing contact angle, whereas the lowest possible contact angle is called the receding contact angle. The difference between the contact angles θ.sub.1 and θ.sub.2 prevents the drop 10 from sliding down the surface 11. The same mechanism, i.e. contact angle hysteresis, traps oil bubbles inside pores.

[0175] At step 2, the model is used to first predict which polarity (e.g. positive or negative, corresponding to extensional or compressional wave pulses, or vice versa) wave pulse will result in an increase in oil relative permeability. The model is then used to determine what is the minimum amplitude required in order to achieve a non-negligible increase in oil relative permeability (for that polarity wave pulse). It has been found that the greater the amplitude, the greater the effect. However, large amplitudes are not always feasible which is why the model is used to predict the minimum amplitude required in order to achieve a non-negligible increase in oil relative permeability.

[0176] At step 3, wave pulses with the predicted shape (polarity) and (at least minimum) amplitude for increasing oil relative permeability are applied to the region of interest. Thus, either compressional or extensional wave pulses are applied to the region of interest, with at least the minimum amplitude required for a non-negligible effect, depending on the result of step 2.

[0177] The time gap between wave pulses depends on the speed at which the contact angle will equilibrate to its most-stable equilibrium distribution (Ruiz-Cabello, 2014). This is an empirical parameter. At the initial stage the stimulation can be started with a time gap between pulses which is 3 to 5 five times larger than the duration of the pulses.

[0178] Step 3 can be performed with different kinds of seismic sources. For example, seismic vibrators, air-guns, seismic receivers working as sources, explosions (on the surface, in the well, in water, etc), various acoustic transmitters used in a borehole, can all be used.

[0179] The seismic source(s) can be located at the surface, in the sea water and/or in a borehole.

[0180] One or several seismic sources can be applied to generate various shapes and amplitudes of the wave pulse(s) at the depth of the region of interest.

[0181] As shown in FIG. 3, in the case of reservoir-scale stimulation, the wave pulses can be applied from a low frequency (e.g. 1-200 Hz) vibrational source 8a (e.g. a seismic vibrator) located at the surface. Such wave pulses are directed to travel down to the region of interest 9. Alternatively, pressure pulsing technology such as borehole fluid injections can be used to apply the wave pulses.

[0182] In the case of near-wellbore-scale stimulation, the wave pulses can be applied with a high frequency (1-100 kHz) acoustic source 8b placed in the wellbore.

[0183] Typical amplitudes of the seismic waves are very small, with strain amplitudes of 10.sup.−6 to 10.sup.−8, which correspond to stress amplitudes of 10.sup.4 Pa to 10.sup.2 Pa, for a rock with a Young's modulus of ˜10 GPa. Wave pulses require significantly lower wave amplitudes than the amplitude that would be required for a comparable effect with a continuous wave.

[0184] In some embodiments, a number of seismic sources are used to emit the wave pulses for stimulating hydrocarbon production in order to maximise the effect of seismic vibration. The model can predict how many sources of a given vibrational power should be applied in order to have a non-negligible effect on oil recovery.

[0185] At step 4, hydrocarbons are extracted from the region of interest 9, e.g. via a well 7 as shown in FIG. 3, in a standard manner. Step 4 is performed at the same time as step 3, and step 3 is performed for as long as step 4 is performed. Seismic wave pulsing is cheap and does not harm the environment so performing step 3 for as long as step 4 is performed is not unduly problematic.

[0186] The above method of stimulating hydrocarbon production can be performed in various locations including offshore, onshore, and in producing boreholes.

[0187] Offshore hydrocarbon production can be stimulated by seismic vessels or by seabed equipment used for permanent reservoir monitoring or by air gun sources.

[0188] Onshore hydrocarbon production can be stimulated by seismic vibrators.

[0189] Hydrocarbon production in producing wells can be stimulated by acoustic sources, e.g. permanently installed in the borehole.

[0190] In some cases, air guns or other explosive sources may not be suitable as they produce predominantly compressional wave pulses (i.e. of a single polarity), which, in some regions, may result in a decrease in relative oil permeability. Thus, in some cases, sources other than air guns or other explosive sources may be required, e.g., if a wave pulse with opposite (extensional, not compressional) polarity is required to increase relative oil permeability. This can be determined by the model.

REFERENCES

[0191] Beresnev, I. A. and Johnson, P. A., 1994. Elastic-wave stimulation of oil production: A review of methods and results. Geophysics, 59(6), pp. 1000-1017. [0192] Manga, M., Beresnev, L, Brodsky, E. E., Elkhouy, J. E., Elsworth, D., Ingebritsen, S. E., Mays, D. C. and Wang, C. Y., 2012. Changes in permeability caused by transient stresses: Field observations, experiments, and mechanisms. Reviews of Geophysics, 50(2). [0193] Rozhko, A. Y., 2016. Two-phase fluid-flow modeling in a dilatant crack-like pathway. Journal of Petroleum Science and Engineering, 146, 1158-1172. [0194] Rozhko, A. Y., and Bauer A., 2018. Contact line friction and surface tension effects on seismic attenuation and effective bulk moduli in rock with a partially saturated crack. Geophysical Prospecting. [0195] Ruiz-Cabello, F. M., Rodriguez-Valverde, M. A., & Cabrerizo-Vilchez, M. A. (2014). Equilibrium contact angle or the most-stable contact angle?. Advances in colloid and interface science. 206, 320-327.