Abstract
The present invention relates to a method of prediction of hydrocarbon accumulation in a geological region comprising the following steps of: a. Generation of a geological basin model; b. Generation of a geomechanical model; c. Generation of an integrated model; d. Generation of a strain map based on the information obtained in steps a to c; e. Prediction of hydrocarbon accumulation from the strain maps.
Claims
1. Method of prediction of hydrocarbon accumulation in a geological region comprising the following steps of: a. Generation of a geological basin model; b. Generation of a geomechanical model; c. Generation of an integrated model; d. Generation of a strain map based on the information obtained in steps a to c; e. Prediction of hydrocarbon accumulation from the strain maps.
2. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the geological basin model further comprises at least one of the following steps of: a. Determination of Horizons and faults; b. Restoration and backstripping to identify the tectonic events; c. Modeling porosity; d. Modeling pressure; e. Modeling Porosity-permeability relationship.
3. Method of prediction of hydrocarbon accumulation in a geological region according to claim 2, wherein the step of modeling pressure further comprises at least one of the following steps of: a. Calibration of the pore pressure model; b. Application of the pore pressure model to the geological region.
4. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the geological basin model comprises mechanical stratigraphy.
5. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the geological basin model comprises the step of modeling permeability.
6. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the geological basin model further comprises at least one of the following steps of: a. Sediment decompaction; b. Acquisition of burial history of the geological region.
7. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the geological basin model comprises the step of modeling overpressure of the geological region.
8. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the generation of a geomechanical model further comprises at least one of the following steps of: a. Seismic Inversion and detailed rock physics analysis including fluid substitution modelling; b. Pre-stack Seismic Data conditioning; c. Pre-stack AVO simultaneous inversion; d. Prediction of mechanical properties based on porosity correlations derived from core results; e. Generation of a 1D geomechanical model.
9. Method of prediction of hydrocarbon accumulation in a geological region according to claim 8, wherein the prediction of mechanical properties based on porosity correlations derived from core results further comprises at least one of that: a. Porosity cubes are sourced from reservoir models; b. In overburden and dense units separating reservoir zones, the prediction of mechanical properties is based on co- upscaled well logs; and c. Mechanical property profiles are sourced from 1 D-geomechanics models.
10. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, further comprising the step of creating a structural model, wherein the method further comprises the step of estimating 3D static and dynamic of the geomechanics model.
11. Method of prediction of hydrocarbon accumulation in a geological region according to claim 10, comprising the step of fault and fracture analysis.
12. Method a of prediction of hydrocarbon accumulation in a geological region according to claim 11, comprising the steps of: a. Generating a Discrete Fracture Network; b. Upscaling the Discrete Fracture Network into the static geomechanics model.
13. Method of prediction of hydrocarbon accumulation in a geological region according to claim 10, wherein the structural model includes information about tectonic stresses in a geological region.
14. Method of prediction of hydrocarbon accumulation in a geological region according to claim 10, wherein the geological basin model and the geo-mechanical model are combined with the structural model to generate the strain maps.
15. Method of prediction of hydrocarbon accumulation in a geological region according to claim 10, wherein the structural model is combined with the integrated model.
16. Method a of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the generation of an integrated model further comprises at least one of the following steps of: a. 3D Mechanical Properties Population; b. Mechanical Properties and Stress Model; c. Pore Pressure Preparation at Selected Time-steps; d. 3D Pre-production Stress Modelling and Calibration.
17. Method a of prediction of hydrocarbon accumulation in a geological region according to claim 16, wherein hydrocarbon accumulations are predicted from the outputs received by steps a. to d.
18. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the step of generation of strain maps comprises the following steps of: a. Modeling of overburden stress of the geological region; b. Modeling of effective stress of the geological region; c. Modeling of pore stress of the geological region.
19. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the strain maps indicate regions of high and low strain.
20. Method of prediction of hydrocarbon accumulation in a geological region according to claim 1, wherein the prediction of hydrocarbon accumulation includes a delineation of areas where hydrocarbon is trapped, and a prediction of migration pathways for hydrocarbon.
21. A map indicating hydrocarbon accumulation, wherein the map is gained by a method of prediction according to claim 1.
22. A computer program product comprising instructions which, when the program is executed by a computer, cause the computer to carry out the steps of the method of claim 1.
23. A computer-readable storage medium comprising instructions which, when executed by a computer, cause the computer to carry out the steps of the method of claim 1.
24. A data processing system comprising means for carrying out the steps of the method of claim 1.
Description
4. SHORT DESCRIPTION OF THE DRAWINGS
[0243] In the following, preferred embodiments of the invention are disclosed by reference to the accompanying figures, in which:
[0244] FIG. 1 shows a workflow for creating strain maps, hydrocarbon accumulations and belts according to the present invention;
[0245] FIGS. 2A-C show a geologic model, where any layer deposited are undergoing two processes; namely compaction and tectonics; according to the present invention;
[0246] FIGS. 3A-C show porosity modeling according to the present invention;
[0247] FIGS. 4A-D show the application of the porosity model on one formation according to the present invention;
[0248] FIG. 5 shows a 3-D porosity model according to the present invention;
[0249] FIGS. 6A-B show calibrating the pressure model according to the present invention;
[0250] FIGS. 7A-D show a pressure model example in one formation according to the present invention;
[0251] FIG. 8 shows a 3-D pressure model according to the present invention;
[0252] FIGS. 9A-D show overpressure results in one formation according to the present invention;
[0253] FIGS. 10A-B show overpressure and permeability maps according to the present invention;
[0254] FIG. 11 shows the density dependency on angle range of the seismic to estimates layer properties;
[0255] FIGS. 12A-C show mechanical properties based on porosity correlations derived from core results in the workflow for 1D Geomechanics models according to the present invention;
[0256] FIG. 13 shows a 1D Geomechanics model example according to the present invention;
[0257] FIGS. 14A-E show the mapping of the mechanical parameters across Abu Dhabi according to the present invention;
[0258] FIG. 15 shows a borehole image log example according to the present invention;
[0259] FIGS. 16A-C show Extraction of Seismic Discontinuity Plans (SDP): Analysis and Input for DFN according to the present invention;
[0260] FIGS. 17A-B show faults corridor in one field (FIG. 17A) and the reactivation of some fault segments within the corridor (FIG. 17B) according to the present invention;
[0261] FIGS. 18A-E show dynamic properties (conductivity and aperture) of fracture corridors, leading to fracture porosity and permeability tensor according to the present invention;
[0262] FIGS. 19A-F show the impact of Natural Fractures on Reservoir Deformation in one formation according to the present invention;
[0263] FIGS. 20A-F show the impact of Natural Fractures on potential permeability in one reservoir section according to the present invention;
[0264] FIGS. 21A-B show the impact of Natural Fractures on fault slip analysis according to the present invention;
[0265] FIGS. 22A-F show fault Effect on Stress Direction according to the present invention;
[0266] FIG. 23 shows a map of shear stresses relative to tectonic stresses according to the present invention;
[0267] FIG. 24 shows stress rotations near faults according to the present invention;
[0268] FIG. 25 shows a finite element model of the Abu Dhabi region normalized by the overburden stress according to the present invention;
[0269] FIG. 26 shows a map of mean and shear stress according to the present invention;
[0270] FIG. 27 shows a map of hydrocarbon accumulations according to the present invention.
5. DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
[0271] FIG. 1 shows a workflow for creating strain maps, hydrocarbon accumulations and belts according to the present invention. Herein, FIG. 1 provides an overview of the steps that can be employed to generate a respective model. In particular, FIG. 1 shows that Horizons (surfaces) and faults were interpreted from seismic data and derived from isopach maps (cf. blue boxes with numbers 1 to 12). Further, FIG. 1 shows the steps relating to the step of seismic inversion (cf. orange boxes with numbers 13 and 14). Further, FIG. 1 shows the steps of generating a 1D geomechanical model (cf. purple boxes with numbers 15 to 20) and 3D shown in dark blue box with number 21. Further, FIG. 1 shows the steps of modeling of the 3D static and dynamic (cf. green boxes with numbers 22 to 25 and red boxes with numbers 26 to 29). Further, FIG. 1 shows the steps relating to the generation of an integrated model up to strain maps; hydrocarbon accumulations and hydrocarbon belts (cf. yellow boxes with numbers 30 to 35).
[0272] FIGS. 2A to C show a geologic model, where any layer deposited is undergoing two processes; namely compaction and tectonics according to the present invention. This relates to steps No. 1-12 in FIG. 1. FIG. 2A shows backstripping of the model to the oldest formation. Simulation process started with decompaction of the formation layers and then re-deposition of each of the older formation until the present day (FIGS. 2B and 2C). At each of the geological time steps, parameters such as porosity and pore pressure were calculated. These calculations were controlled by lithology parameters for each of the layers. The simulation results were analyzed and compared with present well data such as porosity and formation pore pressure. Calibration processes were required when the calculated output results were not consistent with the well data. The initial model parameters needed to be modified and the modifications were done in the model-building step. Once the modifications were finalized, the model needed to be re-simulated. The output results of the modified model should honor the well data. Herein, lithology parameters were modified to get good matches of porosity and pore pressure output results to the well data.
[0273] FIGS. 3A-C show porosity modeling according to the present invention. This relates to steps No. 4-10 in FIG. 1. FIGS. 3A and 3B show the modeled porosity and the modeled pressure for various depths. The porosity-effective stress relationship was used to calibrate compaction curves for lithological layers. FIG. 3C shows the calibrated compaction curve versus the default compaction curve.
[0274] FIGS. 4A to D show the application of the porosity model on one formation according to the present invention. This relates to steps No. 7-12 in FIG. 1. The simulated porosity model is able to predict porosity for each of the formation layers (cf. FIG. 4) and at each geological time steps. The porosity was calculated based on compaction curves and these compaction curves were unique to the formation. While this approach captures the spatial variation of porosity throughout the formation layers. The porosity of a given geological area is shown for the time points of today in FIG. 4A and 95 million years ago in FIG. 4C. FIG. 4B shows to porosity at the position of the well denoted with “A” (cf. FIG. 4A) at different times from around 100 million years ago to the present. As can be seen from the figure, the porosity decreases in time. FIG. 4D shows a burial plot of the different geological layers at different depths with a porosity overlay at the position of Well “A” (cf. FIG. 4A) at different times from 95 million years ago to the present.
[0275] FIG. 5 shows a 3-D porosity model according to the present invention. This relates to steps No. 10-12 in FIG. 1. Based on the results, as shown in FIG. 4, porosity distribution in rock sequence ranges were predicted and calibrated using real data from the lab testing at present day.
[0276] FIGS. 6A and B shows calibrating the pressure model according to the present invention. This relates to steps No. 1-12 in FIG. 1. FIG. 6A shows example of this where three pairs of log permeability-porosity are plotted for the Laffan layer as an example. By decreasing, the permeability values at its corresponding porosity, fluid flow is restricted and pore pressure of the formation and below will increase. FIG. 6B shows a pressure simulation of the geological layers at the position of Well A at different depths for the hydrostatic pressure, the lithostatic pressure and the pore pressure.
[0277] FIGS. 7A to D show a pressure model example in one formation according to the present invention. This relates to steps No. 1-12 in FIG. 1. Formation pore pressure showed good spatial pressure distribution and the evolution of pore pressure honors geological events that were captured during structural model building. The pore pressure of a given geological area is shown in the 3D model in FIG. 7A. FIG. 7B shows the created pressure at one layer (horizon) created from the model in 7A. FIG. 7C shows the pressure changes with time created from the 3D model at one well (A) location. FIG. 7D shows a burial plot of the different geological layers at different depths with pore pressure overlay at the position of Well A (cf. FIG. 7A).
[0278] FIG. 8 shows a 3-D pressure model according to the present invention. This relates to steps No. 1-12 in FIG. 1. Herein, the resulting values, as shown in FIG. 7 were simulated and predicted for each formation layer.
[0279] FIGS. 9A to D show overpressure results in one formation according to the present invention. This relates to steps No. 1-12 in FIG. 1. The overpressure of a given geological area is shown for the time points of today in FIG. 9A and one layer as an example (95 million years ago) in FIG. 9B. FIG. 9C shows overpressure of the layer at the position of Well A (cf. FIG. 9A) at different times from 100 million years ago to the present. FIG. 9D shows a burial plot of the different geological layers at different depths with overpressure overlay at the position of Well A (cf. FIG. 9A) at different times from 100 million years ago to the present. Modeling overpressure is crucial and as shown in FIG. 9, reveals areas where overpressure is observed from simulation results. This shows clearly pressure increases with depth. Formations pressure network is very important to predict overpressure in the model. The connectivity of low permeable formation has an effect on the pressure system of the formations adjacent to it. The nature of formation allows pressure to be transferred via the movement of fluid within the formation such as connate water from a higher pressure zone to a lower pressure zone.
[0280] FIGS. 10A and B show overpressure and permeability maps according to the present invention. This relates to steps No. 1-12 in FIG. 1. The graphs are taken along a line Y to Y′ of the area depicted in FIGS. 4, 7 and 9, as show in FIG. 10B′. Herein, FIG. 10A shows the overpressure along the line Y to Y′ for different depths and respective layers and FIG. 10B shows the horizontal permeability along the line Y to Y′ for different depths and respective layers. The respective arrows show the corresponding fluid flow. As noted before, the nature of formation allows pressure to be transferred via the movement of fluid within the formation such as connate water from a higher pressure zone to a lower pressure zone. This case can be seen in the overpressure model of one layer as an example formation shown in FIGS. 10A and B. The overpressure of the deeper section of the formation is lower than the overpressure of the shallower formation.
[0281] FIG. 11 shows the density dependency on angle range of the seismic to estimated layer properties. This relates to steps No. 13-14 in FIG. 1. The elastic parameters are created by following a workflow dependent on pre-stack seismic inversion.
[0282] FIGS. 12A-C show mechanical properties based on porosity correlations derived from core logs results in the workflow for 1D Geomechanics models according to the present invention. The results of the 1D Geomechanics model are calibrated using lab measurements on cores. This relates to steps No. 13-14 and 15-21 in FIG. 1. Herein, FIG. 12A shows the created parameters from the prestack inversion, calibrated with the 1D Geomechanics models results (15-21). FIG. 12B shows the Young's modulus in some layers variations. FIG. 12C 1, 2 and 3 show the mechanical parameters at one horizon as an example.
[0283] FIG. 13 shows a 1D Geomechanics model example according to the present invention. This relates to steps No. 15-20 in FIG. 1. Herein, the model was exemplarily constructed for Abu Dhabi fields. The first track (Nr. 1) shows the depth. The second track (Nr. 2) shows the chosen formations presented as example. The third track (Nr. 3) shows the Young's modulus (YME) and Poisson's ratio (PR). The fourth track (Nr. 4) shows the unconfined compressive strengths (UCS), tensile strengths (TSTR) and angle of internal friction (FANG). The fifth track (Nr. 5) shows the stresses, the black curve is the vertical stress (sv), SHmax (maximum horizontal stress), SHmin (minimum horizontal stress). The sixth track (Nr. 6) shows the results of wellbore stability showing the safe mud window and fracture gradient. The seventh track (Nr. 7) shows the instability intervals and the eighth track (Nr. 8) shows the caliper.
[0284] FIGS. 14A to E show the mapping of the mechanical parameters across Abu Dhabi according to the present invention. This relates to steps No. 13-21 in FIG. 1. Herein, rock elastic and strength property parameters are constructed for the overburden and reservoir sections using available log and core test data for calibration. The most appropriate correlations are used to establish log-derived elastic and rock strength property profiles. In particular FIG. 14A shows Young's Modulus; FIG. 14B shows Poisson's Ratio; FIG. 14C shows unconfined compressive strengths; FIG. 14D shows tensile strengths; FIG. 14E shows minimum horizontal stress. The oval indications A, B, C, D, E, and F in each figure show the selected wells for validating the mechanical parameters.
[0285] FIG. 15 shows a borehole image log example according to the present invention. This relates to steps No. 18 and 26-29 in FIG. 1. The first track (A) shows the minimum horizontal stresses (SHMIN) depending on breakouts; direct measurements through tests and; the second track (B) shows conductivity; the third track (C) shows the static image and the fourth track (D) shows the azimuth and dip of the CS: conductive seams; DCF=LC: discontinuous conductive fractures and SCF: subsidiary conductive fractures.
[0286] FIGS. 16A to C show fractures and microfaults modeling: Analysis and Input for DFN according to the present invention. This relates to steps No. 26-29 in FIG. 1. In particular, FIG. 16A shows Fracture Detection: Structural Decomposition (Seismic Volume Attributes). FIG. 16B shows the horizons, faults interpretation, and natural fractures around wells from BHI. FIG. 16C shows Extraction of SDP (Seismic Discontinuity Plans): Analysis and Input for DFN.
[0287] FIG. 17A shows faults corridor in one onshore field of Abu Dhabi; FIG. 17B shows the reactivation of some fault segments within the corridor according to the present invention. This relates to steps No. 22-29 in FIG. 1.
[0288] FIGS. 18A to E show dynamic properties (conductivity and aperture) of fracture corridors, leading to fracture porosity and permeability tensor according to the present invention. This relates to steps No. 22-29 in FIG. 1. In particular, in FIG. 18A a porosity model created from steps 1-12 is calibrated and validated using fracture aperture and connectivity from BHI. FIG. 18B shows petrophysical model with saturation; FIG. 18C shows fluids contacts as the common contact in one reservoir. FIG. 18D shows the formula results used in volume calculations HCV=Pore volume×So and FIG. 18E shows STOIIP=HCVo/Bg+(HCVg/Bg)×Rv. Abbreviations: STOIIP=stock-tank oil initially in place, the volume of oil in a reservoir prior to production; HCP=HC (hydrocarbon) initially in place of oil. Solution gas, free gas or condensate at standard surface conditions. GRV=Gross volume; NRF=Net Rock volume; NPV=Net pore volume; HCPV=Hydrocarbon pore volume; So=oil saturation . . . etc.
[0289] FIGS. 19A to F shows impact of Natural Fractures on Reservoir Deformation in one formation according to the present invention. This relates to steps No. 22-29 in FIG. 1. In particular FIG. 19A shows the shear strain with no fractures. FIG. 19B shows the total strain (deformation) with the presence of fractures. FIG. 19C shows volumetric strain that is not only the reservoir but due overburden. FIG. 19D shows the deformation is increased around the faults. FIG. 19E shows the horizontal strain and FIG. 19F shows the deformation around faults and fractures on the horizontal.
[0290] FIGS. 20A to F show the impact of Natural Fractures on potential permeability in one reservoir section according to the present invention. This relates to steps No. 22-29 in FIG. 1. In particular, FIG. 20A shows the volumetric compressibility in case of no fractures and FIG. 20B with presence of fractures. FIG. 20C shows the shear ability and 20D with shear around faults and fractures. FIG. 20E shows compressibility on one layer and 20F the more impact with the inclusion of fractures and faults.
[0291] FIGS. 21A and B show the fault slip potential analysis according to the present invention. This relates to steps No. 26-29 in FIG. 1. In particular, FIG. 21A shows the slip along faults and FIG. 21B shows the inclusion of those fractures with potential slip.
[0292] FIGS. 22A to F show the fault Effect on Stress Direction according to the present invention. This relates to steps No. 26-29 in FIG. 1. In particular FIGS. 22A, B and C show the stress analysis around faults showing total stress and clear of the stress deviation. FIGS. 22D, E and F show the corresponding stress variation showing maximum and minimum horizontal stresses.
[0293] FIG. 23 shows a map of shear stresses relative to tectonic stresses according to the present invention. This relates to steps No. 26-29 in FIG. 1. It clearly shows the rotation of the stresses around the master faults.
[0294] FIG. 24 shows stress rotations near faults according to the present invention. This relates to steps No. 26-29 in FIG. 1. This shows the stress rotation around some faults while others not.
[0295] FIG. 25 shows a finite element model of the Abu Dhabi region normalized by the overburden stress according to the present invention. This model shows all the layers and horizons from surface to reservoirs level. The model integrated all the previous models in one. This relates to steps No. 21 and in FIG. 1.
[0296] FIG. 26 shows a map of mean and shear stress according to the present invention. This relates to step No. 32 in FIG. 1. This shows the shear stresses in one layer as an example.
[0297] FIG. 27 shows a map of hydrocarbon accumulations according to the present invention. This relates to steps No. 31-35 in FIG. 1. This map shows the hydrocarbon accumulations and those trending in one direction forming hydrocarbon belts. The hydrocarbon accumulations show a relation with the low strain areas. Some of those are showing a strict trend, which means they are tectonically related and therefore named hydrocarbon belts.
