J.M. Reyes-Montes

Using Continuous Microseismic Records for Hydrofracture Diagnostics and Mechanics

Summary Using continuous microseismic records is a novel technique for better understanding the mechanics of the fracture network evolution during a hydrofracture treatment, and to provide a tool for diagnostic evaluation of recorded microseismic data. Hydrofracture stimulations are widely used during well completions to optimize production volumes and extraction rates in petroleum reservoirs, enhanced geothermal systems and block-caving mines. Microseismic monitoring is now becoming a standard tool for evaluating the position and evolution of a given treatment, principally by source locating microseismic hypocenters and visualizing these with respect to the treatment volume and infrastructure. The continuous microseismic amplitude record includes the full history of the seismic energy response of the rock mass recorded at a given geophone. We present case studies illustrating the use of this technique for supplementing microseismic locations to better understand the evolution of the fracture treatment, and to diagnose the condition of a given data set, so as to design criteria for more effective processing of the discrete microseismic events.

Fracture network engineering for hydraulic fracturing

Fracture network engineering (FNE) involves the design, analysis, modeling, and monitoring of infield activities aimed at enhancing or minimizing rock mass disturbance. FNE relies specifically on advanced techniques to model fractured rock masses and correlate microseismic (MS) field observations with simulated microseismicity generated from these models. Hydrofracture stimulation is an example where FNE is playing a role, with hydraulic treatments now being widely used to optimize production volumes and extraction rates in petroleum reservoirs, enhanced geothermal systems, and preconditioning operations in caving mines. MS monitoring is now becoming a standard tool for evaluating the geometry and evolution of the fracture network induced during a given treatment, principally by source locating MS hypocenters and visualizing these with respect to the treatment volume and infrastructure. The integrated use of synthetic rock mass (SRM) modeling of the hydrofracturing with enhanced microseismic analysis (EMA...

Analysis of microseismic events during a multistage hydraulic stimulation experiment at a shale gas reservoir

Despite the current easing in demand for increased oil production linked to the global downturn in crude prices, energy demand continuously increases and the long-term demand will require maximizing the productivity of reservoirs and a search into the exploitation of new resources in increasingly challenging environments. In this study, we present the results from the monitoring of the very first multistage stimulation experiment at a shale gas reservoir in Saudi Arabia, presenting an analysis of the microseismicity induced during the treatment. Our aim was to analyse microseismic events to better understand fracture growth and the role of pre-existing fractures in these reservoirs. Microseismic (MS) event monitoring is used to track the creation of fractures during and after the stimulation, and therefore to evaluate the effect of the reservoir stimulation. The monitoring includes a downhole array of 12 3C-sensors that were deployed in a vertical well with a 30.5 m level spacing. A total of 415 MS events were located and analysed, with the results outlining induced fractures extending consistently with an average azimuth of N335° E, normal to the horizontal section of the treatment well. This implies that there are no changes in the local stress direction along the treatment well either in situ or induced along the treatment. There are significant changes in total length and aspect ratio (length/width) of the fractures induced in the different stages. These variations could be attributed to in situ fracturing, local rock heterogeneity or the influence of the treatment parameters. In general, early and late stages of stimulation show the longest fracture networks, with events induced further away from the initiation point. We found no immediate relationship between treatment parameters (peak pressure and pumping rates) and fracture extension. Sensitivity analysis using Monte Carlo simulation methods shows a higher location uncertainty for events located at the early stages, thus limiting the interpretation from monitored seismicity in the early stages. An analysis of magnitude distribution with distance shows a decrease in sensitivity of one degree of magnitude for every 375 m, and a maximum viewing distance of approximately 700 m for the current set-up. The low number of located events does not provide a complete enough dataset for a robust analysis of changes in b-value (slope in linear part of magnitude distribution) during the treatment: however, magnitude distributions, corrected for array sensitivity, provide a useful variable for the validation of geomechanical models currently being developed for the reservoir.

Microseismic analysis for the quantification of crack interaction during hydraulic stimulation

Summary The cluster index provides a means to identify the seismic activity corresponding to the development of connected fracturing that creates paths for fluid transmission during hydraulic stimulations. The location of induced microseismic events is combined with their source dimension, interpreted from the frequency content, to interpret the degree of interaction between the induced fractures. The spatial and temporal evolution of the degree of interaction is provided by the cluster index, which allows the characterization of events in terms of their potential interactivity. This is analyzed for four example well stimulations, describing two distinct behavior patterns for damage evolution: damage initiating as growth of connected fractures followed by scattered isolated fracturing, and fracturing initiating by the induction of scattered fractures followed by coalescence and growth of dominant fracturing.

Time-lapse Velocities for Locations of Microseismic Events - A Numerical Example

The accuracy in the location of microseismic (MS) events relies, among other factors, on the use of a realistic velocity model in the forward calculation of travel times. During the hydraulic stimulation of deep rock reservoirs, the physical properties of the rock are altered and therefore the velocity structure is subject to changes along the treatment. In this paper, a numerical study using the distinct element method and the cross-correlation technique is carried out to measure velocities in a naturally fractured geothermal reservoir in order to better understand the relationship between induced microseismicity and fractures, fluid pressure and seismic velocity anisotropy. The fracture damage zone and fluid permeable zone were successfully correlated with the time-lapse velocity changes extracted from the numerical model. The model offers the unique ability to examine directly the microprocesses leading to macroscopic velocity changes. Validated models could be extended to quantitatively calibrate velocities required for microseismic locations over time, and predict the fracture propagation and fluid migration within a field-scale engineered reservoir.

Automated Microseismic Event Location Using Finite Difference Traveltime Calculation and Enhanced Waveform Stacking

The Fast Sweeping Method (FSM) is a finite difference algorithm providing significant computational efficiency and modelling capability in calculating the first arrivals of seismic P- or S-waves. Based on the calculated travel-timetable, we stack waveform amplitude for every possible source location and origin time followed by semblance weighting. With three-component (3-C) data, the stacked image can be further improved by matching the waveform polarization with the modelled ray vector from FSM and thus reduce the azimuth ambiguity in the location of microseismic (MS) events. We apply the algorithm on synthetic surface and borehole data and show that the combination of FSM and enhanced waveform stacking can efficiently locate MS events with high spatial resolution even when realistic noise levels are added. Finally we test the algorithm on a set of field 3-C data from the stimulation of a sandstone reservoir monitored using two borehole arrays. The method allowed the location of twice the number of event compared to locations using each borehole individually, with both sets defining a consistent fracture structure.

A New Finite Difference Eikonal Equation Solver for Anisotropic Medium

The fast sweeping method has been proved very efficient in calculating the first arrivals in isotropic media. In this study, we extend the fast sweeping method to heterogeneous anisotropic medium by adapting the Lax-Friedrichs local scheme. The new fast sweeping method is able to solve the first arrival traveltime field for both qP and qS waves. By comparing the traveltime field to the full-waveform solution, we demonstrate that the iso-surfaces of the time field follow the constant phase of the wave and form a continuous envelope wrapping the wavefront. The iso-surfaces for the shear wave identify two continuous wavefronts one ahead of the other even in the directions where the triplication of qS-wave is developed. The rays for both qP and qS wave can be traced using the slowness vector from the traveltime field and we compared its accuracy with a two-point ray tracing method in a layered model. We show that rays from the traveltime field is nearly identical to the two-point ray tracing results. This new fast sweeping method not only avoids the multipath and shadow zone issues in complex heterogeneous media but also circumvent the multiple shear branch problems due to anisotropy.

Characterisation of Uncertainties in Microseismic Monitoring through Analysis of Numerically Modelled Events

Passive monitoring of induced microseismic (MS) events provides a unique means for imaging fracture propagation in response to engineering operations. Particularly during hydraulic treatment of hydrocarbon-bearing reservoirs rock MS monitoring provides feedback to field operators on the effect of the treatment and the changes imposed on the fracture network and fluid conductivity within the rock.

Quantifying Reservoir Stimulation Using Passive Traveltime Tomography

Hydraulic fracturing stimulates reservoir and imposes stress changes in the surrounding rock that typically induce or trigger seismicity with a wide range of magnitudes. Seismic monitoring provides insight into the reservoir deformation and give critical feedback to the on-going stimulations. We have developed a passive seismic tomography technique adapted from earthquake seismology to jointly locate induced microseismic events and update the velocity of the reservoir illuminated by the microseismicity. We calculate travel-time based on the fast sweeping method to account for complex 3D distribution of velocity and use the adjoint method to transform the inverse problem to a forward problem which can also be solved by the fast sweeping method. In this paper, we apply our algorithm to a two-stage reservoir stimulation project and demonstrate the capability of the microseismic tomography in mapping the stimulated rock volume and in quantifying the reservoir degradation even in the absence of visible P-waves.

Numerical Modeling of Microseismicity Induced by CO2 Injection

In order to assess the feasibility and performance of geological sequestration as a long-term solution for CO2 depletion, it is crucial to evaluate and monitor the integrity and stability of the caprock. Direct comparison with results from field observation and modeled microseismicity provides a unique tool to evaluate the evolution of the treated rock reservoir. A suite of 2D DEM models with varying gas pressures, reservoir temperatures and permeability for the pre-existing fracture, were built to examine the interaction between the injected CO2 and the pre-existing fracture and caprock. Jointed models with a higher permeability for the pre-existing fracture subject to the highest injection pressure showed microseismic activity increasing with reservoir temperature, indicating higher likelihood of CO2 migration. All the induced fractures crossed the pre-existing fracture following different patterns. High-permeability jointed models with low and medium injection pressures showed no microseismicity and injected CO2 remained confined within the reservoir. Jointed models with a lower permeability for the pre-existing fracture, reproducing caprocks such as shale layers, produced low microseismicity under all modeled pressures and temperatures although CO2 saturated further through the pre-fracture. The unjointed models produced similar results to the low-permeability jointed models.