Characterize Fracture Development Through Strain Rate Measurements by Distributed Acoustic Sensor DAS

In multistage hydraulic fracturing treatments, the combination of extreme large-scale pumping (high rate and volume) and the high heterogeneity of the formation (because of large contact area) normally results in complex fracture growth that cannot be simply modeled with conventional fracture models. Lack of understanding of the fracturing mechanism makes it difficult to design and optimize hydraulic fracturing treatments. Many monitoring, testing and diagnosis technologies have been applied in the field to describe hydraulic fracture development. Strain rate measured by distributed acoustic sensor (DAS) is one of the tools for fracture monitoring in complex completion scenarios. DAS measures far-field strain rate that can be of assistance for fracture characterization, cross-well fracture interference identification, and well stimulation efficiency evaluation. Many field applications have shown DAS responses on observation wells or surrounding producers when a well in the vicinity is fractured. Modeling and interpreting DAS strain rate responses can help quantitatively map fracture propagation. In this work, a methodology is developed to generate the simulated strain-rate responds to assumed fracture systems. The physical domain contains a treated well that the generate strain variation in the domain because of fracturing, and an observation well that has fiber-optic sensor installed along it to measure the strain rate responses to the fracture propagation. Instead of using a complex fracture model to forward simulate fracture propagation, this work starts from a simple 2D fracture propagation model to provide hypothetical fracture geometries in a relatively reasonable and acceptable range for both single fracture case and multiple fracture case. Displacement discontinuity method (DDM) is formulated to simulate rock deformation and strain rate responds on fiber-optic sensors. At each time step, fracture propagation is first allowed, then stress, displacement and strain field are estimated as the fracture approaches to the observation well. Afterward, the strain rate is calculated as fracture growth to generate patterns as fracture approaching. Extended simulation is conducted to monitor fracture propagation and strain rate responses. The patterns of strain rate responses can be used to recognize fracture development. Examples of strain rate responses for different fracturing conditions are presented in this paper. The relationship of injection rate distribution and strain rate responses is investigated to show the potential of using DAS measurements to diagnose multistage hydraulic fracturing treatments.

Optimization of hydraulic fracturing treatment in tight sand reservoir of lower indus basin: an integrated approach

An approach for post-frac production profiling has been presented in this study by integrating a fracture model with a reservoir simulation model for a well drilled in tight sand reservoir of Lower Indus Basin in Pakistan. The presented integrated approach couples the output from the fracture growth model with a reservoir simulation model to effectively predict the behavior of a fractured reservoir. Optimization of hydraulic fracturing was done efficiently through the work presented in this study. The integrated model was used to perform various sensitivities. The production profiles obtained for each case were subsequently used to determine the most profitable case, using an economic model.

Combined Proppant Placement and Early Production Modeling Achieve Increased Fracture Performance in Ecuador's Oriente Basin

In the paper, we document one iteration of the continuous improvement of well performance undertaken in the Oriente Basin in Ecuador. In the past, it had been observed that well economics was sometimes degraded by the issues related to proppant flowback from hydraulic fractures. Proppant flowback resulted in extra costs from well cleanouts, pump replacement, and damage to fracture conductivity. After evaluation of proppant flowback cases using the combined modeling workflow that simulates fracture growth, proppant placement, and early production of solids and fluids, it had been proposed to modify fracture designs and well startup strategy. In this paper, we review the first results of implementation of these modifications in the field and evaluate the significance of improvements.

Stratigraphically Controlled Stress Variations at the Hydraulic Fracture Test Site-1 in the Midland Basin, TX

We investigated the relationship between stratigraphy, stress, and microseismicity at the Hydraulic Fracture Test Site-1. The site comprises two sets of horizontal wells in the Wolfcamp shale and a deviated well drilled after hydraulic fracturing. Regional stresses indicate normal/strike-slip faulting with E-W compression. Stress measurements in vertical and horizontal wells show that the minimum principal stress varies with depth. Strata with high clay and organic content show high values of the least compressive stress, consistent with the theory of viscous stress relaxation. By integrating data from core, logs, and the hydraulic fracturing stages, we constructed a stress profile for the Wolfcamp sequence, which predicts how much pressure is required for hydraulic fracture growth. We applied the results to fracture orientation data from image logs to determine the population of pre-existing faults that are expected to slip during stimulation. We also determined microseismic focal plane mechanisms and found slip on steeply dipping planes striking NW, consistent with the orientations of potentially active faults predicted by the stress model. This case study represents a general approach for integrating stress measurements and rock properties to predict hydraulic fracture growth and the characteristics of injection-induced microseismicity.

Joint microseismic moment tensor inversion and location using P- and S-waves diffraction stacking

The microseismic location methods based on diffraction stacking which does not require arrival picking can yield accurate and reliable source location for data with a low signal-to-noise ratio. However, due to the complex radiation pattern from a rupturing source, variation in the waveform polarities brings challenges to the diffraction-stacking based methods. The current implementations of joint source mechanism inversion and location methods which only use P-wave amplitudes have limitations in noise resistance and location accuracy. To mitigate those issues, we develop a new method for joint microseismic moment tensor inversion and event location using diffraction stacking with P- and S-waves amplitudes, both of which are used to invert for the moment tensor of a microseismic event, and then the inverted moment tensor is used to correct the waveform polarity changes before stacking. In addition, to expedite the large amount of calculations required for moment tensor inversion at each potential source position and origin time, we develop an optimized grid search scheme and implement the algorithm with GPUs. The proposed location method does not require manual picking of the first arrivals, and can automatically detect and locate microseismic events from continuous data. We first validated the method with two synthetic examples, and then applied it to a surface monitoring dataset for hydraulic fracturing at a shale gas well pad in the southern Sichuan Basin, China, where billions of cubic meters of shale gas are being produced annually. The locations of the microseismic events are nicely correlated with the fracturing stages and the determined source mechanisms are also consistent with the expected fracture growth. The proposed method is feasible for microseismic surface monitoring with dense nodal arrays and can provide important information for fracture growth and regional stress characterization.