Matrix permeability and flow-derived DFN constrain reactivated natural fracture rupture area and stress drop — Marcellus Shale microseismic example

2021 ◽  
Vol 40 (9) ◽  
pp. 667-676
Author(s):  
Clay Kurison ◽  
Huseyin S. Kuleli
Keyword(s):  
Fluid Flow ◽  
Pore Pressure ◽  
Stress Drop ◽  
Marcellus Shale ◽  
Linear Flow ◽  
Matrix Permeability ◽  
Rupture Area ◽  
Microseismic Events ◽  
Shale Reservoirs ◽  
Stress Drops

Microseismic events associated with shale reservoir hydraulic fracturing stimulation (HFS) are interpreted to be reactivations of ubiquitous natural fractures (NFs). Despite adoption of discrete fracture network (DFN) models, accounting for NFs in fluid flow within shale reservoirs has remained a challenge. For an explicit account of NFs, this study introduced the use of seismology-based relations linking seismic moment, moment magnitude, fault rupture area, and stress drop. Microseismic data from HFS monitoring of Marcellus Shale horizontal wells had been used to derive planar hydraulic fracture geometry and source properties. The former was integrated with associated well production data found to exhibit transient linear flow. Analytical solutions led to linear flow parameters (LFPs) and system permeability for scenarios depicting flow through infinite and finite conductivity hydraulic fractures. Published core plug permeability was stress-corrected for in-situ conditions to estimate average matrix permeability. For comparison, the burial and thermal history for the study area was used in 1D Darcy-based modeling of steady and episodic expulsion of petroleum to account for geologic timescale persistence of abnormal pore pressure. Both evaluations resulted in matrix permeability in the same picodarcy (pD) range. Coupled with LFPs, reactivated NF surface area for stochastic DFNs was estimated. Subsequently, the aforementioned seismology-based relations were used for determining average stress drops needed to estimate NF rupture area matching flow-based DFN surface areas. Stress drops, comparable to values for tectonic events, were excluded. One of the determined values matched stress drops for HFS operations in past and recent seismological studies. In addition, calculated changes in pore pressure matched estimates in the aforementioned studies. This study unlocked the full potential of microseismic data beyond extraction of planar geometry attributes and stimulated reservoir volume (SRV). Here, microseismic events were explicitly used in the quantitative account of NFs in fluid flow within shale reservoirs.

Integration of Geoscience and Engineering Concepts to Account for Natural Fractures in Fluid Flow within Shale Reservoirs

2021 ◽  
Author(s):  
Clay Kurison ◽  
Ahmed M. Hakami ◽  
Sadi H. Kuleli
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Eagle Ford ◽  
Fracture Geometry ◽  
Ongoing Research ◽  
Linear Flow ◽  
Matrix Permeability ◽  
The Subject ◽  
Shale Reservoirs

Abstract Unconventional shale reservoirs are characterized by low porosity and ultra-low permeability. Natural fractures are known to be present and considered a critical factor for the enhanced post-stimulation productivity. Accounting for natural fractures with existing techniques has not been widely adopted owing to their complexity or lack of validation. Ongoing research efforts are striving to understand how natural fractures can be accounted for and accurately modeled in fluid flow of the subject reservoirs. This study utilized Eagle Ford well data comprising reservoir properties, stimulation metrics, production, microseismicity and permeability measurements from a core plug. The methodology comprised use of production data to extract a linear flow regime parameter. This was coupled with fracture geometry, predicted from hydraulic fracture modeling and microseismicity, to estimate the system permeability. From interpreting microseismic events as slips on critically stressed natural fractures, explicit modeling incorporating a discrete fracture network (DFN) assumed activated natural fractures supplement conductive reservoir contact area. Thus, allowed the estimation of matrix permeability. For validation, the aforementioned was compared with core plug permeability measurements. Results from modeling of planar hydraulic fractures, with microseismicity as validation, predicted planar fracture geometry which when coupled with the linear flow parameter resulted in a system permeability. Incorporation of DFNs to account for activated natural fractures yielded matrix permeability in picodarcy range. A review of laboratory permeability measurements exhibited stress dependence with the value at the maximum experimental confining pressure of 4000 psi in the same range as the computed system permeability. However, the confining pressures used in the experiments were less than the in situ effective stress. Correction for representative stress yielded an ultra-low matrix permeability in the same range as the DFN-based picodarcy matrix permeability. Thus, supporting the adopted drainage architecture and often suggested role of natural fractures in shale reservoir fluid flow. This study presents a multi-discipline workflow to account for natural fractures, and contributes to understanding that will improve laboratory petrophysics and the overall reservoir characterization of the subject reservoirs. Given that the Eagle Ford is an analogue of emerging shales elsewhere, results from this study can be widely adopted.

Using Rate Transient Analysis and Bayesian Algorithms for Reservoir Characterization in Unconventional Gas Wells during Linear Flow

2021 ◽  
pp. 1-19
Author(s):  
P. Yuhun ◽  
O. O. Awoleke ◽  
S. D. Goddard
Keyword(s):  
Hydraulic Fracturing ◽  
Marcellus Shale ◽  
Credible Interval ◽  
Production Data ◽  
Actual Case ◽  
Linear Flow ◽  
Fracture Length ◽  
Matrix Permeability ◽  
Rate Transient Analysis ◽  
Credible Intervals

Summary The main objective of this work is to improve robust, repeatable interpretation of reservoir characteristics using rate transient analysis (RTA). This is to generate probabilistic credible intervals for key reservoir and completion variables. This resulting data-driven algorithm was applied to production data from both synthetic and actual case histories. Synthetic production data from a multistage, hydraulically fractured horizontal completion in a reservoir modeled after the Marcellus Shale reservoir were generated using a reservoir model. The synthetic production data were analyzed using a combination of RTA and Bayesian techniques. First, the traditional log-log plot was produced to identify the linear flow production regime. Using the linear flow production data and traditional RTA equations, Bayesian inversion was carried out using two distinct Bayesian methods. The “rjags” and “EasyABC” packages in the open-source statistical software R were used for the traditional and approximate inversion, respectively. Model priors were based on (1) information available about the Marcellus Shale from technical literature and (2) results from a hydraulic fracturing forward model. Posterior distributions and credible intervals were produced for the fracture length, matrix permeability, and skin factor. These credible intervals were then compared with true reservoir and hydraulic fracturing data. The methodology was also repeated for an actual case in the Barnett shale. The most substantial finding was that for nearly all the investigated cases—including complicated scenarios (such as including finite fracture conductivity, fracturing fluid flowback, and heterogeneity in fracture length in the reservoir/hydraulic fracturing forward model)—the combined RTA-Bayesian model provided a 95% credible interval that encompassed the true values of the reservoir/hydraulic fracture parameters. We also found that the choice of the prior distribution did not affect the posterior distribution/credible interval in a significant manner as long as it was moderately concentrated and consistent with engineering science. Also, a comparison of the approximate Bayesian computation (ABC) and the traditional Bayesian algorithms showed that the ABC algorithm reduced computational time by at least an order of magnitude with minimal loss in accuracy. In addition, the production history used, the number of iterations, and the tolerance of fitting in the ABC analysis had a minimal impact on the posterior distribution after an optimal point, which were determined to be at least 1-year production history, 10,000 iterations, and 0.001, respectively. In summary, the RTA-Bayesian production analysis method was implemented using relatively user-friendly computational platforms [R and Excel® (Microsoft Corporation, Redmond, Washington, USA)]. This methodology provided reasonable characterization of all key variables such as matrix permeability, fracture length, and skin when compared to results obtained from analytical methods. This probabilistic characterization has the potential to enable better understanding of well performance ranges expected from shale gas wells. The methodology described here can also be generalized to shale oil systems during linear flow.

Fault modeling and stress drop estimation based on millimeter-scale tsunami records of an M6 earthquake detected by the dense and wide pressure gauge array

2020 ◽  
Author(s):  
Kubota Tatsuya ◽  
Tatsuhiko Saito ◽  
Wataru Suzuki
Keyword(s):  
Stress Drop ◽  
Pressure Gauge ◽  
Low Frequency ◽  
Fault Model ◽  
Rupture Area ◽  
Tsunami Earthquake ◽  
Off Sanriku ◽  
Stress Drops ◽  
Eastern Japan ◽  
Wide Pressure

<p>Tsunamis observed by offshore ocean-bottom pressure gauges have been used to infer fault models and stress drops for major (M > 7) offshore earthquakes, to understand the earthquake and tsunamigenesis (e.g., Satake et al. 2013). However, it is challenging to observe tsunamis due to moderate (M ~6) earthquakes with reasonable quality by those, previous, few and remote pressure gauge arrays. Recently, a new, dense and wide pressure gauge network, the Seafloor Observation Network for Earthquakes and Tsunamis along the Japan Trench (S-net), was constructed off eastern Japan (Kanazawa et al. 2016). This array observed tsunamis associated with a moderate (M~6) earthquake which occurred inside the array, with amplitudes of less than one cm. We analyzed these millimeter-scale tsunami records to infer the finite fault model and stress drop, and to examine its relationship with other interplate earthquake phenomena.</p><p>We analyzed the pressure data associated with an Mw 6.0 earthquake off Sanriku on August 20, 2016. This earthquake was located at the shallowest part of the plate boundary off Sanriku, Japan, near the northern edge of the rupture area of the 1896 Sanriku tsunami earthquake (Kanamori, 1972). Although the signal-to-noise ratio is not high, the westward tsunami propagation with the velocity of ~0.1 km/s could be recognized when the waveforms were aligned according to the station locations. Using these data, we constrained the rectangular fault model with a uniform slip across the fault. As a result, the fault model was located ~10 km to the west of the Global CMT centroid (a seismic moment M<sub>0</sub>= 1.4 × 10<sup>18</sup> Nm, Mw 6.0, and a stress drop of Δσ = 1.5 MPa). The stress drop seems not so small as expected in tsunami earthquakes such as the 1896 Sanriku tsunami earthquake (≪ ~1 MPa, e.g., Kanamori 1972) even if the uncertainty of the stress drop estimation is considered (Δσ > ~ 0.7 MPa). We also found the rupture area was unlikely to overlap with regions where slow earthquakes are active, such as low-frequency-tremors and very-low-frequency-earthquakes (e.g., Matsuzawa et al. 2015; Nishikawa et al. 2019; Tanaka et al. 2019).</p><p>This result demonstrates that the S-net new dense and wide pressure gauge array dramatically increases the detectability of a millimeter-scale tsunami and the constraints on earthquake source parameters of moderate earthquakes off eastern Japan. It is expected that more tsunamis due to minor-to-moderate offshore earthquakes are recorded by this new array, which will reveal the spatial variation of the stress drops, or mechanical properties, along the plate interface with much higher resolution than previously possible.</p>

Microseismicity caused by injection of water in a gas-saturated reservoir

Geophysics ◽  
2019 ◽  
Vol 84 (6) ◽  
pp. KS183-KS189
Author(s):  
Lucas A. Macias ◽  
Juan E. Santos ◽  
Gabriela B. Savioli ◽  
José M. Carcione
Keyword(s):  
Fluid Flow ◽  
Pore Pressure ◽  
Fluid Transport ◽  
Water Saturation ◽  
Water Injection ◽  
Rock Properties ◽  
Partial Saturation ◽  
Two Phase ◽  
Initial Water ◽  
Microseismic Events

Microseismic events along preexisting zones of weakness occur in a reservoir due to pore pressure buildup and fracturing during fluid injection. We have used a multiphase fluid-flow numerical simulator to model water injection in a gas reservoir. Previous studies generally consider a single fluid, in which the relative permeabilities and capillary pressure play no role. We analyze the effects of partial saturation on the injection process. On the basis of a spatial distribution of weak stress zones and a threshold pore pressure, the simulator models fluid transport in the formation and allows us to obtain the spatiotemporal distribution of the microseismic events. We consider uniform and fractal distributions of the pore pressure at which microearthquakes are triggered. We analyze the influence of the initial water saturation and the presence of preexisting natural fractures, as well as the effect of updating the rock properties after the microseismic events occur. Moreover, we perform simulations in a low-permeability reservoir in which the borehole pressure increment generates a system of fractures that propagate into the reservoir. The importance of considering two-phase fluid flow resides in the fact that partial saturation greatly affects the trigger time evolution. This is mainly due to the difference in compressibility of the two phases.

Source dimensions and stress drops of small earthquakes near Parkfield, California

1984 ◽  
Vol 74 (1) ◽  
pp. 27-40
Author(s):  
M. E. O'Neill
Keyword(s):  
Stress Drop ◽  
Small Region ◽  
Static Stress ◽  
Depth Range ◽  
Zero Crossing ◽  
Source Dimensions ◽  
Duration Magnitude ◽  
Short Period ◽  
Static Stress Drop ◽  
Stress Drops

Abstract Source dimensions and stress drops of 30 small Parkfield, California, earthquakes with coda duration magnitudes between 1.2 and 3.9 have been estimated from measurements on short-period velocity-transducer seismograms. Times from the initial onset to the first zero crossing, corrected for attenuation and instrument response, have been interpreted in terms of a circular source model in which rupture expands radially outward from a point until it stops abruptly at radius a. For each earthquake, duration magnitude MD gave an estimate of seismic moment MO and MO and a together gave an estimate of static stress drop. All 30 earthquakes are located on a 6-km-long segment of the San Andreas fault at a depth range of about 8 to 13 km. Source radius systemically increases with magnitude from about 70 m for events near MD 1.4 to about 600 m for an event of MD 3.9. Static stress drop ranges from about 2 to 30 bars and is not strongly correlated with magnitude. Static stress drop does appear to be spatially dependent; the earthquakes with stress drops greater than 20 bars are concentrated in a small region close to the hypocenter of the magnitude 512 1966 Parkfield earthquake.

Rotation of the principal stress directions due to earthquake faulting and its seismological implications

1995 ◽  
Vol 85 (5) ◽  
pp. 1513-1517
Author(s):  
Z.-M. Yin ◽  
G. C. Rogers
Keyword(s):  
Shear Stress ◽  
Normal Stress ◽  
Principal Stress ◽  
Stress Drop ◽  
Rotation Angle ◽  
Overburden Pressure ◽  
Rupture Area ◽  
Earthquake Faulting ◽  
Stress Directions ◽  
Before And After

Abstract Earthquake faulting results in stress drop over the rupture area. Because the stress drop is only in the shear stress and there is no or little stress drop in the normal stress on the fault, the principal stress directions must rotate to adapt such a change of the state of stress. Using two constraints, i.e., the normal stress on the fault and the vertical stress (the overburden pressure), which do not change before and after the earthquake, we derive simple expressions for the rotation angle in the σ1 axis. For a dip-slip earthquake, the rotation angle is only a function of the stress-drop ratio (defined as the ratio of the stress drop to the initial shear stress) and the angle between the σ1 axis and the fault plane, but for a strike-slip earthquake the rotation angle is also a function of the stress ratio. Depending on the faulting regimes, the σ1 axis can either rotate toward the direction of fault normal or rotate away from the direction of fault normal. The rotation of the stress field has several important seismological implications. It may play a significant role in the generation of heterogeneous stresses and in the occurrence and distribution of aftershocks. The rotation angle can be used to estimate the stress-drop ratio, which has been a long-lasting topic of debate in seismology.

An Optimized Experimental Investigation of Foam-Assisted N2 Huff-n-Puff Enhanced Oil Recovery in Fractured Shale Cores

2021 ◽  
Author(s):  
Xiaofei Xiong ◽  
James Jia Sheng
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Rapid Decline ◽  
Production Time ◽  
Experimental Conditions ◽  
Cycle Number ◽  
Injection Process ◽  
Matrix Permeability ◽  
Shale Reservoirs ◽  
Scale Matrix

Abstract Sustainable development of shale reservoirs and enhanced oil recovery have become a challenge for the oil industry in recent years. Shale reservoirs are typically characterized by nano Darcy-scale matrix, natural fractures, and artificially fractures with high permeability. Some of earlier studies have confirmed that gas huff-n-puff has been investigated and demonstrated as the most effective and promising solution for improving oil recovery in tight shale reservoirs with ultra-low permeability. Fractures provide an advantage in enhancing recovery from shale reservoirs but they also pose serious problems such as severe gas channeling, which led to rapid decline production from a single well. More studies are needed to optimize the process. This paper studies the method of foam-assisted N2 huff-n-puff to enhance oil recovery in fractured shale cores. The influence of foam on oil recovery was analyzed. The effect of matrix permeability, cycle number and production time on oil recovery are also considered. The shale core used in the experiment was from Sichuan Basin, China. For the purpose of comparation and validation, two groups of tests were conducted. One group of tests was N2 huff-n-puff, and the other was foam-N2 huff-n-puff. In the optimization experiment, matrix permeabilities were set as 0.01mD, 0.008mD and 0.001mD, cycle numbers ranged from one to five, the production time is designed to be 1 hour and 24 hours respectively. During the puff period of experiments, the history of oil recovery was closely monitored to reveal the mechanism. During a round of gas injection of fractured shale cores, foam-assisted N2 huff-n-puff oil recovery is 4.59%, which is significantly higher than that of N2 huff-n-puff is only 0.0126%, and the contrast becomes more obvious with the increase of matrix permeability. The results also showed that the cumulative oil recovery increased as the number of cycles was increased, with the same experimental conditions. There is an optimal production time to achieve maximum oil recovery. The cycle numbers, matrix permeability, and production time played important roles in foam-assisted N2 huff-n-puff injection process. Therefore, under certain conditions, foam-N2 huff-n-puff has a positive effect on oil development in fractured shale.

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