Role of fracture opening in triggering microseismicity observed during hydraulic fracturing

Geophysics ◽  
2019 ◽  
Vol 84 (3) ◽  
pp. KS105-KS118 ◽  
Author(s):  
Himanshu Barthwal ◽  
Mirko van der Baan
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Material Balance ◽  
Crack Tip ◽  
Hydrocarbon Reservoirs ◽  
Fluid Injection ◽  
Low Permeability ◽  
Stress Shadow ◽  
Pressure Diffusion ◽  
Microseismic Events

Hydraulic fracturing in low-permeability hydrocarbon reservoirs creates/reactivates a fracture network leading to microseismic events. We have developed a simplified model of the evolution of the microseismic cloud based on the opening of a planar fracture cavity and its effect on elastic stresses and pore pressure diffusion during fluid injection in hydraulic fracturing treatments. Using a material balance equation, we compute the crack tip propagation over time assuming that the hydraulic fracture is shaped as a single penny-shaped cavity. Results indicate that in low-permeability formations, the crack tip propagates much faster than the pore pressure diffusion front thereby triggering the microseismic events farthest from the injection domain at any given time during fluid injection. We use the crack tip propagation to explain the triggering front observed in distance versus time plots of published microseismic data examples from hydraulic fracturing treatments of low-permeability hydrocarbon reservoirs. We conclude that attributing the location of the microseismic triggering front purely to pore pressure diffusion from the injection point may lead to incorrect estimates of the hydraulic diffusivity by multiple orders of magnitude for low-permeability formations. Moreover, the opening of the fracture cavity creates stress shadow zones perpendicular to the principal fracture walls in which microseismic triggering due to the elastic stress perturbations is suppressed. Microseismic triggering in this stress shadow region may be attributed mainly to pore pressure diffusion. We use the width, instead of the longest size, of the microseismic cloud to obtain an enhanced diffusivity measure, which may be useful for subsequent production simulations.

Latent seismicity driven by aseismic creep and enhanced pore-fluid pressure in NE British Columbia

2021 ◽  
Author(s):  
Rebecca O. Salvage ◽  
David W. Eaton
Keyword(s):  
British Columbia ◽  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Fluid Pressure ◽  
Fluid Injection ◽  
Maximum Magnitude ◽  
Dynamic Triggering ◽  
Global Pandemic ◽  
Pressure Diffusion ◽  
Montney Formation

<p>The global pandemic of COVID-19 furnished an opportunity to study seismicity in the Kiskatinaw area of British Columbia, noted for hydraulic-fracturing induced seismicity, during a period of anthropogenic quiescence. A total of 389 events were detected from April to August 2020, encompassing a period with no hydraulic-fracturing operations during a government-imposed lockdown. During this time period, observed seismicity had a maximum magnitude of M<sub>L</sub> 1.2 and lacked temporal clustering that is often characteristic of hydraulic-fracturing induced sequences. Instead, seismicity was persistent over the lockdown period, similar to swarm-like seismicity with no apparent foreshock-aftershock type sequences. Hypocenters occurred within a corridor orientated NW-SE, just as seismicity had done in previous years in the area, with focal depths near the target Montney formation or shallower (<2.5 km). Based on the Gutenberg-Richter relationship, we estimate that a maximum of 21% of the detected events during lockdown may be attributable to natural seismicity, with a further 8% possibly due to dynamic triggering of seismicity from teleseismic events. The remaining ~70% cannot be attributed to direct pore pressure increases induced by fluid injection, and therefore is inferred to represent latent seismicity i.e. seismicity that occurs after an unusually long delay following primary activation processes, with no obvious triggering mechanism. We can exclude pore-pressure diffusion from the most recent fluid injection, as is there is no clear pattern of temporal or spatial seismicity migration. If elevated pore pressure from previous injections became trapped in the subsurface, this could explain the localization of seismicity within an operational corridor, but it does not explain the latency of seismicity on a timescale of months. However, aseismic creep on weak surfaces such as faults, in response to tectonic stresses, in addition to trapped elevation pore-pressure could play a role in stress re-loading to sustain the observed pattern of seismicity.</p>

The role of preexisting fractures and faults during multistage hydraulic fracturing in the Bakken Formation

2014 ◽  
Vol 2 (3) ◽  
pp. SG25-SG39 ◽  
Author(s):  
Yi Yang ◽  
Mark D. Zoback
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Well Being ◽  
Williston Basin ◽  
Bakken Formation ◽  
Multistage Hydraulic Fracturing ◽  
Geomechanical Analysis ◽  
Microseismic Events ◽  
Observation Wells

We performed an integrated study of multistage hydraulic fracture stimulation of two parallel horizontal wells in the Bakken Formation in the Williston Basin, North Dakota. There are three distinct parts of this study: development of a geomechanical model for the study area, interpretation of multiarray downhole recordings of microseismic events, and interpretation of hydraulic fracturing data in a geomechanical context. We estimated the current stress state to be characterized by an NF/SS regime, with [Formula: see text] oriented approximately [Formula: see text]. The microseismic events were recorded in six vertical observation wells during hydraulic fracturing of parallel wells X and Z with three unusual aspects. First, rather than occurring in proximity to the stages being pressurized, many of the events occurred along the length of well Y, a parallel well located between wells X and Z that had been in production for approximately [Formula: see text] years at the time X and Z were stimulated. Second, relatively few fracturing stages were associated with an elongated cloud of events trending in the direction of [Formula: see text] as was commonly observed during hydraulic fracturing. Instead, the microseismic events in a few stages appeared to trend approximately [Formula: see text], approximately 30° from the direction of [Formula: see text]. Earthquake focal plane mechanisms confirmed slip on faults with this orientation. Finally, the microseismic events were clustered at two distinct depths: one near the depth of the well being pressurized in the Middle Bakken Formation and the other approximately [Formula: see text] above in the Mission Canyon Formation. We proposed that steeply dipping N75°E striking faults with a combination of normal and strike-slip movement were being stimulated during hydraulic fracturing and provided conduits for pore pressure to be transmitted to the overlaying formations. We tested a simple geomechanical analysis to illustrate how this occurred in the context of the stress field, pore pressure, and depletion in the vicinity of well Y.

Coupling poroelastic stress change and rate-state fault slip models to simulate fluid injection induced seismic and aseismic slip

2020 ◽  
Author(s):  
Yajing Liu ◽  
Alessandro Verdecchia ◽  
Kai Deng ◽  
Rebecca Harrington
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Fault Slip ◽  
Stress Change ◽  
Fluid Injection ◽  
Coulomb Stress ◽  
Aseismic Slip ◽  
Injection Wells ◽  
Wastewater Disposal ◽  
Stress Changes

<p>Fluid injection in unconventional hydrocarbon resource exploration can introduce poroelastic stress and pore pressure changes, which in some cases may lead to aseismic slip on pre-existing fractures or faults. All three processes have been proposed as candidates for inducing earthquakes up to 10s of kilometers from injection wells. In this study, we examine their relative roles in triggering fault slip under both wastewater disposal and hydraulic fracturing scenarios. We first present modeling results of poroelastic stress changes on a previously unmapped fault near Cushing, Oklahoma, due to injection at multiple wastewater disposal wells within ~ 10 km of distance, where over 100 small to moderate earthquakes were reported between 2015/09 to 2016/11 including a Mw5.0 event at the end of the sequence. Despite the much larger amplitude of pore pressure change, we find that earthquake hypocenters are well correlated with positive shear stress change, which dominates the regimes of positive Coulomb stress change encouraging failure. Depending on the relative location of the disposal well to the recipient fault and its sense of motion, fluid injection can introduce either positive or negative Coulomb stress changes, therefore promoting or inhibiting seismicity. Our results suggest that interaction between multiple injection wells needs to be considered in induced seismicity hazard assessment, particularly for areas of dense well distributions. Next, we plan to apply the model to simulate poroelastic stress changes due to multi-stage hydraulic fracturing wells near Dawson Creek, British Columbia, where a dense local broadband seismic array has been in operation since 2016. We will investigate the relative amplitudes, time scales, and spatial ranges of pore pressure versus solid matrix stress changes in influencing local seismicity.</p><p>Finally, we have developed a rate-state friction framework for calculating slip on a pre-existing fault under stress perturbations for both the disposal and hydraulic fracturing cases. Preliminary fault slip simulation results suggest that fault response (aseismic versus seismic) highly depends on 1) the relative timing in the intrinsic earthquake cycle (under tectonic loading) when the stress perturbation is introduced, 2) the amplitude of the perturbation relative to the background fault stress state, and 3) the duration of the perturbation relative to the “memory” timescale governed by the rate-state properties of the fault. Our modeling results suggest the design of injection parameters could be critical for preventing the onset of seismic slip.</p>

Simulation of proppant transport and fracture plugging in the framework of a radial hydraulic fracturing model

2020 ◽  
Vol 35 (6) ◽  
pp. 325-339
Author(s):  
Vasily N. Lapin ◽  
Denis V. Esipov
Keyword(s):  
Numerical Model ◽  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Oil And Gas Industry ◽  
Injection Rate ◽  
Fluid Injection ◽  
Subtraction Technique ◽  
Gas Industry ◽  
Proppant Transport ◽  
Hydraulic Fracture Propagation

AbstractHydraulic fracturing technology is widely used in the oil and gas industry. A part of the technology consists in injecting a mixture of proppant and fluid into the fracture. Proppant significantly increases the viscosity of the injected mixture and can cause plugging of the fracture. In this paper we propose a numerical model of hydraulic fracture propagation within the framework of the radial geometry taking into account the proppant transport and possible plugging. The finite difference method and the singularity subtraction technique near the fracture tip are used in the numerical model. Based on the simulation results it was found that depending on the parameters of the rock, fluid, and fluid injection rate, the plugging can be caused by two reasons. A parameter was introduced to separate these two cases. If this parameter is large enough, then the plugging occurs due to reaching the maximum possible concentration of proppant far from the fracture tip. If its value is small, then the plugging is caused by the proppant reaching a narrow part of the fracture near its tip. The numerical experiments give an estimate of the radius of the filled with proppant part of the fracture for various injection rates and leakages into the rock.

Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 397-407 ◽  
Author(s):  
Mashhad Mousa Fahes ◽  
Abbas Firoozabadi
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
High Temperatures ◽  
Gas Production ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Absolute Permeability ◽  
Low Permeability ◽  
Gas Well ◽  
Water Blocking

Summary Wettability of two types of sandstone cores, Berea (permeability on the order of 600 md), and a reservoir rock (permeability on the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90C. In this work, chemicals previously used at 90C for wettability alteration are found to be ineffective at 140C. New chemicals are used which alter wettability at high temperatures. The results show that:wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures,wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions,wettability alteration results in improved gas productivity, andwettability alteration does not have a measurable effect on the absolute permeability of the rock for some chemicals. We also find the reservoir rock, unlike Berea, is not strongly water-wet in the gas/water/rock system. Introduction A sharp reduction in gas well deliverability is often observed in many low-permeability gas-condensate reservoirs even at very high reservoir pressure. The decrease in well deliverability is attributed to condensate accumulation (Hinchman and Barree 1985; Afidick et al. 1994) and water blocking (Engineer 1985; Cimolai et al. 1983). As the pressure drops below the dewpoint, liquid accumulates around the wellbore in high saturations, reducing gas relative permeability (Barnum et al. 1995; El-Banbi et al. 2000); the result is a decrease in the gas production rate. Several techniques have been used to increase gas well deliverability after the initial decline. Hydraulic fracturing is used to increase absolute permeability (Haimson and Fairhurst 1969). Solvent injection is implemented in order to remove the accumulated liquid (Al-Anazi et al. 2005). Gas deliverability often increases after the reduction of the condensate saturation around the wellbore. In a successful methanol treatment in Hatter's Pond field in Alabama (Al-Anazi et al. 2005), after the initial decline in well deliverability by a factor of three to five owing to condensate blocking, gas deliverability increased by a factor of two after the removal of water and condensate liquids from the near-wellbore region. The increased rates were, however, sustained for a period of 4 months only. The approach is not a permanent solution to the problem, because the condensate bank will form again. On the other hand, when hydraulic fracturing is used by injecting aqueous fluids, the cleanup of water accumulation from the formation after fracturing is essential to obtain an increased productivity. Water is removed in two phases: immiscible displacement by gas, followed by vaporization by the expanding gas flow (Mahadevan and Sharma 2003). Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2003; Penny et al. 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al. 1989; Sognesand 1991; Baig et al. 2005).

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

2021 ◽  
Vol 8 ◽  
pp. 55-79
Author(s):  
E. Bakhshi ◽  
A. Shahrabadi ◽  
N. Golsanami ◽  
Sh. Seyedsajadi ◽  
X. Liu ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Pore Pressure ◽  
Earth Model ◽  
Reservoir Properties ◽  
Stress Regime ◽  
Geomechanical Properties ◽  
Hydrocarbon Reservoir ◽  
Diagenetic Processes ◽  
Mechanical Earth Model ◽  
New Equation

The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.  

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