Study on the ratio of pore-pressure/stress changes during fluid injection and its implications for CO2 geologic storage

<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 &#8220;memory&#8221; 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>

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Pore Pressure/Stress Coupling and its Implications for Seismicity

Exploration Geophysics ◽

10.1071/eg00448 ◽

2000 ◽

Vol 31 (1-2) ◽

pp. 448-454 ◽

Cited By ~ 68

Author(s):

Richard Hillis

Keyword(s):

Pore Pressure ◽

Pressure Stress

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A Model of Pore Pressure and Effective Stress Changes During Hydrocarbon Depletion by Slowness Integrated Data Analysis

On Significant Applications of Geophysical Methods - Advances in Science, Technology & Innovation ◽

10.1007/978-3-030-01656-2_36 ◽

2019 ◽

pp. 161-163 ◽

Cited By ~ 1

Author(s):

Kurniawan Adha ◽

Wan Ismail Wan Yusoff ◽

Luluan Almanna Lubis

Keyword(s):

Data Analysis ◽

Pore Pressure ◽

Effective Stress ◽

Stress Changes ◽

Integrated Data Analysis

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Dynamic Modeling of Channel Formation During Fluid Injection Into Unconsolidated Formations

SPE Journal ◽

10.2118/173891-pa ◽

2015 ◽

Vol 20 (04) ◽

pp. 689-700 ◽

Cited By ~ 5

Author(s):

S.. Ameen ◽

A. Dahi Taleghani

Keyword(s):

Preferential Flow ◽

Volume Fraction ◽

Injection Pressure ◽

Internal Erosion ◽

Fluid Injection ◽

Critical Threshold ◽

Model Parameters ◽

Flow Paths ◽

Preferential Flow Paths ◽

Stress Changes

Summary Injectivity loss is a common problem in unconsolidated-sand formations. Injection of water into a poorly cemented granular medium may lead to internal erosion, and consequently formation of preferential flow paths within the medium because of channelization. Channelization in the porous medium might occur when fluid-induced stresses become locally larger than a critical threshold and small grains are dislodged and carried away; hence, porosity and permeability of the medium will evolve along the induced flow paths. Vice versa, flowback during shut-in might carry particles back to the well and cause sand accumulation inside the well, and subsequently loss of injectivity. In most cases, to maintain the injection rate, operators will increase injection pressure and pumping power. The increased injection pressure results in stress changes and possibly further changes in channel patterns around the wellbore. Experimental laboratory studies have confirmed the presence of the transition from uniform Darcy flow to a fingered-pattern flow. To predict these phenomena, a model is needed to fill this gap by predicting the formation of preferential flow paths and their evolution. A model based on the multiphase-volume-fraction concept is used to decompose porosity into mobile and immobile porosities where phases may change spatially, evolve over time, and lead to development of erosional channels depending on injection rates, viscosity, and rock properties. This model will account for both particle release and suspension deposition. By use of this model, a methodology is proposed to derive model parameters from routine injection tests by inverse analysis. The proposed model presents the characteristic behavior of unconsolidated formation during fluid injection and the possible effect of injection parameters on downhole-permeability evolution.

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Pore Pressure, Stress Distributions, and Instantaneous Liquefaction of Two-Layer Soil under Waves

Journal of Waterway Port Coastal and Ocean Engineering ◽

10.1061/(asce)ww.1943-5460.0000155 ◽

2012 ◽

Vol 138 (6) ◽

pp. 435-450 ◽

Cited By ~ 23

Author(s):

M. B. Can Ulker

Keyword(s):

Pore Pressure ◽

Stress Distributions ◽

Pressure Stress

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The role of geomechanical modeling in the measurement and understanding of geophysical data collected during carbon sequestration

The Leading Edge ◽

10.1190/tle40060413.1 ◽

2021 ◽

Vol 40 (6) ◽

pp. 413-417

Author(s):

Chunfang Meng ◽

Michael Fehler

Keyword(s):

Pore Pressure ◽

Fault Location ◽

Mechanical Response ◽

Fluid Pressure ◽

Geophysical Data ◽

Fluid Injection ◽

Coupled Flow ◽

Cap Rock ◽

Stress And Deformation ◽

Pressure Changes

As fluids are injected into a reservoir, the pore fluid pressure changes in space and time. These changes induce a mechanical response to the reservoir fractures, which in turn induces changes in stress and deformation to the surrounding rock. The changes in stress and associated deformation comprise the geomechanical response of the reservoir to the injection. This response can result in slip along faults and potentially the loss of fluid containment within a reservoir as a result of cap-rock failure. It is important to recognize that the slip along faults does not occur only due to the changes in pore pressure at the fault location; it can also be a response to poroelastic changes in stress located away from the region where pore pressure itself changes. Our goal here is to briefly describe some of the concepts of geomechanics and the coupled flow-geomechanical response of the reservoir to fluid injection. We will illustrate some of the concepts with modeling examples that help build our intuition for understanding and predicting possible responses of reservoirs to injection. It is essential to understand and apply these concepts to properly use geomechanical modeling to design geophysical acquisition geometries and to properly interpret the geophysical data acquired during fluid injection.

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Experimental Investigation of Depletion- and Injection-Induced Changes in Poromechanical, Transport, and Strength Properties of High-Porosity Sandstone

SPE Journal ◽

10.2118/205364-pa ◽

2021 ◽

pp. 1-21

Author(s):

Saeed Rafieepour ◽

Stefan Z. Miska ◽

Evren M. Ozbayoglu ◽

Nicholas E. Takach ◽

Mengjiao Yu ◽

...

Keyword(s):

Pore Pressure ◽

Effective Stress ◽

Microstructural Analysis ◽

Optical Microscope ◽

Strength Properties ◽

Rock Properties ◽

Absolute Permeability ◽

High Porosity ◽

Confining Stress ◽

Stress Changes

Summary In this paper, an extensive series of experiments was performed to investigate the evolution of poromechanical (dry, drained, undrained, and unjacketed moduli), transport (permeability), and strength properties during reservoir depletion and injection in a high-porosity sandstone (Castlegate). An overdetermined set of eight poroelastic moduli was measured as a function of confining pressure (Pc) and pore pressure (Pp). The results showed larger effect on pore pressure at low Terzaghi’s effective stress (nonlinear trend) during depletion and injection. Moreover, the rock sample is stiffer during injection than depletion. At the same Pc and Pp, Biot’s coefficient and Skempton’s coefficient are larger in depletion than injection. Under deviatoric loading, absolute permeability decreased by 35% with increasing effective confining stress up to 20.68 MPa. Given these variations in rock properties, modeling of in-situ-stress changes using constant properties could attain erroneous predictions. Moreover, constant deviatoric stress-depletion/injection failure tests showed no changes or infinitesimal variations of strength properties with depletion and injection. It was found that failure of Castlegate sandstone is controlled by simple effective stress, as postulated by Terzaghi. Effective-stress coefficients at failure (effective-stress coefficient for strength) were found to be close to unity (actual numbers, however, were 1.03 for Samples CS-5 and CS-9 and 1.04 for Sample CS-10). Microstructural analysis of Castlegate sandstone using both scanning electron microscope (SEM) and optical microscope revealed that the changes in poroelastic and transport properties as well as the significant hysteresis between depletion and injection are attributed to the existence and distribution of compliant components such as pores, microcracks, and clay minerals.

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Role of fracture opening in triggering microseismicity observed during hydraulic fracturing

Geophysics ◽

10.1190/geo2018-0425.1 ◽

2019 ◽

Vol 84 (3) ◽

pp. KS105-KS118 ◽

Cited By ~ 3

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.

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Fluid-induced aseismic fault slip outpaces pore-fluid migration

Science ◽

10.1126/science.aaw7354 ◽

2019 ◽

Vol 364 (6439) ◽

pp. 464-468 ◽

Cited By ~ 36

Author(s):

Pathikrit Bhattacharya ◽

Robert C. Viesca

Keyword(s):

Pore Fluid ◽

Fluid Injection ◽

Fluid Migration ◽

Aseismic Slip ◽

Earthquake Triggering ◽

Effective Normal Stress ◽

Shear Rupture ◽

Stress Changes ◽

Slip History ◽

Rupture Model

Earthquake swarms attributed to subsurface fluid injection are usually assumed to occur on faults destabilized by increased pore-fluid pressures. However, fluid injection could also activate aseismic slip, which might outpace pore-fluid migration and transmit earthquake-triggering stress changes beyond the fluid-pressurized region. We tested this theoretical prediction against data derived from fluid-injection experiments that activated and measured slow, aseismic slip on preexisting, shallow faults. We found that the pore pressure and slip history imply a fault whose strength is the product of a slip-weakening friction coefficient and the local effective normal stress. Using a coupled shear-rupture model, we derived constraints on the hydromechanical parameters of the actively deforming fault. The inferred aseismic rupture front propagates faster and to larger distances than the diffusion of pressurized pore fluid.

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