scholarly journals The role of fault offset in induced seismicity potential

2020 ◽  
Author(s):  
Victor Vilarrasa ◽  
Francesco Parisio ◽  
Roman Makhnenko ◽  
Haiqing Wu ◽  
Iman Rahimzadeh Kivi
Keyword(s):  
Induced Seismicity ◽  
Reservoir Rock ◽  
Fluid Injection ◽  
Low Permeability ◽  
Total Stress ◽  
Element Analysis ◽  
Stress Regime ◽  
Fault Stability ◽  
Stress Changes ◽  
Base Rock

<p>Geological media is envisioned as a strategic resource to store large volumes of CO<sub>2</sub> and mitigate climate change. Geo-energy applications, such as geologic carbon storage, geothermal energy, and subsurface energy storage, involve injection and extraction of fluids that cause pressure diffusion. Pore pressure changes may induce seismicity, especially in faults that intersect the injection formation or are hydraulically connected with it. We numerically study with finite element analysis of coupled hydro-mechanical conditions how fault stability is affected by fluid injection into a porous aquifer that is overlaid and underlain by low permeability clay-rich formations. We model a layered sedimentary basin with alternating soft and low permeability with stiff and high permeability formations and include the crystalline basement at the bottom. Additionally, a low permeability steep fault, whose offset ranges from zero to the reservoir thickness, crosses the system. We consider a normal faulting stress regime typical of extensional environments. Simulation results show that the reservoir pressurization as a result of fluid injection causes significant stress changes around the fault that affect its stability. The stress changes depend on the stiffness of the rock juxtaposed to the pressurized reservoir. If there is no offset, the rock is stiff on both sides of the fault, inducing a homogeneous horizontal total stress increase along the thickness of the reservoir. As a result, the deviatoric stress becomes smaller and the induced seismicity potential is low. As the fault offset increases, some part of the base rock gets juxtaposed to the pressurized reservoir. The soft base rock deforms more than the reservoir rock in response to the reservoir expansion, inducing a lower horizontal total stress. Thus, fault stability reduces when the pressurized reservoir rock is juxtaposed with the softer base rock. This finding shows that the induced seismicity potential may increase with the fault offset.</p>

Multi-phase hydromechanical modeling of induced seismicity: general insights and the case study of the deep geothermal project in St. Gallen, Switzerland

2020 ◽  
Author(s):  
Dominik Zbinden ◽  
Antonio Pio Rinaldi ◽  
Tobias Diehl ◽  
Stefan Wiemer
Keyword(s):  
Fluid Flow ◽  
Induced Seismicity ◽  
Gas Flow ◽  
Fluid Injection ◽  
Induced Earthquakes ◽  
Stress Changes ◽  
Reservoir Conditions ◽  
Multi Phase ◽  
Phase Fluid

<p>Industrial projects that involve fluid injection into the deep underground (e.g., geothermal energy, wastewater disposal) can induce seismicity, which may jeopardize the acceptance of such geo-energy projects and, in the case of larger induced earthquakes, damage infrastructure and pose a threat to the population. Such earthquakes can occur because fluid injection yields pressure and stress changes in the subsurface, which can reactivate pre-existing faults. Many studies have so far focused on injection into undisturbed reservoir conditions (i.e., hydrostatic pressure and single-phase flow), while only very few studies consider disturbed <em>in-situ</em> conditions including multi-phase fluid flow (i.e., gas and water). Gas flow has been suggested as a trigger mechanism of aftershocks in natural seismic sequences and can play an important role at volcanic sites. In addition, the deep geothermal project in St. Gallen, Switzerland, is a unique case study where an induced seismic sequence occurred almost simultaneously with a gas kick, suggesting that the gas may have affected the induced seismicity.</p><p>Here, we focus on the hydro-mechanical modeling of fluid injection into disturbed reservoir conditions considering multi-phase fluid flow. We couple the fluid flow simulator TOUGH2 with different geomechanical codes to study the effect of gas on induced seismicity in general and in the case of St. Gallen. The results show that overpressurized gas can affect the size and timing of induced earthquakes and that it may have contributed to enhance the induced seismicity in St. Gallen. Our findings can lead to a more detailed understanding of the influence of a gas phase on the induced seismicity.</p>

More Than 40 yr of Potentially Induced Seismicity Close to the San Andreas Fault in San Ardo, Central California

2020 ◽  
Vol 92 (1) ◽  
pp. 187-198
Author(s):  
Thomas H. W. Goebel ◽  
Manoochehr Shirzaei
Keyword(s):  
Induced Seismicity ◽  
Surface Deformation ◽  
Active Faults ◽  
Stress Transfer ◽  
Correlation Coefficients ◽  
Spatial Proximity ◽  
Fluid Injection ◽  
Induced Earthquakes ◽  
Temporal Correlations ◽  
Stress Changes

Abstract Evidence for fluid-injection-induced seismicity is rare in California hydrocarbon basins, despite widespread injection close to seismically active faults. We investigate a potential case of injection-induced earthquakes associated with San Ardo oilfield operations that began in the early 1950s. The largest potentially induced events occurred in 1955 (ML 5.2) and 1985 (Mw 4.5) within ∼6  km from the oilfield. We analyze Synthetic Aperture Radar interferometric images acquired by Sentinel-1A/B satellites between 2016 and 2020 and find surface deformation of up to 1.5  cm/yr, indicating pressure-imbalance in parts of the oilfield. Fluid injection in San Ardo is concentrated within highly permeable rocks directly above the granitic basement at a depth of ∼800  m. Seismicity predominantly occurs along basement faults at 6–13 km depths. Seismicity and wastewater disposal wells are spatially correlated to the north of the oilfield. Temporal correlations are observed over more than 40 yr with correlation coefficients of up to 0.71 for seismicity within a 24 km distance from the oilfield. Such large distances have not previously been observed in California but are similar to the large spatial footprint of injection in Oklahoma. The San Ardo seismicity shows anomalous clustering with earthquakes consistently occurring at close spatial proximity but long interevent times. Similar clustering has previously been reported in California geothermal fields and may be indicative of seismicity driven by long-term, spatially persistent external forcing. The complexity of seismic behavior at San Ardo suggests that multiple processes, such as elastic stress transfer and aseismic slip transients, contribute to the potentially induced earthquakes. The present observations show that fluid-injection operations occur close to seismically active faults in California. Yet, seismicity is predominantly observed on smaller unmapped faults with little observational evidence that large faults are sensitive to induced stress changes.

Tracking Induced Seismicity in the Fort Worth Basin: A Summary of the 2008–2018 North Texas Earthquake Study Catalog

2019 ◽  
Vol 109 (4) ◽  
pp. 1203-1216 ◽  
Author(s):  
Louis Quinones ◽  
Heather R. DeShon ◽  
SeongJu Jeong ◽  
Paul Ogwari ◽  
Oner Sufri ◽  
...  
Keyword(s):  
Induced Seismicity ◽  
Fluid Injection ◽  
Well Log ◽  
Fort Worth ◽  
North Texas ◽  
Wastewater Disposal ◽  
Fort Worth Basin ◽  
Stress Changes ◽  
Seismic Networks ◽  
Earthquake Sequences

Abstract Since 2008, earthquake sequences within the Fort Worth basin (FWB), north Texas, have been linked to wastewater disposal activities related to unconventional shale‐gas production. The North Texas Earthquake Study (NTXES) catalog (2008–2018), described and included herein, uses a combination of local and regional seismic networks to track significant seismic sequences in the basin. The FWB earthquakes occur along discrete faults that are relatively far apart (>30  km), allowing for more detailed study of individual sequence development. The three largest sequences (magnitude 3.6+) are monitored by local seismic networks (<15  km epicentral distances), whereas basinwide seismicity outside these three sequences is monitored using regional distance stations. A regional 1D velocity model for the FWB reflects basinwide well log, receiver function, and regional crustal structure studies and is modified for the larger individual earthquake sequences using local well‐log and geology data. Here, we present an mb_Lg relationship appropriate for Texas and a basin‐specific ML relationship, both calculated using attenuation curves developed with the NTXES catalog. Analysis of the catalog reveals that the earthquakes generally occur within the Precambrian basement formation along steeply dipping normal faults, and although overall seismicity rates have decreased since 2016, new faults have become active. Between 2006 and 2018, more than 2 billion barrels of fluids were injected into the Ellenburger formation within the FWB. We observe strong spatial and temporal correlations between the earthquake locations and wastewater disposal well locations and injection volumes, implying that fluid injection activities may be the main driving force of seismicity in the basin. In addition, we observe seismicity occurring at greater distances from injection wells (>10  km) over time, implying that far‐field stress changes associated with fluid injection activities may be an important component to understanding the seismic hazard of induced seismicity sequences.

Dynamic Modeling of Channel Formation During Fluid Injection Into Unconsolidated Formations

SPE Journal ◽  
2015 ◽  
Vol 20 (04) ◽  
pp. 689-700 ◽  
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.

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).

Separation of Primary Stress in Finite Element Analysis of Pressure Vessel with the Principle of Superposition

2007 ◽  
Vol 353-358 ◽  
pp. 373-376 ◽  
Author(s):  
Bing Jun Gao ◽  
Xiao Ping Shi ◽  
Hong Yan Liu ◽  
Jin Hong Li
Keyword(s):  
Finite Element Analysis ◽  
Finite Element ◽  
Engineering Application ◽  
Total Stress ◽  
Principle Of Superposition ◽  
Element Analysis ◽  
Primary Stress ◽  
The Finite Element Analysis ◽  
Asme Code ◽  
Allowable Load

A key problem in engineering application of “design by analysis” approach is how to decompose a total stress field obtained by the finite element analysis into different stress categories defined in the ASME Code III and VIII-2. In this paper, we suggested an approach to separate primary stress with the principle of superposition, in which the structure does not need to be cut into primary structure but analyzed as a whole only with decomposed load. Taking pressurized cylindrical vessel with plate head as example, the approach is demonstrated and discussed in detail. The allowable load determined by the supposed method is a little conservative than that determined by limited load analysis.

scholarly journals New prediction method for transient productivity of fractured five-spot patterns in low permeability reservoirs at high water cut stages

Open Physics ◽  
2018 ◽  
Vol 16 (1) ◽  
pp. 499-508
Author(s):  
Chuanzhi Cui ◽  
Zhongwei Wu ◽  
Zhen Wang ◽  
Jingwei Yang ◽  
Yingfei Sui
Keyword(s):  
Prediction Method ◽  
Mass Conservation ◽  
High Water ◽  
Low Permeability ◽  
Element Analysis ◽  
Fracture Length ◽  
High Water Cut Stage ◽  
High Water Cut ◽  
Water Cut ◽  
Low Permeability Reservoirs

AbstractPredicting the productivity of fractured five-spot patterns in low permeability reservoirs at high water cut stages has an important significance for the development and optimization of reservoirs. Taking the reservoir heterogeneity and uneven distribution of the remaining oil into consideration, a novel method for predicting the transient productivity of fractured five-spot patterns in low permeability reservoirs at high water cut stages is proposed by using element analysis, the flow tube integration method, and the mass conservation principle. This new method is validated by comparing with actual production data from the field and the results of a numerical simulation. Also, the effects of related parameters on transient productivity are analyzed. The results show that increasing fracture length, pressure difference and reservoir permeability correspond to an increasing productivity. The research provides theoretical support for the development and optimization of fractured five-spot patterns at the high water cut stage.

scholarly journals De-risking the energy transition by quantifying the uncertainties in fault stability

2021 ◽  
Author(s):  
David Healy ◽  
Stephen Hicks
Keyword(s):  
Geothermal Energy ◽  
Induced Seismicity ◽  
Energy Transition ◽  
Rock Properties ◽  
The Public ◽  
Fault Stability ◽  
Hazard And Risk ◽  
Synthetic Datasets ◽  
The Uk ◽  
Fracture Susceptibility

Abstract. The operations needed to decarbonise our energy systems increasingly involve faulted rocks in the subsurface. To manage the technical challenges presented by these rocks and the justifiable public concern over induced seismicity, we need to assess the risks. Widely used measures for fault stability, including slip and dilation tendency and fracture susceptibility, can be combined with Response Surface Methodology from engineering and Monte Carlo simulations to produce statistically viable ensembles for the analysis of probability. In this paper, we describe the implementation of this approach using custom-built open source Python code (pfs – probability of fault slip). The technique is then illustrated using two synthetic datasets and two case studies drawn from active or potential sites for geothermal energy in the UK, and discussed in the light of induced seismicity focal mechanisms. The analysis of probability highlights key gaps in our knowledge of the stress field, fluid pressures and rock properties. Scope exists to develop, integrate and exploit citizen science projects to generate more and better data, and simultaneously include the public in the necessary discussions about hazard and risk.

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