**2. Background**

Security of energy supplies, the continuous growth in energy demand, and climate change are among the greatest global challenges that we face. Nearly all projections agree that we will remain heavily reliant on fossil fuels for many years. For example, the International Energy Agency's 'business-as-usual' analysis from 2008 indicates that in 2030 approximately 83% of the world's energy demand will still be met by fossil fuels. In 2011 this was revised downward to 55% due to high oil prices, government incentives for renewable energies and environmental concerns (EIA, 2011). Technological innovations will therefore be required to (i) find new hydrocarbon reserves or enable recovery from proven resources previously inaccessible or uneconomic; (ii) maximize recovery from producing reservoirs, and (iii) deal with CO2 emissions. Microseismic monitoring and hydraulic fracturing are mainly related to the first two points.

Recovery of hydrocarbons from previously uneconomic yet proven resources such as shalegas and other tight-gas plays has become possible due to significant improvements in the last 10 years in two key technologies, namely horizontal drilling and hydraulic fracturing. Tightgas reservoirs are characterized by low porosity and permeability, indicating that little pore space is present and that fluid flow is guaranteed to be slow and difficult, thus severely complicating reservoir drainage. On the other hand, this gas is often located in very thick lithologic units such that the resource volume is large. Horizontal drilling into these units enables drainage over a larger well contact area (2-3 km instead of 100-200m), thus improving fluid flow. In hydraulic-fracture well treatments, fluids possibly mixed with proppants (slurry) are injected under high pressure to induce fracturing of the reservoir, thereby further enhanc‐ ing reservoir drainage by increasing the effective permeability through the creation of an interconnected fracture network.

The technological advances in these two key technologies have been such that in 2000 only 1% of the total gas production in the US came from shale-gas fields, whereas currently this is estimated to be 20% (IHS CERA, 2010). Figure 1 shows the extent of current and potential shale-gas plays in North America. It is clear that tight-gas and shale gas will remain an important resource for many years to come and further technological improvements will enable economic drainage of additional reservoirs. One of these emerging technologies is microseismic monitoring.

and enhanced geothermal systems (e.g., Häring et al., 2008), microseismic monitoring techniques are being used increasingly by the oil and gas industry to monitor hydraulic stimulation of "tight" (very low permeability) hydrocarbon reservoirs and steam injection into heavy-oil fields. As such, it is one of the technologies underpinning the recent up‐ swing of oil production in Western Canada, as well as the development of new tight-gas fields, monitoring of caprock integrity during in situ heavy-oil exploitation, and carbon capture and storage (McGillivray, 2005; Maxwell et al., 2010; Verdon et al., 2010; Maxwell,

This paper reviews some of the current questions and research in microseismicity, ranging from acquisition, processing to interpretation. However, before reviewing these aspects, it is important to consider the wider context first and the economic impact of hydraulic fracturing

Security of energy supplies, the continuous growth in energy demand, and climate change are among the greatest global challenges that we face. Nearly all projections agree that we will remain heavily reliant on fossil fuels for many years. For example, the International Energy Agency's 'business-as-usual' analysis from 2008 indicates that in 2030 approximately 83% of the world's energy demand will still be met by fossil fuels. In 2011 this was revised downward to 55% due to high oil prices, government incentives for renewable energies and environmental concerns (EIA, 2011). Technological innovations will therefore be required to (i) find new hydrocarbon reserves or enable recovery from proven resources previously inaccessible or uneconomic; (ii) maximize recovery from producing reservoirs, and (iii) deal with CO2 emissions. Microseismic monitoring and hydraulic fracturing are mainly related to the first

Recovery of hydrocarbons from previously uneconomic yet proven resources such as shalegas and other tight-gas plays has become possible due to significant improvements in the last 10 years in two key technologies, namely horizontal drilling and hydraulic fracturing. Tightgas reservoirs are characterized by low porosity and permeability, indicating that little pore space is present and that fluid flow is guaranteed to be slow and difficult, thus severely complicating reservoir drainage. On the other hand, this gas is often located in very thick lithologic units such that the resource volume is large. Horizontal drilling into these units enables drainage over a larger well contact area (2-3 km instead of 100-200m), thus improving fluid flow. In hydraulic-fracture well treatments, fluids possibly mixed with proppants (slurry) are injected under high pressure to induce fracturing of the reservoir, thereby further enhanc‐ ing reservoir drainage by increasing the effective permeability through the creation of an

The technological advances in these two key technologies have been such that in 2000 only 1% of the total gas production in the US came from shale-gas fields, whereas currently this is estimated to be 20% (IHS CERA, 2010). Figure 1 shows the extent of current and potential

2011; Clarkson et al., 2011).

440 Effective and Sustainable Hydraulic Fracturing

in tight-hydrocarbon fields.

**2. Background**

two points.

interconnected fracture network.

**Figure 1.** Current shale plays in North America. Source: EIA http://www.eia.gov/pub/oil\_gas/natural\_gas/analy‐ sis\_publications/maps/maps.htm

Hydraulic fracturing (also known as fraccing or fracking) leads to brittle failure inside a reservoir, which is typically accompanied by microseismicity. Microseismicity refers to discrete rock-deformation events, analogous to tiny earthquakes, that are generally of moment magnitude < 0. For reference, magnitude 0.2 is the equivalent of the energy released by a large hand grenade (30 g TNT equivalent), whereas a typical small mining blast has a magnitude around 1-1.5, corresponding to 2-2.5kg of TNT. Since magnitude scales are logarithmic, negative magnitude events thus correspond to the energy yield equivalent of milligrams or even micrograms of TNT.

Monitoring of microseismic activity is a geophysical remote-sensing technology that provides the ability to detect and map associated fracturing processes, either in real-time or in postprocessing mode. A typical field deployment involves the installation of an array of continu‐ ous-recording 3-component geophones within observation well(s) near the zone of interest, and/or a large number of surface sensors. Although relatively new to the oil and gas industry, similar monitoring technologies for earthquakes have been honed and developed by the seismological and mining research communities for decades (e.g. Gibowicz and Kijko, 1994; Bolt, 1984; Stein and Wysession, 2003). The goal of microseismic monitoring is to detect, locate and characterize microseismic events, which often occur in large numbers within cloud-like distributions that reflect underlying fracture networks. This approach enables monitoring of frac treatments in real-time in order to detect the extent of the stimulated rock volume and thus the success of the treatment, as well as predict likely improvements in subsequent reservoir drainage.

or deploy instrumentation inside wells, and permits deployment of one or two orders of

Microseismic Monitoring Developments in Hydraulic Fracture Stimulation

http://dx.doi.org/10.5772/56444

443

**•** The current strategy for hydraulic fracturing of tight-gas reservoirs is to minimize acquisi‐ tion durations to reduce costs. Recently recognized phenomena, such as long-period longduration events (Das and Zoback, 2011), indicate that much can be learned from the use of exceptionally long deployment times (i.e., weeks rather than days) in order to enable more complete characterization of background noise spectra. Such long recording durations would also enable the evaluation of technology for noise interferometry (cf. de Ridder and Delinger, 2011) to reveal not only what happens during stimulation, but also in the period

**•** Various formulas are currently used within industry to calculate the magnitude of micro‐ seismic events (Shemata and Anderson, 2010). Since magnitude formulas were developed for describing earthquake phenomena, they are calibrated for significantly larger magni‐ tudes. The extrapolation of different formulas to 4-5 orders of magnitude below their calibration range leads to discrepancies in reported values. Accurate magnitude determi‐ nation is of practical importance for various reasons, including (i) the determination of the stimulated rock volume (Maxwell et al., 2006); (ii) recently implemented controls in the UK on hydraulic fracturing operations are based on a "traffic-light system" (de Pater and Baisch, 2011) in which operations are suspended for several days if any event exceeds ML = 0, and stopped if any event exceeds ML = 1.7; and (iii) on liability issues related to induced

**•** Currently the emphasis is on mapping brittle failure, yet it is hypothesized that the cumu‐ lative energy released via brittle failure represents only a minute fraction of the total injected energy, indicating that a large portion of energy release may occur aseismically (i.e., plastically or at very slow deformation rates) (Maxwell et al., 2009). This suggests that there may be an advantage to acquisition of continuous recordings for analysis of the ultra-low frequency spectral content of microseismic activity, which may be diagnostic of certain types of aseismic rock failure (Benson et al., 2008; Pettit et al., 2009; Beroza and Satoshi, 2011). A university-led project to acquire microseismic data was undertaken in northern British Columbia, Canada. This experiment involved the recording of several multistage hydraulic fracture treatments performed in two horizontal wells (Figure 2). The microseismic data were collected using both surface and borehole sensors. The borehole tool string consisted of a 6 level broadband system with downhole digitization. Surface sensors included a 12-channel array with a mix of vertical-component and 3-C geophones, and 22 broadband sensors

The unusual setup was designed to investigate multiple objectives. First, microseismic monitoring was performed using both surface and borehole equipment to compare acquisition strategies and determine their respective advantages and inconveniences such as ease of deployment, costs, detectability of events, other signals and associated noise levels. In addition, the experiment is unique in that both broadband and short-period equipment are deployed. The approximate lowest recording frequencies for the various equipment are; broadband

.

magnitudes more instruments.

seismicity (Cypster and Davis, 1998).

deployed in 7 localized arrays over an area of ~ 0.5 km2

before and immediately following the slurry injection.

Applications of microseismic monitoring within industry, particularly in oil and gas, have seen remarkable growth during the past 10 years (Warpinski, 2009; Maxwell, 2010). This has not been limited to hydraulic fracture treatment for shale-gas and other tight-gas plays, but has included stimulation technologies such as fracturing or steam injection applied to tight-oil or heavy-oil fields and also techniques for maximizing recovery from producing reservoirs. It is estimated that over one million hydraulic fracture treatments have been performed in the US in the past 60 years (King, 2012), and that currently 3-5% of fracs in North America involve microseismic monitoring. Oil and gas companies have made significant expenditures (con‐ servatively \$100's MM) for microseismic monitoring, but face extraordinary technological challenges to fully utilize the results. Their efforts are hampered by a number of factors, including an incomplete understanding of seismological and geomechanical processes associated with induced microseismicity.

In the next sections we will review current pertinent research questions on microseismic acquisition, processing and interpretation. Since many items are intimately intertwined it is inescapable that some points may be revisited throughout the chapter.
