Microseismic monitoring: Listen and see the reservoir

Part 1 – More akin to earthquake seismology than seismic reflection imaging, changes in reservoirs create signals that reveal internal reservoir structures and flow conduits otherwise unseen

Andy Jupe, John Cowles and Rob Jones, CSM Associates Ltd., Penryn, Cornwall, UK

assive seismic monitoring refers to locating sounds that arise from reservoir changes. Accurately mapping the precise locations of these signals allows delineation of fault structures and flow regimes within the reservoir.

This is the first of a two-part article. It describes the brief history of passive seismic monitoring, the theory behind its use in reservoir imaging and how it is acquired, processed and applied. In March, Part 2 will describe a recently completed case history of a North Sea reservoir.

Background

Since the early 1980s, microseismic monitoring (aka passive seismic monitoring) has been regularly and successfully used in the geothermal industry to monitor hydraulic fracturing operations and stimulation, track fluid movement, target development wells and help with fault delineation.¹ Its adoption by the oil and gas industry has been slow, due to technical difficulties associated with the behavior and deployment of seismic sensors in hydrocarbon environments. These technical problems have now been largely overcome, and because of its high-resolution coverage and low cost-to-benefit ratio, the reservoir characterization potential of microseismic monitoring is being recognized and exploited by proactive operators.

Microseismic events are very small earthquakes, usually between –3 and 1 M_L, occurring on failure surfaces such as fractures, which have typical radii in the 1- to 10-m scale. They have been detected and located at distances over 1 km from the monitoring well in hydrocarbon reservoirs.² Because the earth stresses acting within a reservoir are anisotropic, shear stresses build up on naturally occurring fracture surfaces. Under normal conditions, these fracture surfaces are locked together.

However, when in situ stresses are perturbed by reservoir production activity such as changing fluid pressure, the fractures shear, producing small earthquakes, Fig. 1 Seismic signals from microseismic events can be detected using borehole geophones, thereby enabling mapping of microseismic events and associated pressure/stress changes within the reservoir. The borehole geophones need to be positioned as close to the reservoir as possible.

Although surface units are suitable for measuring large scale, e.g., tectonic-related seismicity, they cannot detect the size of event that is of interest for characterizing reservoirs. Attenuation effects mean that only the largest events reach surface sensors. Rates of seismic activity appear to have a fractal-type distribution, and for every event detected (using a surface seismometer or an OBS) at say magnitude 2 M_L, there may be hundreds or thousands of events at –1 M_L.

In 1997, using a single, multi-level Vertical Seismic Profile (VSP) tool, more than 2,000 microseismic events were detected and located during 19 days of monitoring a chalk reservoir in the North Sea. It is this large number of small seismic events that enables the technique to be used to image pressure fronts and faults. Therefore, the more events detected and located, the better the data produced on reservoir evolution and deformation mechanisms.

The time is now approaching for a much wider adoption of microseismic monitoring technology in the oil and gas industry, for a number of reasons. The major technical barriers have been overcome, and the move toward permanent monitoring systems installed as part of the completion has made the "Deeplook" concept integral to future development.³ The industry is more open than ever to the adoption of new techniques, particularly as 3-D seismic reflection cannot always provide all the answers.

Perhaps what is more significant is that the potential of 4-D/time-lapse seismic has succeeded in moving the focus, from just imaging reservoir structure, to understanding more about long-term reservoir behavior and production processes, remote from the wellbore. Reducing costs and maximizing production and recovery factors could result.

One common objection to microseismic monitoring often heard is that the technique is only applicable to reservoirs with high rock velocities. Successful surveys by Arco⁴, Phillips Norway and more recently Amoco, in environments ranging from shallow unconsolidated sands to chalks, have shown that this is not the case. Microseismic monitoring is becoming a valuable and unique tool for achieving 3-D spatial monitoring remote from the monitoring well (typically a 2-km coverage diameter), and can now be economically implemented on land and offshore.

Microseismic also has the potential to complement 4-D seismic surveys, and can be used where reflection seismic surveys are inhibited from effective reservoir mapping due to gas clouds. Calibrating 4-D seismic surveys, using borehole seismic techniques, has been addressed by Johnston et al., 1992, and Lee et al., 1995. Microseismic monitoring can be used to help calibrate 4-D surveys and provide real time, ongoing imaging of hydro / geomechanical processes. To effect this linkage with 4-D seismic, microseismic processing can (after Bossu 1996):

• Describe deformation processes of the reservoir, such as event location, magnitude, focal solutions and prevailing stress field
• Map active and conductive fractures of faults, at an intermediate scale between borehole imaging and 3-D seismic imaging.

Microseismics: The Basics

Microseismic monitoring is a branch of earthquake seismology. Most of the differences between microseismic monitoring and exploration seismology arise from the fact that, in exploration seismology, the source is directly controlled; it has a known position and origin time. In microseismic monitoring, the source position and origin time are both unknown. Indeed, determining them is typically the first goal in microseismic monitoring. Of course, the disadvantage of unknown source position is compensated by the fact that locations of the sources are not limited to the surface of the earth, or to boreholes, and they generate a lot of S-wave as well as P-wave energy. More important, they are produced as a direct result of production processes and occur where there is some causal activity within the reservoir.

Microseismic events manifest themselves as distinct bangs, typically in the hundreds-of-Hertz audio-frequency range.¹ Seismic waves generated by source mechanisms are convoluted by rock properties between the source event and receivers in the reservoir. Study of the waveforms and source mechanisms provides information on deformation mechanisms, geometry of conductive fractures and reactivated fault structures, and distribution of fluid flow and pressure-front movement within the reservoir.⁵

Fig. 2 shows compression and shear wave arrivals on six seismic sensors, each with three components. The vertical component is represented in black, while the two horizontal components are displayed in blue and orange. The particle-motion diagrams, or hodograms, are plotted as ratios of these components and provide directional information. Each microseismic event can also be considered a high-frequency seismic source, activated within the reservoir, enabling high-resolution time-lapse velocity imaging, e.g., tomography.

The specific nature of reservoir microseismic activity depends on many factors, such as rock type, state of stress, etc. In geothermal applications, microseismic event rates of greater than one per second can occur during hydraulic fracturing. In a recent North Sea field survey, during normal production, average event rates of 100 a day were recorded from a single observation well.²

Microseismic events can be located from a single monitoring well using a multi-level, 3-component geophone array, typically a VSP tool, although a spatially distributed network is optimal. For accurate and reliable locations, sensors must record the signal undistorted in the few-hundred-Hertz range. The signal is analyzed to give estimates of microseismic event magnitude, length of the fault that has moved and other detailed information.

For event location, a velocity model of the reservoir is first developed, typically 2-D or 3-D, based on a combination of reflection seismic and well log data. The location process can be viewed as comprising two stages. First, distance between sensor and microseismic event is given by the time delay between S-wave and P-wave arrivals. Second, direction of the event is given by analysis of P-wave particle motions, or through a process similar to the triangulation methods used in surveying or navigation. In practice, complex search and optimization algorithms replace the simple process described here, but the principle remains the same.

Acquiring Microseismic Surveys

Microseismic surveys fall into two broad categories: temporary and permanent. There are two types of temporary surveys:

• Pilot study for a permanent system
• Monitoring for short-term operations such as cuttings re-injection or fracturing.⁶

Temporary surveys can now be carried out routinely on land or offshore, but permanent monitoring offshore still has certain issues that need addressing regarding sensor deployment, coupling and longevity. However, it would be unusual for an operator today to move straight into permanent monitoring without first carrying out a temporary survey. Companies such as Amoco and Phillips Norway have recently carried out successful, temporary microseismic surveys offshore using multi-level arrays deployed in observation wells.

Before committing to permanent deployment of borehole geophones in a field where no microseismic monitoring has been tried, a detailed design study should be undertaken. Three key issues to address are:

1. Network design
2. Assessment of contribution to reservoir management
3. Hardware specification.

Numerical modeling of microseismic sensor network performance assesses ability to resolve the target zone, e.g., injector/producer horizon, required location accuracy, event detection sensitivity and individual event source mechanisms, that is, fracture plane orientations. Using genetic-algorithm-based software, it is also possible to achieve the optimization of sensor distribution based on cost/objectives.

The next step is to evaluate the reservoir management information that can be derived, including:

• Evaluation of probable microseismic failure mechanisms associated with production/injection, e.g., strike or dip-slip shear
• Microseismic event association with individual reservoir processes
• Evaluation of operational parameters, such as pumping rates and pressures, required to induce microseismic activity.

Additional elements include specification of sensors, deployment, site operations, acquisition, processing and costs. To carry out a study of this type, the operator is required to make data available on the production or injection zones of wells, logs, flowrates, geology, velocity structure, and similar items.

Processing

Microseismic events are analyzed for event rates and assessment of the spatial distribution of seismicity within the context of reservoir operations. Online processing is usually performed in the field or at the client's office. This generally provides data quality control, arrival-time picking, hodogram (particle motion) calculation and preliminary event location and visualization.

Final processing is usually carried out by the service company and typically involves: event location using a 2-D or 3-D ray-tracing approach; source parameter evaluation, including magnitude, source radius, static stress drop, etc.; and application of advanced processing techniques, such as the "collapsing"⁷ technique to refine locations.

Integrating microseismic data with existing reservoir data and simulators to assist in interpretation and prediction is a rapidly developing area.⁸ It requires close cooperation between the operator and processing staff. Given the way 3-D seismic processing has spawned so much specialist support software for integrating seismic and other reservoir data, expect to see a rapid growth in packages supporting the integration of microseismic data.

Conclusion

To summarize, microseismic monitoring has shown it can be used for:

• 3-D time-lapse imaging of reservoir stimulation
• Identification of anisotropic flow and well targeting, Fig. 3.
• Delineation of leaky fault structures
• Predictive reservoir models
• Reducing uncertainty.

Albeit likely to be a while before microseismic monitoring becomes routine, it has been proven to deliver important information about reservoir behavior.

Literature Cited

¹ Phillips, W. S., et al., "Reservoir mapping using microearthquakes: Austin Chalk, Giddings field, TX and 76 field, Clinton Co., KY," SPE 36651, Annual Technical Conference and Exhibition, Denver, Colorado, Oct. 6-9, 1996.

² Maxwell, S.C., et al., "Microseismic logging of the Ekofisk reservoir," SPE 47276, Eurock 98 Conference, Trondheim, Norway, 1998.

³ Stoessel, E. T., "Access and integration of emerging technologies: Keys to successful imaging of reservoir fluids in depth and time," OTC 87161, Offshore Technology Conference, Houston, Texas, May 4-7, 1998.

⁴ Brady, J. L., "Microseismic monitoring of hydraulic fractures in Prudhoe Bay," SPE 29553, SPE 69th Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA.

⁵ Jupe, A. J. and R. H. Jones, et al., "The role of induced microearthquake activity in characterizing fracture-dominated fluid flow," AAPG International Conference Proceedings, Nice, France, September 1995.

⁶ Keck, R. G. and R. J. Withers, "A field demonstration of hydraulic fracturing for solids waste injection with real-time passive seismic monitoring," SPE 28495, SPE 69th Annual Technical Conference and Exhibition, New Orleans, Louisiana, USA.

⁷ Jones, R. H. and R. C. Stewart, "A method for determining significant structures in a cloud of earthquakes," Journal of Geophysical Research, Vol. 102, No. B4, pp. 8245-8254, April 10, 1997.

⁸ Jupe, A., et al., "Monitoring and management of fractured reservoirs using induced microearthquake activity," SPE/ISRM 47315, Eurock 98 Conference, Trondheim, Norway, 1998.

The authors

Dr. Andrew Jupe is manager of CSMA's Microseismics Group and has 10 years' experience in microearthquake seismology and numerical modeling of rock mechanical and hydromechanical processes. For the last six years he has worked in geoscience R&D and consultancy in oil and gas, geothermal and radioactive waste disposal industries. He graduated from Reading University in 1985 with a BSc (hons) in geological geophysics with mathematics, and focused his PhD in geophysics/rock mechanics.

John Cowles is business development manager for CSM Associates Ltd. and has 14 years' experience in marketing and business development, including six years in the oil and gas industry. His primary role is to help transfer the microseismic monitoring expertise and experience, gained from geothermal and radwaste applications worldwide, to the oil and gas industry. He graduated from Manchester University in 1982 and earned his masters degree in 1991 at Bristol Polytechnic.

Dr. Robert Jones, CSMA's chief geophysicist, graduated from Manchester University with a BSc (hons) in physics in 1981. He earned his masters degree in applied geophysics at Birmingham University in 1982, and a PhD in geophysics at Cambridge University. He has been with CSMA for 11 years, specializing in development of microseismic location algorithms, processing and interpretation.

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company