In the March 2006 issue of E&P, I wrote about microseismic monitoring, referring to it as “the other 4-D.” In that article I described some of the then-current developments on the microseismic monitoring front, some of the promising areas for future application and some of the challenges. In this article my aim is to bring you up to date on how this fascinating field is developing. One thing is certain, the interest and effort in this field has certainly continued to grow. At the time of my earlier article, most would have needed a brief definition of passive seismic or microseismic monitoring before any discussion could continue. Today the subject has been discussed in numerous articles and papers and was even the subject of a sold-out 3-day workshop in Dubai last December.

The bull market for unconventional gas has been great for microseismic monitoring, both as a business and a technical driver. As gas shale and other tight gas plays have developed in the

Figure 1. Cross-section view of the microseismic events recorded during a seven-stage frac of a horizontal well drilled in the Barnett shale in Texas. The different colors represent events from the different stages of treatment. The well is visible as a straight line within the event cluster. The bounding horizons represent the top and bottom of the reservoir interval. (Figure courtesy MicroSeismic Inc.)
Fort Worth Basin and beyond, operators increasingly have turned to microseismic monitoring of frac treatments to help define treatment parameters and optimal well spacing. Take Newfield Exploration as an example. In a recent presentation to investors, David Trice, president and chief executive officer, described an extensive test in the Woodford play of Oklahoma where the monitoring of various treatment programs in closely spaced wells will play a key role in the development plans of this important new resource play. A surf through the Web pages of the players in the unconventional gas game throughout the lower 48 will uncover numerous references to the importance of microseismic monitoring in the development of these reservoirs. Monitoring is shedding light on how to best frac these reservoirs and what well spacing is really required.

It is noteworthy that as operators have stepped out into less mature tight gas plays where monitor wells are just not as available, the use of surface arrays for frac monitoring has become more common. Dr. Norman Warpinski of Pinnacle Technologies, a noted pioneer in the field of microseismic monitoring, has called the ability to monitor fracs from the surface the “Holy Grail” of microseismic monitoring. (Pinnacle Technologies Quarterly Newsletter, Spring, 2007).

The commercial success of frac monitoring has allowed for substantial technical advances in the last 2 years.

Processing speeds have increased to the point where data are available for analysis in near real time. Visualization tools (Figure 1) have been developed that allow for the microseismic events to viewed interactively in time and space in a rich 3-D environment that contains well logs, geologic horizons, seismic data and the time-dependent treatment data (pump curves).
Decisions can be made on treatment parameters for the next stage to be pumped based on the results of the last stage. Such decisions can save operators a great deal of money if pump volumes can be reduced. Wells can be saved if it appears the frac is wandering off in the wrong direction. Post-mission, operators can now re-model the frac to honor not just the pump and pressure data but also the microseismic data on the dimensions and placement of the frac. Hence, a better design for the next well in the play is achieved.

Another oil field application where microseismic monitoring has gotten good traction is in the area of steam injection for the mobilization and production of heavy oils. This is probably no surprise as the high-pressure injection of steam into the glassy, cold bitumen is very close to a fracturing procedure. Shell Canada, ESSO Canada, ConocoPhillips, Total and other operators in Canada’s north now routinely use microseismic monitoring in conjunction with their heavy oil operations, particularly in cyclic steam stimulation but reportedly now in steam-assisted gravity drainage as well. Monitoring was first directed at environmental compliance, listening for breaks in steam pipes or well casing at other-than-reservoir level. They have now learned that monitoring can show where the steam is penetrating and saturating the bitumen (steam compliance) and, more importantly, where it is not, leaving valuable pay behind (Figure 2).

Another energy-related application of microseismic monitoring that has matured in the last
Figure 2. Geophysical monitoring of a pad (green box) of horizontal cyclic steam stimulation wells (in red and blue) at Shell Canada’s Peace River in situ heavy oil operation. Shown are microseismic event locations (red and magenta dots), tiltmeter measured surface uplift (colder colors show uplift as a result of steam buildup), seismically mapped faults (fences in the plot), downhole seismic monitor stations (white squares on the inclined magenta well), and permanent tiltmeter and time-lapse seismic monitoring installations (black squares and crosses on the surface). The use of these diverse datasets in combination with geological information, temperature, pressure and injection/production data helps in the optimization of this and future pads of wells. (Figure courtesy Shell Canada)
few years is in the area of geothermal energy production. For example, Geodynamics Limited of Australia has used microseismic monitoring to map out its 1.5 sq mile (4 sq km) hydrothermal reservoir as it was created. The reservoir consists of a granite body at 13,900 ft (4,250 m) depth that has been hydraulically fractured to increase its permeability such that water can flow through the granite to harvest geothermal energy in the form of heat. Microseismic monitoring is the only way the operator could know just how big a reservoir it had created.

Monitoring of CO2 sequestration activity is yet another application that is intuitively well-suited to the microseismic method. Indeed, in the same E&P article referenced earlier the results of a CO2 injection pilot monitoring project whose results showed real promise were briefly presented. However, there has not been a great deal of industry uptake in this area. It may well be that a detailed knowledge of where the CO2 is going and the continued competence of the reservoir as a containment facility will be driven more by the regulatory authorities than by the folks doing the storing.

Microseismic monitoring has long played a role in the mining industry, particularly as a risk avoidance tool, listening for events that are precursors to rock bursts and other structural failures. Monitor arrays are also used in a similar way for risk reduction in salt cavity storage facilities. These are well-established applications of the technology that in many ways are ahead of the adoption of the method into the oil field. A workshop at the European Association of Geoscientists and Engineers (EAGE) in London this past June explored this very topic, seeking to transfer to the oil field some of the knowledge from these other industries. The full-day workshop attracted nearly 100 participants. Papers from the coal and hard rock mining segments were augmented by early-stage oil company results from field surveillance operations both seismic and non-seismic. The participants seemed to agree that microseismic should be an integral part of a multidisciplinary approach to production monitoring.

In truth, however, the general application of long-term microseismic monitoring to standard reservoir production activities, those less violent and thus quieter than hydro-frac, has really not taken off as it might. It would appear that in this field the value proposition of monitoring is yet to be well established. In a few instances, notably where ocean bottom cable (OBC) arrays have been planted to enable 4-D seismic (such as BP’s Valhall field in the North Sea), the operators are actively pushing the data to try to establish that value proposition, but publication on passive seismic results has been sparse. As well, an Aramco pilot project designed to monitor water flooding in the Ghawar field of Saudi Arabia (Dasgupta, 2005 SEG Houston) has yet to produce any published results. Case histories that show the value of such monitoring will be required before this technology really takes hold.

Where, then, is the technology today? In the oilfield microseismic monitoring has seen increasing application to hydro-frac monitoring and steam-assisted heavy oil production.
Processing speed, visualization and analytical tools have improved greatly over the last 2 years in direct relation to the number of projects performed. We are still on a steep learning curve with respect to the interpretation of these data. Only rarely are the data analyzed beyond simple event locations in time and space, even though a wealth of other information that relates to the geomechanics and fluid mechanics of the reservoir is available. A broader implementation of long-term monitoring, including microseismic monitoring, of reservoir production definitely requires that we move further up this learning curve and demonstrate meaningful value.

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