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Into the Abyss!

Borehole seismic – the technological challenge of listening at extreme depth. William Wills of Avalon Sciences discusses some of the principle requirements driving borehole seismic technology innovation.
This article appeared in February, 2013

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Schematic of a borehole microseismic monitoring system outlining specific requirements for fracture mapping, including example hodogram display (bottom left) of recorded microseismic traces for each 3D component. Source: Avalon Geosciences The domain of borehole seismic exploration is fast approaching a new era in technological advancement, with the dynamic and challenging requirements for mapping and monitoring continually increasing as complex, hostile well environments dominate over shallower conventional hydrocarbon reservoirs.

The deployment of seismic recording systems deep within the well to acquire high resolution data has become common practice over the last few decades. This technology has been dominantly used to complement surface seismic surveying bringing advantages such as noise reduction and immunity from the distorting effects of near-surface rocks, especially sediments. The well-established method of downhole Vertical Seismic Profiling (VSP) thus allows for much higher resolution imaging between lithologies proximal to the well whilst even revealing subtle impedance changes beyond total depth of the exploration well. At its most basic application, ‘check shot’ borehole seismic calibrates for any inferred depth uncertainty of reflectors presented by surface seismic, giving an enhanced velocity model around a well.

Borehole Seismic for Deep Reservoirs?

Schematic of a typical borehole seismic tool string with surface power and system panels. Source: Avalon Geosciences However, as directional drilling technology has advanced over the last decade, allowing for access to more complex and deeper environments (e.g. within subsalt zones), so has the need developed for more intricate seismic surveying techniques. Conventional surface 3D seismic surveys of deep subsalt reservoirs, such as at the deepwater Wilcox Trend in the Gulf of Mexico, are complicated by the presence of 300–600m thick allochthonous salt canopies. Recent surface techniques to map below the salt have made progress in the form of wide-azimuth (WAZ) towed streamer acquisition. However, deep reservoirs, like those found in the Gulf of Mexico with well depths of over 10,500m, so far have demonstrated that this technique is not solely sufficient for such deep reservoir characterisation. At these depths the modest angle of incidence from the distal surface (mid 20° range) can potentially render reservoir amplitude analysis as an inappropriate technique, especially within poorly or unevenly illuminated subsalt environments.

Advances in surface seismic processing for subsalt settings such as Pre-stack Depth Migration (PSDM) are still sensitive to velocity error and vertical resolution, especially in areas of multifaceted salt geometry which exhibit large lateral velocity variations. PSDM is dependent on an accurate velocity model, which for profound depths rarely incorporates localised low velocity zones or takes into account anisotropy, resulting in velocity models which may be too deep and too steep, thus complicating regional reconstructions and resolution of individual structures. Further uncertainty can be introduced due to the contamination of primary energy at reservoir level by multiple signals generated above the top salt and water bottom. This can often be a serious issue when migrated multiples resemble faulted geometry.

The Engineering Challenge for Hotter and Deeper


Correlated data from North Belt Well, Texas 2010, acquired by Digital Geochain Borehole Seismic System. Cross normalised seismic trace recorded on Dual Geophones (traces 1 and 3) vs Quad Geophones (traces 2 and 4). The magnitude spectrum shows a ~6 dB differential in signal to noise over the recorded bandwidth between the Dual (blue) and Quad (red) sensor packs. Source: Avalon Geosciences Pressure safeguards are required to ensure insulation of the system from the immense borehole fluid pressures. On the left is an example of pressure bulkhead and seals linking the wireline to a borehole seismic satellite, and the image on the right shows an associated high-temperature, high-pressure test chamber to reconstruct borehole conditions.  Source: Avalon Geosciences Determining quality and integrity of reservoirs that remain below seismic resolution can be achieved if the seismic receiver can be located downhole proximal to the area of interest. However, at these depths a real technological challenge is presented. In regions such as the Gulf of Mexico these geophone tools need to be designed to function within very hostile borehole environments with temperatures of over 180°C and pressures reaching 25,000 PSI.

The current industry standard borehole seismic receiver systems in general provide a downhole pressure housing for the seismic sensor and coupling mechanism (usually in the form of a retractable arm) to the borehole casing or formation. Most modern sensor packs are three-component, allowing for full analysis wave particle motion.

Borehole seismic arrays are deployed as a series of satellites on a wireline string. The pressure housing hosts both the geophone sensor pack and coupling mechanism along with the downhole digital telemetry system, maximising dynamic range and sample rate, ideally with real time data transmission and display to surface. Much borehole seismic development of the last five to ten years has allowed for downhole electronics to survive and operate with minimal noise within increasingly hot well conditions (150°C+). To do this the downhole electronic technology has introduced robust thermal insulation and active cooling within the well. Deploying such systems is not without risk; much research has been done to ensure the immense borehole fluid pressures (25,000 PSI+) on the deep receivers do not lead to ingress through mechanical seals, resulting in electrical leakage.

For more complex time-lapse 4D seismic surveys involving re-visiting or continuously monitoring a reservoir site, it is more beneficial to have a permanent monitoring system in place. To survive at pressure on a semi-permanent basis, industry development has replaced compression set O-rings with metal-metal seals, increasing resilience to gas and fluid intrusion from the borehole, even in the most hostile wells.

Optimising for Borehole Microseismic Monitoring

The fundamental principles of hydraulic fracturing are broadly understood throughout the hydrocarbon exploration industry. ‘Unconventional’ high porosity ultra-low permeability reservoir rocks must be artificially fractured in order to provide a hydrocarbon flow pathway. As the high-pressure pumping of a liquid proppant (often a sand/water/chemical gel matrix) passes through a well at a perforated cased point into the tight formation, the fracture events generate high-frequency, low-amplitude microseismicity. This can be detected by a borehole receiver satellite ideally positioned straddling cross-well to the target zone, as shown in the introductory figure on page 42. When employing three-component geophones (X, Y, Z axis) and establishing the receiver orientation and azimuth within a velocity model, the particle motion of the geophone can be displayed as a hodogram. When combined with a picked P- and S-wave arrival time differential, this allows the fracture event to be pinpointed on a 3D grid in real time. To do this the receiver orientation and coupling quality must be initially established. Current practice is to use the downhole perforation shot, but this can be augmented further by initially deploying a repeatable downhole source within the injection well.

The quality of the geophone receiver therefore plays a fundamental part in how accurately the fracture progression is mapped. Most seismic geophone sensors have historically been passive analogue devices typically comprising a spring-mounted magnetic mass moving within a wire coil to induce an electrical signal. The response of a coil/magnet geophone is proportional to ground velocity. Excellent sensor sensitivity is a vital characteristic when trying to pick low-amplitude microseismic arrivals. Even when deployed in relatively quiet borehole conditions, sensors featuring significant electronic noise (especially at temperature) can be enough to mask a microseismic arrival. To improve on this signal to noise ratio, technology has evolved to stack the phones within the sensor pack component of a downhole receiver, with the latest technology achieving so far four phones on each component, with 12 in each receiver satellite.

As the thermal noise (En) output voltage can be expressed as En = √4kTBR (B Boltzmann’s constant, kT Temperature, B Bandwidth and R Geophone Resistance), then the sensitivity of a typical geophone is effectively doubled when in series whilst only marginally increasing En, as demonstrated in the figure above.

This provides a much more cost-effective method of increasing sensitivity compared to standard borehole satellites, which accomplish multiple sensors per axis by mechanically joining two independent ‘dual’ geophone satellites together within the monitoring well. Coupled receiver methods leave the stack trace vulnerable to error from mechanical coupling to casing discrepancies, cement irregularities, and inaccuracy from an increased distance between the joined sensor packs, which can be over a metre in vertical separation. Housing multiple geophones per component within a single satellite goes much further in guaranteeing perfect stacking.

Optimising the digital downhole electronics is also a key role for fracture monitoring. If the borehole geophone response has electronic downhole gain applied (54 dB), increasing dynamic range, and a high sample rate (one sample every 1/4ms), it will provide a recording bandwidth of up to 1600 Hz, which is perfectly suited to comprehensively measure all the energy content generated by the high-frequency microseisms.

Evolution

The demand for borehole seismic receivers to operate in ever more hostile environments with increased downhole life time, whilst delivering augmented sensitivity, dynamic range and broadband, is driving sensor technology innovation. The move to multiple high-temperature geophones and high-gain electronics is only one small step in the evolution of downhole seismic tools. Distributed fibre optic systems with large broadband and low noise may be the next step in progression but are yet to establish themselves within the extremes of well pressure and temperature. However, as this technology develops, so too will resolution and confidence mature when characterising and monitoring seismic within deep complex geology.

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