OILFIELD TECHN

OLOGY MAGAZIN

E JULY 2010

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VOLUME 03 ISSUE 03-JULY 2010

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Well arranged receivers for better definitionKim Gunn Maver, Henry Menkiti, Mark McCallum and Uwe Rinck, Schlumberger, France, UK and Canada, assess the benefits of and provide guidance for optimally deploying seismic data receiver arrays within wellbores.

Enhancing resolution of subsurface features, and thus optimising hydrocarbon reservoir management, depends heavily on using diverse methods of measurement and resolution.

Well log data provide a variety of high resolution measurements of the formation in close proximity to the wellbore. However, conventional logging’s depth of investigation is limited to within several feet of the reservoir surrounding the wellbore wall and falls short when it comes to characterising rock properties and fluid behaviour at the reservoir scale. Conversely, conventional 2D and 3D seismic data acquisition provides coarse detail at the reservoir scale, but not the kind of fine resolution needed to determine rock and fluid properties in a reservoir.

To improve the interwell image and provide higher resolution measurements than surface seismic, gravity, magnetic and electric data can, and deeper investigation than well logs can, receiver arrays are deployed within the wellbore.

Vertical seismic profiling (VSP), crosswell seismic and microseismic acquisition use receiver arrays in the wellbore. Acquiring high resolution data in the interwell space requires deployment of reliable receiver arrays, which in turn overcomes inherent issues within the well and mitigates risks to the well’s completion. As these three wellbore deployed receiver array technologies have been improved in recent years, it is now possible to substantially improve reservoir management with the data acquired in this fashion.

Furthermore, sensor arrays deployed in the wellbore can also have multiple purposes and can potentially be used to acquire data with more than one acquisition technology at a time, thus offering operational efficiency benefits.

Finally, important reservoir information is derived from the individual technologies, and the data can also reinforce each other through integration during both processing and advanced interpretation. The final reservoir model results become more accurate and reliable through cross technology verification.

This article provides an up to date overview of the three applications of well deployed seismic receiver arrays, how they are related, and the potential for data integration for better reservoir definition.

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Interwell imagingVSP, crosswell seismic and microseismic technologies use receivers deployed in the wellbore in proximity to the reservoir and are therefore able to record a higher fidelity reservoir related seismic signal, which improves the subsurface resolution.

The three wellbore deployed seismic receiver array technologies for interwell imaging are outlined in Table 1.

VSP is a mature technology with a well known application to provide higher subsurface resolution than surface seismic data can and deeper formation penetration than well logs can, but with imaging limited to the vicinity of the wellbore. Crosswell seismic and microseismic acquisition are newer technologies that the industry is still working on integrating into reservoir management workflows. Crosswell seismic data provide a seismic image further away from the well than VSP data can and with higher resolution, as well as a velocity tomography model. Microseismic data are a result of oilfield operations related to the reservoir. Production or injection

activity induces microseismic events through changes in pore pressure, and these events can be used to interpret the dynamic response of the reservoir.

There are opportunities integrating the hardware when acquiring the different types of data, and the measurements are somewhat complementary.

VSPVSP acquisition improves vertical seismic resolution by placing the receiver array in the wellbore. Higher resolution is achieved by shortening the ray path and limiting the signal attenuation. However, the subsurface coverage is only in the wellbore vicinity, in contrast to the greater areal coverage of surface seismic data.

A VSP survey (Figure 1) is the result of processing the data recorded by a downhole geophone when a source is activated on the surface. A series of closely spaced geophone levels is generally required for accurate VSP processing and interpretation.

A wireline tool equipped with receivers is deployed by means of a cable and clamped against the side of the borehole (open or cased), and shots are recorded by geophones placed in stationary positions at different depths. These shots (typically five) between levels are recorded and stacked for each depth, and then the tool is moved to the next position; typically, the spacing between levels in the well is regular and short (10 - 30 m).

A key factor in VSP evolution and improved efficiency has been the re-engineering of sensor packaging1. One integrated borehole seismic system provides improved signal fidelity through the use of small, three component (3C) sensor packages that are acoustically isolated from the main body of the tool (Figure 2). The isolated sensor

Table 1. Wellbore deployed receiver array technologies

VSP Crosswell seismicity Microseismicity

Seismic receiver arrays Variable position for VSP; fixed position in the upper wellbore for 3D VSP.

Variable position, determined by coverage required to image zone of interest.

Usually within the reservoir or just above the reservoir section.

Deployment A number of geophones deployed on a wireline and clamped against the side of the casing; source located on the surface.

Receiver array consisting of either hydrophones or geophones deployed in one well; source deployed in another well.

Geophones deployed using wireline or on tubing for later retrieval or cemented in place for permanent installation.

Acquisition Source triggered and moved on the surface in preset patterns to provide the required subsurface illumination.

Sources and receivers moved in a preset pattern in the wells to resolve the image at the reservoir section.

Events caused by pore pressure changes induced by reservoir production or injection; recorded by geophones.

Results 2D and 3D AVO seismic section with higher resolution than surface seismic data in the vicinity of or just below the wellbore. 2D and 3D time lapse results for repeat surveys.

2D seismic section with higher resolution than with either surface seismic data or VSP data in the interwell space at the reservoir section and 2D velocity tomographic model. 2D time lapse results for repeat surveys.

Located microseismic event provides continuous real time 3D information about stress changes in and around the reservoir.

Application Vp/Vs for AVO modelling; multicomponent surface survey design and processing calibration; improved definition of reservoir geometry; fluid movements from time lapse surveys.

Understanding reservoir geometry and rock properties from the 2D seismic section; details of fluid movements from time lapse surveys from both the velocity tomography and the seismic section.

Mapping induced fractures to highlight the effect of pressure change on the lithological framework, including caprock integrity, faulting and fluid front monitoring.

Figure 2. Sensors for VSP data acquisition.

Figure 1. Different VSP deployment and acquisition approaches.

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package, which houses the three axis geophones, is designed to keep all tool resonances outside the useful frequency of the seismic signal, as well as to achieve optimal coupling in all borehole conditions. This design ensures accurate recording of the seismic signal and results in true amplitude measurement on all three axes, ensuring outstanding vector fidelity.

Today VSP surveys are providing more accurate data and better processed images of the subsurface with dramatic reductions in

the amount of rig time it takes to record such surveys. Applications have grown to include large scale 3D projects delivering, in addition to checkshot and correlation information, products such as direct measurement of attenuation and spherical divergence, identification of interbed multiples, 2D phase analysis of surface seismic data, 3D match filtering of surface seismic data, and acoustic impedance inversion, among others. A point to note, VSP inversion is not as straightforward as surface seismic processing following migration. Having a fixed array downhole poses some limitations on existing techniques. Addressing these limitations will provide a means of utilising additional applications.

This solution was chosen for offset VSPs in two exploration wells offshore Mexico. The objective was to obtain high resolution compressional (P-wave, or Vp) and converted shear wave (S-wave, or Vs) seismic images as well as to investigate how the P-wave and S-wave amplitudes were affected by the presence of hydrocarbons. In the first well, receivers were spaced every 10 m up to 200 m in depth, allowing converted shear waves to be picked close to the seafloor and providing the first shear checkshot survey offshore Mexico. In the second well, VSP processing was integrated with drill bit seismic data recorded in the same well to deliver a complete borehole seismic answer.

Crosswell seismicCompared to VSP, further enhancement in vertical resolution and subsurface coverage may be achieved by placing both the receiver array and the source in different wells up to 1 km apart to image the interwell space2.

Crosswell seismic data provide higher vertical resolution imaging of the reservoir layers of up to 10 times better than surface seismic data3. Both direct arrival data and reflected information are processed to provide a detailed subsurface image of the reservoir or zone of interest. The crosswell seismic data improve the understanding of the reservoir geometry and rock properties from the reflection seismogram and provide details of fluid migration, including steam chambers, from both the velocity tomography and reflection seismogram.

Standard seismic receiver arrays run on 12 conductor wirelines and are built to withstand the rigours of the production well environment and to operate in vertical and deviated wells, and in both openholes and cased holes.

A total of 80 hydrophones are configured into 10 or 20 noise cancelling active arrays or levels with 3 m spacing. Signal preprocessing is distributed throughout the array for maximum sensitivity and signal-to-noise performance. Specially designed ceramic hydrophones ensure faster data acquisition and superior frequency response (100 - 4000 Hz) than geophones provide, which is critical for high resolution imaging. These hydrophones are specially developed to withstand wellbore temperatures and pressures. The systems are designed to operate with standard wellhead pressure control systems for optimum safety.

The source for acquiring crosswell seismic data can be piezoelectric or magnetically clamped. Both sources are borehole friendly and distribute the energy produced over a wellbore area large enough to prevent damage to the casing or cement4.

The crosswell seismic data acquisition is carried out by deploying a receiver array in one well and a source in another well (Figure 3). The source is moved up at regular intervals, emitting a controlled pulse measured by the receiver array in the other well and then moved to the next location with the goal of illuminating as much of the subsurface as possible through the aperture of

Figure 4. Comparison of crosswell seismic data and surface seismic data illustrating the substantially increased resolution in the crosswell seismic data.

Figure 3. Crosswell seismic imaging operations normally involve accessing two or more wells simultaneously.

the source locations and range of receiver locations. Once complete, several fans of raw data are acquired and processed, generating a high resolution 2D seismic section and a velocity tomography image in the interwell space.

Santa Rosa field in Venezuela, operated by state oil company Petroleos de Venezuela SA (PDVSA), is a structurally complex fluvial sand system with interbedded shales. In addition to the depositional complexity, post depositional faulting events further complicated and compartmentalised the reservoir. Crosswell seismic data were acquired to resolve the geological setting, thereby providing additional reservoir scale detail and allowing identification of the structural complexities for intelligent development of the field. Figure 4 shows a dramatic increase in resolution compared with the surface seismic and the ability to image features such as channel cuts and faulting. With this information PDVSA was able to define proper well spacing and drilling strategies to optimise gas production.

MicroseismicityMicroseismicity provides continuous real time information about the stress changes in the reservoir away from and between wells; the changes are caused by injection and production operations. Induced fractures can be mapped, and these changes in both space and time provide a unique insight into the effect of pressure change on the lithological framework and associated movement of reservoir fluids.

In connection with injection of proppants for hydraulic fracture monitoring, microseismicity is used to monitor the induced fractures even in real time. To monitor the reservoir when injecting drill cuttings, gas, H2S or CO2, induced microseismicity can indicate if the caprock is being breached or if faults are being reactivated to create a leakage path to the surface. When producing hydrocarbons from a reservoir, induced microseismicity may indicate which part of the reservoir has pressure communication and is being produced and highlight potential areas of bypassed hydrocarbons.

Microseismic events have, in general, a low magnitude: from Mw -4 to 1. To record microseismicity, a good microseismic sensing system that can consistently record high fidelity, low noise data that maximises the located event population is required.

To bring the sensors close to the reservoir to better record the low magnitude microseismic events, the sensors can be positioned in a well, and the viability of the microseismic sensing system can be modelled.

When monitor wells are available for installing microseismic sensing systems, this is not an issue. The microseismic sensing system can either be cemented in place for abandoned wells or left in the well for short or long term monitoring and then retrieved.

The limited availability of monitoring wells, especially in the oilfield environment, and particularly offshore, has meant that without an active monitoring well solution, microseismic monitoring is likely to remain a niche technology for reservoir management.

A tubing deployed clamp, which is released downhole to clamp against the casing for the geophones to be decoupled from the flow

noise, makes microseismic recording possible during well operation5 (Figure 5). Furthermore, a new design array of geophones with a tetrahedral pattern of four sensors at a 109˚ angle provides both long term reliability, if one sensor fails, and improved signal fidelity6.

To calculate the location, source and magnitude of the recorded microseismic events, a velocity model is developed for both Vp and Vs using available velocity information from well logs, surface seismic data and other data sources.

Microseismicity was recorded during a three step acid stimulation job using the clamping mechanism7. A single well was used for monitoring during the acid stimulation, which at the reservoir depth of approximately 15 000 ft was highly deviated. A two level, tubing deployed system clamping the sensors to the casing was used; the sensors recorded microseismicity during flow in the tubing.

Good quality microseismic events were detected and localised, as shown in Figure 6. The development over time of the microseismic events associated with the well stimulation indicates a pathway for the acid fluids away from the reservoir section reducing the impact of the well stimulation. After two months the microseismic sensing system was successfully retrieved, and a new stimulation strategy is being considered. The microseismicity highlighted a previously unknown permeable zone, which has since been included in the fracture network model and static model.

Joint data acquisitionOperational efficiencies can be gained by utilising the wellbore deployed arrays for multiple means of data acquisition.

Certain requirements of sensor position within the wellbore must be met for the various applications, and the seismic signal requirements should be considered. Table 2 shows the most widely used sensing elements and their basic specifications for the given acquisition application. Because of the recent broadening of the source frequency bandwidth for vibroseis, the measurement with accelerometer in the acceleration domain is beneficial in terms of amplitude and phase response at the low frequencies in comparison to the measurement in the velocity domain of standard geophones. The increased low frequency bandwidth does not require a higher sampling interval, but microseismicity and, in particular, crosswell seismicity will require a higher sampling frequency because of the nature of the signal source.

Table 2 shows a comparison of the various data acquisition techniques, which can have multiple applications without requiring a lot of changes to the equipment. State of the art modern data acquisition systems provide reliable time stable signal sampling at

Table 2. Overview of the technical specifications of sensors in the well

VSP Crosswell seismicity Microseismicity

Sensor 3C geophones (or accelerometers).

Hydrophones 3C geophones (or accelerometers).

3C geophones (or accelerometers) 4C tetrahedral geophones (or accelerometer).

Bandwidth 1 - 400 Hz 15 - 4000 Hz 15 Hz (1 Hz) - 900 Hz

Sampling rate 1 - 2 ms 0.25 ms 0.5 ms

Acquisition technique Source synchronous. Source synchronous. Nonsynchronous, continuous gap free acquisition synchronous to GPS time.

Acquisition time Days. Weeks. From days for hydraulic fracture monitoring to years for permanent reservoir monitoring.

Data volume Low for VSP to very high for 3D VSPs.

Large. Very large for raw data, low for detected microseismic events.

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the high sampling frequency rates required for all downhole seismic applications. Careful planning of the sensing system and the position inside the wellbore will allow the combination of the various source techniques.

To combine the applications of well deployed seismic receiver arrays, modelling should be performed, taking into account the different applications with the different receiver and source point positions for both surface and crosswell source positions. Planning the combined applications in advance can lead to a potential well positioning and installation of downhole sensor networks that may even allow a combination with surface seismic acquisition. Minimal adaptations to the acquisition system will allow long term stable acquisition with the potential of a full field network described earlier. 3C and 4C acceleration or velocity domain sensors can easily be combined and do not cause any acquisition obstacles.

Figure 6. The final processed microseismic events located in relation to the well trajectory. Red dots were the first phase of the well stimulation; green dots, the second phase; and yellow dots, the third and final phase.

Figure 5. Tetrahedrally arranged sensors used for microseismic data acquisition on the left. The clamp before it is deployed on tubing with the geophone on the right.

Integrating data acquired with well deployed geophonesImportant reservoir information is derived from the individual technologies, but the various datasets can also reinforce each other through integration during both processing and advanced interpretation. The final reservoir model results become more accurate and reliable through cross technology verification.

Crosswell seismic data have higher vertical resolution than VSP seismic data and even higher vertical resolution than surface seismic data. However, both crosswell seismic data and VSPs have limited lateral subsurface coverage. VSP seismic data only resolve in the proximity of the wellbore, whereas crosswell seismic data only resolve the subsurface in between well pairs some distance from the wellbore. The two measurements can therefore jointly illuminate a larger part of the subsurface, similar to a 2D surface seismic but with higher vertical resolution.

A valid velocity model is required to accurately locate microseismic events8. Velocity tomography from crosswell seismic data provides additional detailed velocity information in the interwell space, which is not available from other sources. The located microseismic events could indicate fracturing or activation of smaller faults, which may be visible only on high resolution crosswell seismic sections or VSP sections.

Fluid front monitoring is important to optimise reservoir production and locate bypassed oil. Tomographic velocity changes from the crosswell seismic data can potentially be related to the induced microseismicity due to changes in pore pressure. If time lapse crosswell seismic data and VSP data are acquired, both direct and indirect monitoring of the fluid front is possible, and the results can be used to update the dynamic reservoir model. O T

References1. NUTT, L., and MENKITI, H. [2004]: Advancing the VSP envelope. Hart’s E&P,

April 2004.2. ORTIZ, J. [2007]: Information-driven life-cycle reservoir management. World Oil,

October 2007.3. ZHANG, W., LI, G., AND CODY, J. [2002]: Understanding Reservoir Architectures

at Christina Lake, Alberta, with Crosswell Seismic Imaging. CSEG Recorder, May 2002.

4. WINBOW, G.A. [1991] Borehole stresses created by downhole seismic sources. Geophysics 56, 1655 - 1657.

5. FLOCH, G.L., JONES, R., and RINCK, U. [2008]: Microseismics moving into ‘live’ wells. American Oil and Gas Reporter, December 2008.

6. JONES, R., and ASANUM, H. [2004]: Optimal Four Geophone Configuration, Vector Fidelity, and Long-Term Monitoring. EAGE Amsterdam, May 2004, paper Z99.

7. MAVER, K.G., BOIVINEAU, A.-B., RINCK, U., BARZAGHI, L., and FERULANO, F. [2009a]: Real time and continuous reservoir monitoring using microseismicity recorded in a live well. First Break, July 2009.

8. MAXWELL, S., [2009]: Microseismic location uncertainty. CSEG Recorder, April 2009.

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