Second EAGE Workshop on Permanent Reservoir Monitoring 2013 – Current and Future Trends

In December 2012, Petrobras began the seismic survey of its first deep-water permanent reservoir monitoring (PRM) at Jubarte oilfield, in the Campos Basin. The Jubarte PRM seismic system equipment used was purchased from PGS/Optoseis™. The system comprises a fully 4C fiber-optic sensor array installed on the seabed and an optoelectronics controlling and recording unit installed on the topside of the floating production, storage and offloading vessel (FPSO) P-57. Upon completion of installation of the system in deep-water, Petrobras with PGS shall acquire active seismic data at least once a year using a seismic source vessel and passive or microseismic data between them.

Many of the arguments that are used for permanent seismic monitoring for offshore reservoirs also apply to onshore monitoring, but there are also differences. A permanent installation removes at least one source of repeatability problems, because there will be no receiver position differences between base and monitor surveys. For land surveys (and for Ocean Bottom Node surveys) receiver and shot position differences can be nearly avoided with careful acquisition, while for streamer surveys the unpredictable currents will always lead to some position differences, although tidal shooting and steerable streamers can reduce that problem. However, even perfect repositioning of sources and receivers will not solve all repeatability problems for land surveys because of the changing nearsurface between base and monitor survey. The use of buried sources and receivers will improve that situation, but even then careful acquisition and processing is required to remove, for instance, seasonally-changing source and receiver ghosts. This can be done successfully, as demonstrated in a permanent seismic monitoring trial of thermal EOR, in Schoonebeek, The Netherlands, where a seismic monitor surveys was acquired on a daily basis. The progress of the steam front could be monitored with surprising detail. Another similarity for offshore and onshore monitoring is that the economic benefits of a permanent installation, compared to surveys with retrievable equipment, materialize only after a number of monitor surveys have been acquired due to the upfront installation costs of the permanent system. If the changes in the reservoir are not very rapid, or if the operator of the field has no options to react with well management based on the rapid reservoir changes, then it becomes more difficult to make a business case for a permanent installation. The magnitude of the problem is more acute for onshore than for offshore applications, because onshore wells are typically significantly less costly than offshore wells. In this paper we give an overview of the results of the permanent onshore seismic monitoring trial at Schoonebeek and discuss the options to reduce the costs while maintaining the required accuracy of the monitoring results.

PGS has recently completed deployment of the world’s first, and to this date only, full-solution deep-water PRM project in the Jubarte field in Brazil for Petrobras. The project includes a fully fiber-optic system, topside installation on the FPSO, marine installation of the system in deep-water, the acquisition of active data using a shooting vessel, the acquisition of passive seismic data as well as data-processing of both active and passive data. In addition to describing the final solution and showing what was done, the paper shall also describe some of the steps done prior to implementation. This includes initial efforts to design, certify and build the system, followed by or in parallel preparations to deploy the system offshore. The presentation shall also briefly describe how the unique optical system works and its components. The system itself includes a wide range of different items – from top-side Opto-electronics to a riser, lead-in cables, a sub-sea hub with optical wet-mates, as well as the actual seismic array cables with optical 4C sensor stations over the field. This presentation may also cover some of the hurdles to introduce 4D PRM and permanent monitoring, as well as opportunities to overcome the same, if time permits.

PRM systems are known to provide excellent reservoir monitoring information. Still after ten years of operation of the first commercial system, PRM is in an experimental stage for most operators when considering methods of acquiring seismic data. Facilium has worked in more than twenty five projects, worldwide, with more than ten clients in attempting to establish PRM systems, and have been involved in all existing, some future and some lost cases. Some of the experience in the attempt to achieving sanction for investment in PRM is expressed in “The rock strewn path to sanction of PRM”.

Much time and effort is spent in obtaining internal approval for PRM systems, installing them, and then processing the raw data. But regardless of the justification used to approve a PRM system, the processed results are valuable only if the output is integrated with other data sets to understand reservoir dynamics in a context that influences business decisions. Long term reservoir monitoring in shale plays is achieved using permanently installed geophone arrays over areas of 400 sq km or more. The raw data from these systems are processed to locate microseismic activity associated with hydraulic fracture stimulation. This discussion will focus on a study performed on two adjoining pads in the Horn River basin, NE British Columbia where microseismic data is integrated with many other data sources to develop a set of usable predictive correlations to guide future development in the area. Other data incorporated includes seismic attribute volumes, well logs, FMI’s, production data, tracer data, pressure transient data, and core data. The specific results from this study may not be directly applicable to offshore reservoirs monitored by PRM systems, but the workflow for data integration are applicable to the development and depletion of any hydrocarbon system.

Permanent installations delivering frequent multiple time-lapsed seismic surveys offer many advantages to data processing and seismic inversion. It is natural that provision of seismic data at a time-scale scale closer to the production/reservoir engineer should open up a range of innovative technologies for 4D seismic interpretation such as pressure-saturation change estimation, connectivity analysis and history matching. However, these dynamic data must also be interpreted to ensure the time constants of the reservoir processes involved with production and injection are properly factored into the analysis. Whilst operational practicalities and budget usually determine the exact frequency and timing of survey shoots, the benefit of understanding the processes we discuss is that they help to further constrain the key controlling parameters of the reservoir fluid flow simulation model, and improve its ultimate forward predictive capability.

In recent years a new fibre-optic based technology, Distributed Acoustic Sensing (DAS), has emerged which has the potential to revolutionise permanent downhole monitoring. DAS uses a standard single-mode optical fibre deployed along the entire length of the wellbore as the sensor and is able to measure both acoustic and seismic signals along the wellbore. Fibre-optic cable deployed permanently in the well is now being used to monitor the fluid and proppant placement and in-flow along the production zone. Furthermore the fibre can be used to take Vertical Seismic Profile (VSP) measurements in wells where the deployment of conventional geophone is not possible. Once the DAS fibre is permanently deployed no further well intervention is necessary enabling low cost repeat measurements to be made. This technology has the opportunity to transform the ability to make time-lapse VSP measurements. In this paper, we will present further details of the permanent downhole applications for DAS and provide case studies of how DAS is being used in time-lapse VSP and permanent flow measurements.

In a collaborative project between Silixa, Weatherford and Statoil, simultaneous multiwell VSP data were successfully acquired using intelligent Distributed Acoustic Sensing (iDAS). The iDAS enables the use of an optic fibre as a massive seismic sensor array. In this field trial the iDAS was retrofitted to existing fibres installed for other purposes. Simultaneous measurements were carried out using 4 iDAS units retrofitted to fibres in three different wells coming up to the same platform. Several seismic lines were shot, e.g. one above each of the well tracks, while listening in the well directly below the shots and also in neighbouring wells at an angle to the shot line. All three wells were producing during the trial and the downhole seismic data were acquired without disturbing the well operations. Consequently data hold information about the flow in the well in addition to the seismic information.

The recent expansion of surface and near-surface microseismic monitoring during hydraulic fracturing has led to the development of techniques that are directly applicable to more general permanent microseismic reservoir monitoring. Recent work associated with surface and near-surface microseismic monitoring of hydraulic fracturing for shale gas in the Fayetteville and Marcellus formations has helped to develop new methods to process low signal-to-noise ratio (SNR) data. Improvements to the SNR by stacking the data using novel non-linear stacking techniques and stacking of perforation shots allows the use of Coalescence Migration Mapping (CMM), an established technique used for downhole monitoring, to detect and locate microseismic events from surface data.