Advanced time-lapse seismic acquisition technology improves repeatability by greatly reducing noise and positioning problems that previously impeded reservoir management.
The Norne field in the Norwegian Sea demonstrates the impressive insights now accessible through time-lapse seismic data. The surveys are more than just a means to image the Norne reservoir - they reveal how the reservoir is reacting to the production process, and they play a vital role in reservoir management.
To properly evaluate subtle changes in reservoirs, a repeat seismic survey must replicate the previous survey. New seismic acquisition systems such as the Q-Marine single-sensor system are demonstrating that they can control the major acquisition factors that affect repeatability - background noise and positioning of sources and receivers - better than conventional systems. Streamer steering, a fully-integrated positioning network, calibrated marine sources and single-sensor recording set time-lapse surveys acquired with these systems apart from conventional time-lapse surveys. In addition, the inherent repeatability of the data eliminates the need for special processing to match the surveys. The simplified processing contributes to shorter project cycle times, which means the maximum value can be obtained from the data.
The Norne challenge
The Norne field offshore Norway epitomizes many of the challenges of economically producing oil and gas in the Norwegian Sea and North Sea (Figure 1). Discovered by operator Statoil and partners in 1991, this billion-barrel field is currently in decline, with daily production of approximately 126,000 bbl of oil and approximately 176 MMcf of gas supported by water and gas injection. The produced hydrocarbons flow to a floating production, storage and offloading vessel (FPSO) moored in the middle of the field. Before installing the FPSO, Statoil acquired a conventional towed-streamer seismic survey in 1992 that covered the entire Norne field.
Statoil decided early in the life of the Norne field to acquire time-lapse seismic data to optimize field development by monitoring the movement of oil and gas in the reservoir, paying special attention to the oil/water contact (OWC). As part of that effort, the company also wanted to compare reservoir-simulation results with time-lapse seismic data.
A critical aspect of time-lapse seismic technology is ensuring that the differences between the seismic surveys represent actual changes in the reservoir rather than differences in how the surveys were acquired. The Norne field presented special problems because the presence of the FPSO meant that seismic acquisition vessels would not be able to pass directly over the central part of the field. WesternGeco and Statoil seismic acquisition specialists and geophysicists prepared an integrated project design (IPD) study to ensure that the Q system would offer higher quality data and better repeatability than a conventional seismic survey.
Analysis of the 1992 conventional 3-D survey, well data and oceanographic information over Norne field helped optimize acquisition parameters. Geophysicists analyzed existing seismic data and vertical seismic profiles to understand the bandwidth and noise characteristics of the survey area. The IPD study incorporated results from the first two repeatability test swaths acquired over Norne in 2001 and reservoir production histories to model the expected changes in reflectivity due to changes in saturation and pressure. The modeling results indicated that there would be a low level of noise and that the expected time-lapse signal would be visible after fewer than 2 years of oil and gas production.
The project-planning study also addressed safety concerns, including the expected weather conditions and prevailing currents. The acquisition team developed contingency plans and rehearsed for events such as loss of propulsion by the acquisition vessel. Although such an event is unlikely, the presence of the FPSO meant that a drifting vessel would pose a significant hazard.
The initial survey was acquired in less than 3 weeks during August 2001. The Geco Topaz acquisition vessel towed six 10,499-ft (3,200-m) streamers with 164 ft (50 m) of separation and steering fins at 1,312-ft (400-m) intervals along the streamers. An undershoot with the Western Pacific minimized the repeatability hole in the seismic survey around the Norne FPSO. Streamer steering made it possible to acquire data within 131 ft (40 m) of the Norne FPSO (Figure 2). In June 2003, the Geco Topaz acquired the first repeat marine survey, making Norne the first field to have time-lapse Q-Marine data.
The 2003 monitor survey was quickly compared with the 2001 baseline survey. For quality control during acquisition, the survey crew monitored ambient noise, source and receiver positioning, and seismic repeatability to ensure that subtle changes in signal from the previous survey would be discernable and preserved. Within days of the end of acquisition, Statoil was able to use the data to determine the location of the OWC, evaluate the progress of water injection and update the reservoir model to revise horizontal infill-drilling plans.
The steered streamers reduced streamer feathering and dramatically improved repeatability of the Norne data (Figure 3). A key repeatability metric, the normalized root-mean-square (NRMS), quantifies results of various types of noise, including positioning errors and random noise. Between the 1992 conventional survey and the 2003 survey, NRMS from a volume that includes the reservoir interval exceeded 26% in 35% of the seismic volume. Between the 2001 and 2003 surveys, 66% of the seismic section had less than 10% NRMS. The smaller the NRMS, the better the repeatability and the greater the confidence in the 4-D results. Qualitative examination of seismic sections also reveals the difference in repeatability between the conventional survey and the newer surveys (Figure 4).
Subsequent detailed processing of the Norne surveys onshore included surface-related multiple elimination (SRME) and Kirchhoff prestack migration. This processing improved the definition of the time-lapse signal and allowed for analysis of time-lapse amplitude variation with offset (AVO) on fully migrated gathers.
Immersive visualization highlighted changes in acoustic impedance between surveys - places in which water replaced oil in the reservoir. A well path Statoil originally planned landed in an area where the seismic data changed between the 2001 and 2003 surveys, suggesting that the OWC had already breached a horizontal permeability barrier. By moving the horizontal well path laterally and 131 ft (20 m) higher, Statoil was able to target oil, saving US $29 million - the cost of drilling another horizontal sidetrack. In addition to improving well planning, engineers were able to adjust production and injection rates and to observe movement of the waterflood front.
Statoil planned to acquire a third Q survey of the Norne field in 2004, approximately 13 months after the previous monitor survey. Ultimately, the company seeks to use time-lapse seismic data to increase recovery from 40% to 52% and to extend the life of the field beyond 2015.
New insights from time-lapse seismic data
Seismic technology, a key to improved exploration success rates over the past few decades, is now an established technology for reducing risk and uncertainty in subsequent stages in the lives of oil and gas fields. In many cases, the survey cost is a small fraction of its value in terms of minimizing development drilling costs and in recovering additional hydrocarbons. Time-lapse seismic surveys, calibrated with well log and borehole seismic data, help identify fluid types, map fluid saturations and flow barriers between wells, and enable operators to make more informed drilling, development and reservoir-management decisions.
To extract maximum value from time-lapse data, seismic repeatability must continue to improve. Improved repeatability will allow oil and gas companies to see time-lapse signals within repeat surveys in a matter of months rather than years and to detect the very small changes in reflectivity normally associated with hydrocarbon production from carbonate reservoirs. This shorter time frame will facilitate more active and timely reservoir management.
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