Four-Dimensional Seismic Data

Key Takeaways

• The repeatability of 4D seismic is the critical technical challenge that determines whether the 4D signal (the difference between monitor and baseline) can be distinguished from noise: if the monitor survey is not acquired with the same geometry, the same source characteristics, the same receiver coupling, the same processing sequence, and the same environmental conditions as the baseline, differences between the surveys may reflect acquisition and processing effects rather than actual reservoir changes; the NRMS (normalized root-mean-square of the 4D difference in the overburden, where no real change is expected) is the standard repeatability metric, with NRMS values below 15% considered excellent (typically achievable with permanent seabed cable systems), 15-25% good, 25-40% acceptable, and above 40% indicating poor repeatability where the 4D signal is overwhelmed by non-repeatable noise; the North Sea Foinaven, Grane, and Valhall fields, which installed permanent ocean-bottom cable (OBC) systems on the seabed above the reservoir, consistently achieve NRMS values below 10% and have produced the most reliable 4D seismic results in the industry because the receiver position is exactly the same for every monitor survey; the Norne field in Norway, monitored by repeated conventional streamer surveys over 20 years, achieves NRMS values of 25-35% that are sufficient to track major waterflood fronts and gas cap expansion but insufficient to resolve fine-scale reservoir heterogeneity details.
• Fluid saturation versus pressure discrimination in 4D seismic interpretation uses the different signatures of saturation change and pressure change to separately map oil-water contact movement (saturation-driven signal) from compaction and pressure depletion effects (pressure-driven signal): oil replacing by water (imbibition) increases the bulk modulus of the pore fluid and decreases the acoustic impedance of the reservoir relative to the waterflood front — a positive 4D amplitude change in most reservoir settings; gas replacing oil (during solution gas drive below the bubble point) dramatically reduces the bulk modulus and acoustic impedance, creating a very strong negative 4D amplitude change that is often detectable even when the gas saturation is only 5-10%; pressure depletion without saturation change affects seismic response by changing the effective stress on the rock frame (increasing effective stress as pore pressure decreases, stiffening the rock and increasing velocity) and by triggering gas exsolution at the bubble point (creating a saturation change effect); Gassmann's equations, combined with laboratory measurements of rock and fluid properties at reservoir conditions, allow quantitative prediction of the expected 4D amplitude response for different scenarios of fluid substitution and pressure change, providing the rock physics framework needed to interpret 4D observations in terms of specific reservoir processes.
• 4D seismic production monitoring has transformed reservoir management decisions for waterfloods and gas injection projects by providing field-scale maps of sweep efficiency (how much of the reservoir has been contacted by injected fluid) that cannot be obtained from any number of wells; at the Forties field in the UK North Sea, 4D seismic surveys conducted at 3-5 year intervals between 1997 and 2020 identified multiple unswept volumes between wells that were subsequently targeted by infill drilling campaigns, adding over 100 million barrels of recoverable reserves to the field's production base; at the Ekofisk chalk field in Norway, 4D seismic successfully imaged the spreading of the water injection front in the fractured chalk reservoir, allowing operators to redirect injection to better contact unswept zones and to identify the dynamic drainage patterns controlled by natural fracture corridors that were invisible in the static 3D seismic data; the Sleipner CO2 storage project has used 4D seismic monitoring since 1999 to track the growth of the injected CO2 plume in the Utsira Sand, producing one of the world's most detailed datasets on CO2 storage behavior and validating geomechanical and flow models for CO2 containment.
• Permanent reservoir monitoring (PRM) systems using permanently installed ocean-bottom fiber optic cables or node arrays have transformed 4D seismic from a periodic intervention (requiring a vessel survey every 3-5 years) to a near-continuous monitoring capability (acquiring monitor surveys every few months or even continuously for some distributed acoustic sensing systems): the PRM system at Ekofisk, installed in 2010, has recorded over 30 high-quality 4D surveys in the subsequent decade, providing time resolution of fluid movement that shows seasonal pressure variations, response to individual workover events, and the dynamic interaction between producer-injector pairs on timescales of weeks to months that periodic conventional surveys completely miss; the cost of installing a PRM system (typically $50-100 million for a large offshore field) is justified by the improved production management decisions enabled by continuous monitoring — faster identification of bypassed oil, earlier detection of injector breakthrough, and better allocation of infill drilling capital to the highest-value unswept targets; PRM is now standard infrastructure in new field development design for major offshore fields in Norway, the UK, Brazil, and the Gulf of Mexico where the value of improved recovery factors from better sweep management exceeds the PRM installation cost within a few years of production.
• 4D seismic feasibility studies determine whether the expected reservoir changes will produce a detectable 4D signal before committing to the expense of a monitor survey acquisition, by modeling the Gassmann fluid substitution response (the change in seismic amplitude at the reservoir level due to the expected change in fluid saturation and pressure) and comparing it to the expected noise level (NRMS) for the survey design: the key parameters in a 4D feasibility assessment are the reservoir's fluid sensitivity (the change in seismic impedance per unit change in water saturation or gas saturation, which depends on the reservoir rock's compressibility, porosity, and the acoustic impedance contrast between the pore fluids), the expected saturation and pressure changes over the planned monitoring interval (from reservoir simulation), the NRMS achievable with the planned acquisition geometry (estimated from local experience or from published repeatability statistics for similar acquisition designs), and the minimum detectable change (the amplitude change that exceeds the background NRMS by a factor of 2-3); high-porosity, unconsolidated sands with large fluid impedance contrasts (the Gulf of Mexico deepwater sands, the Norwegian Sea Brent reservoirs) have excellent 4D feasibility, while tight carbonates, deep chalk, and low-porosity sands have poor 4D feasibility because the rock frame is too stiff to show significant fluid sensitivity.