Seismic data is not just for exploration anymore. New techniques are being applied throughout the life of the field.

Oil and gas operators are improving their performance in finding, appraising, developing and managing their reservoirs by combining high-quality seismic data with logging, vertical seismic profiling (VSP) and reservoir production data. Through careful calibration, including rock physics modeling, seismic information can help asset teams more accurately determine reservoir structure and properties, and reduce risk and uncertainty at any stage in the life of a field.

Modern 3-D seismic technology has helped reduce the costs of finding and developing oil and gas reserves. It is credited with enabling exploration in deep water, imaging moderately complex geology using prestack time and subsalt depth imaging, and improving early field appraisal and development decisions. Initially, 3-D seismic technology was used primarily as a niche delineation/development tool because it was considered too expensive for exploration. However, the improved imaging and reduced uncertainty it delivered caused it to quickly become a standard tool in exploration. Over the last 20 years, 3-D seismic technology has helped reduce the uncertainty in reserves estimates and enabled operators to locate reserves in increasingly challenging structural and stratigraphic traps.

Now the role of seismic technology has come more than full circle and today is helping asset teams monitor their reservoirs, enhance production, increase recovery and maximize economic value throughout the life of the field. New seismic services such as Q-Marine technology from WesternGeco, in addition to improvements to established services such as depth imaging, attribute analysis and inversion, have extended the capability and value of 3-D seismic applications, again by timely delivery of improved imaging solutions with reduced uncertainty. Q-Marine technology represents advances in calibrated source signatures, single-sensor acquisition, a dense acoustic positioning network, and steerable streamers. Source signatures are measured on every shot, allowing source variations to be corrected in processing. Single-sensor acquisition provides dense sampling of both the wavefield and noise, allowing processing steps that enhance the signal while reducing the noise. This, in turn, permits acquisition designs that enhance bandwidth at both ends of the spectrum, such as shallower streamer depths and minimal low-frequency acquisition filters.

Several areas of oil and gas drilling and exploitation can benefit from the use of seismic information.

Avoiding drilling hazards

The industry spends about US $20 billion annually on drilling operations. About 15% of that total (around $3 billion) is attributable to lost time and equipment. Unexpected, abnormally high formation pressures (geohazards) are a major cause of these drilling losses. As the focus of exploration moves to deeper oil and gas targets, assessment of potential geohazards with seismic attributes has become an integral part of well planning. When compared to the cost of drilling operations, the cost of hazard prediction is minor and the benefits substantial.

One multiclient survey over a deepwater producing field in the Gulf of Mexico helped identify de-watering features (mud volcanoes) and gas hydrate reflections that could be hazardous to drilling operations. In another multiclient survey in the Gulf of Mexico, AVO inversion is used to identify shallow water flow (SWF) hazards as high Vp/Vs zones (figure 1). Abnormally high Vp/Vs ratios indicate zones that may be overpressured and in the near-surface sediments suggest potential drilling hazards.

Reducing development risks

On any field development risks are huge, but these risks are magnified as operators move out into the deepwater provinces and even exploit deeper and more complicated assets in shallow-water areas. Seismic data reduce many of these development risks, particularly as they relate to appraising the subsurface and designing the topside facilities and well locations to optimally produce the hydrocarbons.
Field appraisal typically involves drilling several wells in an effort to understand subsurface structure and characterize the reservoir flow potential. Three-D seismic data interpretation has played a major role in exploration but often lacks the detail and reliability needed to greatly impact field appraisal. This can change with higher-resolution results that provide detailed structural images that better define reservoir size and internal complexity. With this information, appraisal well locations can be chosen more carefully, and fewer wells may be required.

The cost of facilities, such as platform type and size, pipeline and water handling capacity, number of wells, and injection/production facilities, accounts for a significant portion of reservoir development expenditures. Offshore, there is often just one opportunity to make these decisions, and that is before production begins. Poor decisions lead to injection and production limits that cap plateau production rates, oversized facilities that unnecessarily inflate upfront CAPEX, and production contracts that can't be honored. Remedial actions to correct these poor decisions are inevitably more expensive than spending more money on useful data up front.

Therefore, high-quality seismic data that can provide appraisal-quality information about the reservoir volume, fluid contacts and possibly even reservoir drive mechanism are instrumental in making these early decisions the right decisions. In addition, time-lapse seismic information is increasingly recognized as critically important to optimally developing a field, so deepwater assets are being developed in phases that allow additional seismic data and reservoir performance to impact the decisions on what permanent structures will be installed.

Using both 3-D and multicomponent seismic analysis, operators can design well locations and trajectories to ensure that appraisal and development wells contact more reserves while reducing risk and uncertainty in development planning. One of the greatest of these risks is not producing the reserves expected, and one of the major causes is internal reservoir structure that effectively compartmentalizes the reservoir. High-quality seismic technology is increasingly producing images and attributes that identify faults and fractures that control fluid movement and even image the fluid movement itself with time-lapse surveys. This knowledge of reservoir structure and flow reduces the risk of leaving recoverable reserves in the ground and allows the operator to make more meaningful economic projections over the life of the field.

Understanding reservoir flow

Time-lapse 3-D (4-D) seismic surveys have been a growing technical success and for some operators have greatly influenced key reservoir management decisions. For example, Statoil recently conducted the first Q-on-Q 4-D survey over the Norne Field in the North Sea (figure 2). The monitor survey was acquired less than 2 years after the baseline survey yet provided a key deliverable within 2 weeks of the completion of acquisition: a visible 4-D effect that resulted in Statoil officials changing their drilling plans less than a month after data acquisition was complete. "High-resolution fast-track results helped with the horizontal drilling plans," said Bard Osdal, senior geophysicist at Statoil.

Setting very specific performance objectives and minimizing the data acquisition, processing and analysis turnaround time is transforming 4-D from a successful technical experiment to a key business tool.
Increasing recovery factor

Given the high cost of field developments, operators have recognized that it is often more economical to seek higher recovery factors in existing fields rather than leave oil in the ground and rely on new developments. Reservoir characterization and simulation models are at the core of modern asset management, and the quality of these models influences the success of well performance, field development and, ultimately, hydrocarbon recovery. As the field is developed, each new well provides an additional calibration point, and as the field produces hydrocarbons, it also produces valuable information about the production characteristics of the field.

In figures 3a and 3b, a multiattribute classification process, utilizing both the log and seismic data to establish a relationship between seismic attributes and lithology, generated the sand probability section. In 3-D (figure 3b), the complexity of possible injected sand bodies is evident, illustrating the need for high-quality seismic data to observe and map such features.

These features appear to be connected to the main reservoir area but may not be produced with the existing well pattern. Therefore, to increase the recovery factor in this field, it may be necessary to alter the development strategy, perhaps including a new or sidetracked well. Such a decision is only possible with confidence in the reservoir characterization.

Delaying abandonment costs

Towards the end of the reservoir life cycle, high-fidelity 3-D surveys, calibrated and inverted to rock and fluid properties, can enhance late-stage development programs. Guided by seismic information specific to their reservoirs, asset teams are able to target small compartments efficiently and identify attic hydrocarbons, which can then be recovered at low marginal cost. Further, the same seismic survey can be used for near-field "exploration" to find hydrocarbons on the flanks, above or below, the reservoir at minimal finding cost. This approach extends field life, makes use of existing production facilities, delays abandonment costs and boosts overall return on investment.

A survey was acquired over a mature field in the Brent Province of the North Sea with the objective of improving the characterization of the interwell region and so target bypassed hydrocarbons. If successful, the impact would be to help maximize recoverable reserves and extend the economic life of the field. Processing and inversion provided a clear and sharp fit with the existing well data, giving increased confidence in the inversion results. Further, the improved spatial and temporal resolution has allowed the operator to map the fine geological details within the reservoir and enabled, for the first time, mapping of individual sand bodies. This has greatly improved confidence in well planning and may extend the economic life of the field.

Summary

Every hydrocarbon-producing basin presents its own opportunities and challenges. Modern seismic methods help operators boost the net present value of their field and resolve specific problems such as right-sizing facilities, optimizing infill drilling and locating bypassed zones. The seismic techniques that operators choose to apply will, naturally, reflect their needs and the characteristics of the asset. In underexplored regions, seismic technology will continue to be an indispensable tool for exploration and field delineation. However, in developing and maturing oil provinces, new seismic technologies are being engineered and used as flexible tools for reservoir management and optimization.