A quiet revolution has been taking place in the geophysical community. Assisted by better measurements and faster processing, seismic data has become an essential tool for reservoir management. Using seismic to monitor the behavior of reservoirs in production is not a new concept, but it has taken some time to evolve from a theoretical principle to a practical necessity. By developing the ability to perform highly accurate time-lapse seismic surveys, production geophysicists have been able to observe and quantify changes in the data that can only be the result of fluid movement within the reservoir. This provides a heretofore unavailable macro-image of the reservoir’s behavior over time that can be used to calibrate sophisticated numerical simulators, long used by reservoir managers to predict performance.

The traditional role of seismic technology tended to mimic the conventional view of the

Figure 1. The Geophysical Continuum is illustrated in this seismic-to-simulation integrated workflow. (All graphics courtesy of WesternGeco)
lifecycle of a field; a linear process starting with exploration and ending with abandonment. Conventional seismic technology has delivered subsurface images, and buying decisions have been dictated by immediate imaging needs within the cycle, but without consideration for future imaging requirements. In addition, conventional seismic data are rarely of sufficient resolution or fidelity to reliably extrapolate quantitative maps of reservoir properties such as porosity.

Today’s dynamic exploration and production environment demands much more and advanced seismic technology plays a key role. With brownfield exploration, step-out exploration, and exploration near existing facilities, the lifecycle of a reservoir becomes a continuous loop. Seismic data buying decisions must take this into account. WesternGeco describes this cycle as The Geophysical Continuum, defined as the connected life cycle of an oil field where uncertainty is reduced by using high-fidelity geophysical measurements that are consistently calibrated with all other oilfield measurements (Figure 1).

A major factor enabling fast turnaround has been the use of Q-Technology single-sensor seismic hardware and software developed by the service company to deliver advanced seismic measurements that can span the life of a reservoir. The key to unlocking this potential lies in making fundamentally better seismic measurements that deliver greater reservoir detail, allowing seamless calibration with other geophysical and borehole data. The technique reduces uncertainty between wells and provides operators with a greater degree of confidence. The final link in the chain was forged with the recent acquisition of Odegaard, a company with technology that bridged the gap between geophysicists and reservoir engineers. Also instrumental in facilitating communication between geoscientists and engineers has been the introduction and development of high-resolution 3-D dynamic visualization — seeing is believing.

On the horizon
With deepwater wells costing US $25 million or more to drill, operators face three main challenges — reducing exploration risk, reducing upfront costs and protecting their
Figure 2. Time-lapse (4-D) monitoring helps identify changes in water saturation indicated by increases in acoustic impedance that signify encroaching water levels or injection water breakthroughs.
investment. They can accomplish these objectives by using complementary technology to narrow the search and improve the likelihood they will discover a hydrocarbon-bearing structure before they spud the first well. New planning and design software helps operators assess the potential risks and rewards of each technology application before investing. Economical broad-brush bathymetry/gravimetry (B/G) surveys and magnetotellurics (MT) can identify sedimentary features and indicate the thicknesses of resistive strata, respectively. Single-sensor marine seismic provides definitive 3-D seismic imaging, and is able to define images beneath salt layers. Finally, once a promising structure has been imaged, controlled source electromagnetic surveys (CSEM) can define the areal extent of hydrocarbon reservoirs within it.

Seamlessly integrating these technologies produces a super-refined geophysical survey, hence improved prospect knowledge and reduced decision-risk. Low cost Bathymetry (seabed profiling) and gravimetry (subterranean structure profiling) combine to identify sedimentary features such as fluvial channels and deltaic fans. This technique can quickly image large areas helping to indicate those with highest potential for more detailed investigation. Economical magnetotellurics (MT) indicates the presence and thickness of subterranean resistive strata. MT is particularly suited for deepwater exploration where its sensitive signal is not degraded by interference from roads, trains and populated areas. Used sequentially, these technologies can greatly reduce exploration risk by identifying the most promising areas for detailed seismic exploration.

Very high-resolution single source seismic provides unprecedented 3-D images of the subsurface for modeling and pinpointing of drilling targets as well as identifying potential drilling hazards to be avoided. Resistive beds as thin as 3 ft (1 m) can be imaged, provided they have significant lateral extent. Interpreters can establish four-way closure and identify the structure. Finally, augmented by quality seismic data, interpretation of CSEM surveys can reveal the presence and areal extent of hydrocarbon bearing strata, reducing exploration risk. Planning software can pre-qualify a potential target to indicate its suitability for CSEM investigation before an investment is made.

The enhanced knowledge provided by these technologies and techniques when integrated into the 3-D whole earth model can effectively reduce exploration and drilling risk.

New reserves at Norne
To see how the seismic-to-simulation concept works in practice, the results of a recent 4-D seismic survey project (with surveys made in 2001, 2003 and 2004) helped operator Statoil monitor fluid movements, improve planning of in-fill drilling, improve the field recovery factor from 40% to 52% and extend field life beyond 2015.

For example, a seismic slice using base survey data showed acoustic impedance relative to water saturation curves from the well logs. Then, by looking at the difference between the 2003 data and the base survey, a 4-D feature was seen just above the original oil-water contact. The feature was mapped using 3-D to grow an image of the difference between the base and 2003 surveys. This technique was applied to different areas of the field with similar results, namely, an increase in acoustic impedance (AI) caused by water replacing oil as the reservoir fluid (Figure 2).

Predicting drainage patterns that conform to a previously developed model is not very exciting, but can certainly validate the technique. The real value comes when the 4-D results show changes not predicted by the model. This happened several times at Norne, in the Norwegian sector of the North Sea.

How this is done can be illustrated by examining the seismic section with formation tops and projected development well plan superimposed (Figure 3). Original development plans called
Figure 3. Differences in acoustic impedance signaled localized water encroachment through a leaking barrier and caused the operator to redesign the proposed horizontal drainhole. The original well plan (black) was too close to the water. The revised well plan (gray) will add to the reservoir’s productive life.
for a well to be drilled to drain the Ile reservoir as shown by the black well trajectory line. A carbonate cemented barrier had been interpreted to lie between the Tilje and Ile formations and pressure data taken from several offset wells indicated this to be a sealing barrier. The acoustic impedance differences between the base 2001 survey and the 2003 survey can be seen (reds indicate an increase in AI between base and 2003 and blues indicate a decrease in AI over the same period). It is obvious that water has penetrated the supposedly sealing
carbonate barrier and was encroaching on the base of the Ile formation. When the 3-D geobody was grown to map the volume represented by the 4-D effect caused by the oil being replaced by water, it was clear that the proposed well path was very close to the new oil-water contact. In fact, the toe of the proposed well was right in the middle of a water zone. The 4-D results were processed onboard the survey vessel and delivered within a week of acquisition. As a result of this interpretation, over the following seven days Statoil revised the well track placing it in the same reservoir, but above the indicated new water level (indicated by the gray well trajectory line). The well was drilled on the new trajectory and flowed 25,157 b/d of oil with no water on start up.

Time and again 4-D results have been used to verify the accuracy of the reservoir model, or conversely, to dispute it. Norne’s complex geology is a perfect candidate for time-lapse seismic, and confidence in Statoil’s ability to make correct predictions has grown as production tests confirm decisions made as a result of using the seismic-to-simulation approach.

The tie that binds
Whether the driving force is adding or replacing reserves, increasing production, maximizing recovery, unlocking unconventional hydrocarbon potential or some combination of these, the links are strengthened. By treating reservoir management as a continuous lifecycle, operators benefit from the synergies that derive from a fully integrated service company. What engineers like to call “from pore to process” is mimicked by the “seismic to simulator” approach. Together they form a powerful bond that can deliver valuable knowledge for the life of the reservoir.