Historically, subsurface exploration specialists have strived to predict lithology and fluid content from seismic data prior to drilling, but many times Mother Nature has fooled them with a dry hole when the drill bit finally penetrates the target level. Once a field has been discovered and developed, the reservoir development specialists have a significant advantage over the explorationist by having available rock and fluid property data measured at wells to integrate into the reservoir model. When calibrated with production data, 4-D seismic can yield pressure and saturation changes in units of pounds per square inch and saturation percent with measures of uncertainty. Such information can be used as input into reservoir simulators to forecast future performance as well as for the direct identification of areas of bypassed pay and isolated fault blocks.
"Certainly knowing which areas of a reservoir are changing has qualitative value to operators, but with the quantitative 4-D analysis that we have developed recently, it is now possible to directly estimate the underlying changes in pressure and saturation that cause the 4-D seismic changes, in engineering units with uncertainty analysis," said Dr. David E. Lumley, president and chief executive officer, 4th Wave Imaging. "Armed with seismic-derived engineering data such as this, asset managers can significantly reduce the risk in their investment decisions. Quantitative pressure and saturation results of this type promise to bring accelerated adoption of 4-D seismic in development planning and reservoir management."

What does it take to be successful?
One of the key elements in 4-D success is a reservoir whose production-related changes will lead to observable 4-D seismic changes. This is not always intuitive and requires screening and feasibility studies to estimate the expected changes with production and a determination if such changes could be detected with available seismic data. Along with this technical assessment the asset team must envision how such information could be applied to improve its asset management strategy. This implies that team members have a good understanding of the rock and fluid properties and how they will change with various reservoir producing mechanisms. In order to have this understanding, core and fluid samples must be collected and analyzed during the exploration/appraisal phase.
Team members also need repeatable, high-quality seismic data such that the seismic changes can be detected and compared. Seismic data quality and repeatability are two of the variables over which operators/contractors do have some control. Again this is part of the cost-benefit exercise: Is it worthwhile to invest in steerable acquisition or to over-sample the data to make sure you have repeatable shots? Is there something that can be done to increase the frequency content of the data to improve resolution? The project may have a 3-D survey that was sufficient for exploration and appraisal purposes but would not meet the needs of being a good baseline survey, thus requiring a new survey prior to production.
Even with good-quality seismic data, the data needs to be processed so that the team is looking at reservoir changes rather than artifacts from either acquisition or processing. Because we are looking at small seismic differences (such as amplitude and time-shifts) in 4-D projects, minor problems in many of the standard processing steps (statics, phase, etc.) can cause significant difficulties in quantitatively analyzing 4-D datasets. For the area of study, calibrated relationships must be developed between seismic attribute changes and reservoir changes. Some of the required relationships are the understanding of how dry bulk modulus (Kdry) and dry shear modulus (Gdry) change as a function of porosity, clay content and pressure.
An example - Gullfaks
Statoil's Gullfaks field has a set of reservoirs where 4-D seismic has been successfully applied to map changes in pressure and saturation. The main producing reservoirs are variable-thickness Jurassic sands up to 900 ft (300 m) thick in the Brent, Cook and Statfjord formations. Statoil was interested in anomalous production rates in the study area. The company acquired repeat streamer surveys in 1985, 1996 and 1999, and the seismic differences that occurred between these vintages of data sets were analyzed. The various seismic data volumes were cross-equalized and amplitude vs. offset (AVO)-balanced. A proprietary software application was then applied to invert the time-lapse seismic datasets to produce quantitative estimates of reservoir pressure and saturation change. The pressure-saturation inversion (psi) is calibrated with production data at well locations to derive the actual engineering units of pore pressure and fluid saturation.
(This information first appeared in First Break volume 21.)

Summary - application
Although there is good overall agreement between psi and the well-based drainage map as shown in Figure 1, there are important differences when you examine the details. The red arrow on the left shows one area where Statoil was uncertain whether oil had been produced. The psi saturation map shows no change in this area, indicating that the oil rim had not been produced by 1999 and probably remains as bypassed oil today.

Application:
Identification of areas already swept;
Identification of unswept areas;
Sealing nature of faults;
Identification of areas of over-injection; and
Indication of possible vertical and lateral communication.

These have led to:
Identification and drilling of new opportunities;
Dry hole avoidance by not drilling proposed wells in wet areas;
Modification of injection rates and volumes;
An improved reservoir model;
Additional reserves and improved return on investment; and
Avoidance of drilling problems by knowing pressure distributions.
For more information, visit www.4thwaveimaging.com.

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