Seismic Evaluation of Hydrocarbon Saturation in Deepwater Reservoirs
This project will develop and calibrate tools for better seismic identification of in situ pore fluids and improve our ability to estimate hydrocarbon saturation.
Colorado School of Mines
College Station, TX
University of Houston
Paradigm Geophysical Corp.
Results We have demonstrated that with careful calibration, direct hydrocarbon indicators can better distinguish between uneconomic ‘Fizz’ gas and economic hydrocarbon reservoirs. Some of this progress comes from better characterization of fluid and rock properties. Other aspects include alternative techniques to invert surface seismic data for fluid types and saturations. We have also developed improved work flows for accurately measuring frequency dependent changes in seismic data that are predicted by seismic models, procedures that will help to more reliably identify anomalies associated with hydrocarbons.
We have been prolific in publishing expanded abstracts and presenting results, particularly at the SEG. This year, we had eight such papers to promote technology transfer
This research project has focused on improving our ability to identify and quantify in situ fluids. This lowers the risk in drilling new prospects and improves our capability to monitor fluid motion and exchange in producing reservoirs. The prime benefit locally is an incremental improvement in discovery efficiency and cost. On a larger scale, this also improves our ability to find and assess deep-water resources as a national asset.
Drilling in the deep water environment is expensive and risky. Seismic data has improved to where different pore fluid types can be distinguished. However, many ‘dry’ holes continue to be drilled, often due to ‘false’ hydrocarbon indicators.
This project was designed to develop and calibrate techniques to better identify fluid contents at depth. These include methods to make more valid estimates of fluid properties, better ways to calculate the fluid response in rocks, and techniques to distinguish interfering effects resulting from thin beds, low resolution, invasion, etc.
Several approaches have been taken to improve our ability to identify in situ fluids:
- Rock and fluid properties are systematic and can be predicted
- Correct values must be used to properly calibrate deep-water seismic data
- Turbidite reservoirs have geometries that can be identified in field data
- These geometric effects have been quantified and their influence examined
- Hydrocarbon indicators have been compared and evaluated for fluid sensitivity
- Inappropriate processing procedures have been identified and documented
- Inversion techniques have been developed to better distinguish hydrocarbons
- New processing work flows for frequency-dependent anomalies were developed
- The effects of attenuation have been evaluated and applied as an indicator
- A final technology transfer symposium is scheduled for April, 2006
Current Status (June 2006)
The project was successfully completed on April 30, 2006. To this end, we completing our theoretical developments, generating recommended processing flows, and perfecting our rock and fluid properties interpretation techniques. Some minor additional data analysis and modeling will complete our case studies.
We have now produced improvements in the tools used for in situ fluid identification. These methods now should be tested by industry in actual exploration. To promote this transfer, we are arranging our third DHI mini-symposium. The response from industry representatives has been enthusiastic, and several people have already volunteered to present and participate this April.
Project Start: September 1, 2002
Project End: April, 30, 2006
Anticipated DOE Contribution: $750,000
Performer Contributions: $250,000.00 (33% of total)
NETL - Chandra Nautiyal (email@example.com or 918-699-2021)
Colorado School of Mines - Michael Batzle (firstname.lastname@example.org or 303-384-2067)
Quarterly Report October - December, 2005 [PDF-1.23MB]
Quarterly Report July - September, 2005 [PDF-4.42MB]
As part of our technology transfer effort, we have submitted and presented numerous abstracts at the Society of Exploration Geophysicists Annual Meeting in November, 2005 in Houston. These include:
- Influence of internal reservoir structure on composite reflection coefficients
- Robust frequency dependent AVO workflow: Deep water GOM example
- Seismic models of turbidite reservoirs
- Use of outcrop analogs to predict lithology influence on the seismic signature
- Diagnosis of “fizz-gas” and gas reservoirs in deep-water environment
- Inversion of Sw and porosity from seismic AVO
- Velocities of deep water reservoir sands
- Tuning effect on fluid properties estimated from AVO inversion.
Han, De-Hua, and Batzle, Michael, Diagnosis of "fizz-gas" and gas reservoirs in deepwater environment, expanded abstract, Society of Exploration Geophysicists annual meeting, Houston, TX, November 6-11, 2005.
Sensitivity of 15 different hydrocarbon indicators in deep-water fizz and gas reservoirs.
Inverted water saturation and porosity for two patches. In Patch A, the inversion clearly defines the hydrocarbon zone (low Sw). In Patch B, an uneconomic "fizz" gas zone, the technique correctly indicates low hydrocarbon saturation.
Sheet sand expression in outcrop (a) with wireline (b) and seismic response (c). Note scale of outcrop is almost ¼ that of the seismic. Outlines indicate sheets on seismic and outcrop, highlighted areas indicate sheets in logs.
A high attenuation ring is observed around King Kong amplitude anomaly. (a) Near offset amplitude on top sand horizon; (b) Mean frequency below reservoir. The location is shifted down-dip direction: about 120 meters to the leftwards and 50 meters downwards.