Deepwater pore & fracture presure and temperature regimes ; Best practise.
The following guidelines were generated almost 20years ago by a joint industry group seeking to drill wells in a new deepwater environment for the first time.
So as things have moved from there, I am simply seeking any further lessons to be learned or best practices that can be employed in this key part of a well planning management process.
Pressure regimes, fracture gradients and temperature profiles.
Formation pressure prediction in deepwater is identical to pressure prediction in shallower water and onshore areas
Pore and structure pressure theory rules of thumb
1. First well estimate is generally be made on seismic interpretations
2. As wells are drilled, the seismic estimates are refined with actual well data e.g. resistivity and sonic plots, RFT pressures, well kicks, logging 'MDT' results, and drilling parameters
3. For seismic derived pore pressure, the matrix stress technique in conjunction with the interval velocity data from properly analysed velocity gathers has been successfully used worldwide
4. Stacking velocities are less successful in estimating formation pressures.
5. There must be at least 1500m of normally pressured clastics to establish a normal trend, reasonable predictions have been made with a lesser section.
6. Seismic techniques are less successful where abnormal pressures start near the top of the depositional sequence.
1. First well estimate is generally be made on seismic interpretations
2. As wells are drilled, the seismic estimates are refined with actual well data e.g. resistivity and sonic plots, RFT pressures, well kicks, logging 'MDT' results, and drilling parameters
3. For seismic derived pore pressure, the matrix stress technique in conjunction with the interval velocity data from properly analysed velocity gathers has been successfully used worldwide
4. Stacking velocities are less successful in estimating formation pressures.
5. There must be at least 1500m of normally pressured clastics to establish a normal trend, reasonable predictions have been made with a lesser section.
6. Seismic techniques are less successful where abnormal pressures start near the top of the depositional sequence.
Structure Gradient
7. For fracture gradients, reasonable estimates can be made from seismic data.
8. Leak-off tests of offset wells and actual formation pressures are needed to refine the estimates, However the principles in Hubert and Wills’ classic equation on fracture gradients as modified by Eaton, Pennebaker, and Christian have resulted in reasonable estimates of fracture pressure:
9. Fracture gradient = (Overburden – Pore Pressure) x Stress Ratio + Pore Pressure
10.In deepwater, overburden pressure can be estimated reasonably well by extending a seawater pressure gradient to the mudline depth in the area of interest and drawing a line from that point to the depth of interest which is parallel to existing overburden pressure curves available from the shallower water in similar basins, such as the Northern North Sea. This method assumes formation densities are the same. The actual density should be used after the first wells are drilled.
11.Stress ratio can be estimated from existing correlations as it is primarily a function of the overburden stress. Using the pore pressure estimated via geophysical methods, fracture pressure can be calculated using the overburden pressure and stress ratio already estimated. Such techniques should be considered when data is extrapolated from shallow water areas.
12.Compared with wells in shallower water, there is less difference in deepwater between the formation pressure and fracture gradient.
13.The water gradient adds less to the overburden than to the formation pressure.
14.As a result, additional casing strings may be required for higher formation pressures. E.g. in deepwater Gulf of Mexico, formation pressure increases at the rate of 1 ppg per 1000 feet, which requires 6-7 casing strings for a 10,000 foot well.
7. For fracture gradients, reasonable estimates can be made from seismic data.
8. Leak-off tests of offset wells and actual formation pressures are needed to refine the estimates, However the principles in Hubert and Wills’ classic equation on fracture gradients as modified by Eaton, Pennebaker, and Christian have resulted in reasonable estimates of fracture pressure:
9. Fracture gradient = (Overburden – Pore Pressure) x Stress Ratio + Pore Pressure
10.In deepwater, overburden pressure can be estimated reasonably well by extending a seawater pressure gradient to the mudline depth in the area of interest and drawing a line from that point to the depth of interest which is parallel to existing overburden pressure curves available from the shallower water in similar basins, such as the Northern North Sea. This method assumes formation densities are the same. The actual density should be used after the first wells are drilled.
11.Stress ratio can be estimated from existing correlations as it is primarily a function of the overburden stress. Using the pore pressure estimated via geophysical methods, fracture pressure can be calculated using the overburden pressure and stress ratio already estimated. Such techniques should be considered when data is extrapolated from shallow water areas.
12.Compared with wells in shallower water, there is less difference in deepwater between the formation pressure and fracture gradient.
13.The water gradient adds less to the overburden than to the formation pressure.
14.As a result, additional casing strings may be required for higher formation pressures. E.g. in deepwater Gulf of Mexico, formation pressure increases at the rate of 1 ppg per 1000 feet, which requires 6-7 casing strings for a 10,000 foot well.
Pore Pressure and Fracture Gradient
Velocity data from seismic shot points in the Deepwater Basin would be interpreted until pore and fracture pressure trend lines were established. From this, two or three prognosed trend lines e.g. A,B and C would be established and plotted on a pressure depth graph. If the seismic data was very similar to the seismic data in another similar area. The trend line (A, B or C) that best fits the similar data would be selected. The other trend lines derived would not be discounted and would also be designed for e.g. for lower and higher anticipated formation and fracture pressures.
Velocity data from seismic shot points in the Deepwater Basin would be interpreted until pore and fracture pressure trend lines were established. From this, two or three prognosed trend lines e.g. A,B and C would be established and plotted on a pressure depth graph. If the seismic data was very similar to the seismic data in another similar area. The trend line (A, B or C) that best fits the similar data would be selected. The other trend lines derived would not be discounted and would also be designed for e.g. for lower and higher anticipated formation and fracture pressures.
Temperature Estimates, and Pore Pressure While Drilling
Temperature gradients can also be estimated from seismic velocity data. Once compaction trends have been estimated, the temperature can be estimated from the interval velocity trends. Temperature profiles change as the pressure transition zone climbs with increasing distance from the depo-center. Below the top of the overpressures, temperature gradient increases because of the increased fluid content of the under compacted sediments.
Temperature gradients can also be estimated from seismic velocity data. Once compaction trends have been estimated, the temperature can be estimated from the interval velocity trends. Temperature profiles change as the pressure transition zone climbs with increasing distance from the depo-center. Below the top of the overpressures, temperature gradient increases because of the increased fluid content of the under compacted sediments.
During the drilling operation, the various mud log and MWD parameters will then be used to determine the proper weights for deepwater wells. Just as no one parameter works best in shallower water wells, all parameters should be monitored for the first wells. In the deepwater Gulf of Mexico, increasing gas, MWD resistivity, and d exponent, cuttings abundance, drag, torque, short trip behaviour, and wire line logs are all valuable indicators of formation pressure. Temperature is also a good indicator although experience has shown that the long drilling riser often results in a constant flow line temperature.
Rules of thumb.
1) Based on seismic data, formation pressures can be estimated to be very similar to the formation pressures found in similar deepwater or depositional regions
2) It is possible that formation pressures can and will vary, depending on the geological distance from the depocenter.
3) Fracture gradients can be estimated from seismic data,
4) Temperature data can be estimated from seismic data.
5) During drilling, the data from mudlogs and MWD has been successfully used to determine formation pressures for deepwater wells.
1) Based on seismic data, formation pressures can be estimated to be very similar to the formation pressures found in similar deepwater or depositional regions
2) It is possible that formation pressures can and will vary, depending on the geological distance from the depocenter.
3) Fracture gradients can be estimated from seismic data,
4) Temperature data can be estimated from seismic data.
5) During drilling, the data from mudlogs and MWD has been successfully used to determine formation pressures for deepwater wells.
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Posted by
Peter Aird
Drilling Specialist/Well Engineer/Training Consultant
Discussions: 113
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