High-Pressure Well Design
- Harrie Krus (Shell U.K. E and P) | Jean-Marie Prieur (Shell U.K. E and P)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling Engineering
- Publication Date
- December 1991
- Document Type
- Journal Paper
- 240 - 244
- 1991. Society of Petroleum Engineers
- 1.4 Drillstring Design, 1.14.1 Casing Design, 1.7.5 Well Control, 1.11 Drilling Fluids and Materials, 1.10 Drilling Equipment, 5.6.4 Drillstem/Well Testing, 1.6.1 Drilling Operation Management, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.1.9 Heavy Oil Upgrading, 4.2.3 Materials and Corrosion, 1.6 Drilling Operations, 1.3.2 Subsea Wellheads
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Shell U.K. E and P (Shell Expro), operator in the U.K. North Sea on behalf of Shell and Esso, plans to drill 20 high-pressure wells during the next 2 years. The well design is based on new standards developed after the U.K. Dept. of Energy restriction on high-pressure drilling in the autumn of 1988. Studies were carried out to optimize casing design and drilling performance on these wells. Several casing schemes, including a slim-hole option, were analyzed. The material specifications for casing and drillpipe were reviewed to ensure that they met the loads imposed during drilling, well-control, and well-testing operations. The requirement for sour-service material was weighted against possible H2S adsorption by the mud film. As a result, a new drillstring and two high-pressure casing schemes have been specified. The high-pressure casing scheme used depends on the maximum expected surface pressure.
Shell Expro adopted a worst well-design scenario after the U.K. Dept. of Energy moratorium on high-pressure drilling of exploration and appraisal wells. The worst-case scenario is defined as the complete wellbore evacuated to reservoir gas with a maximum expected wellhead pressure equal to the maximum expected bottomhole pressure (BHP) minus the hydrostatic head of the gas column. The design's main objective is to allow the well to be closed in safely under all circumstances. The semisubmersibles were upgraded and the operating procedures were revised accordingly. The 15,000-psi [103.4-MPa] - working-pressure-rated sour-service sub-sea wellhead and blowout prevention equipment are designed and tested to operate at a continuous temperature of 250 degrees F [121 degrees C] and to sustain a maximum temperature of 350 degrees F [176 degrees C] for 1 hour. The last criterion is currently under discussion because some experts believe that it may be too conservative as a design parameter if a philosophy of always being able to shut in the well is maintained. Sour-service design of the intermediate casing (the casing string set above the high-pressure reservoir and exposed when the high-pressure reservoir is drilled) is required if H2S is present in high-pressure reservoirs. In the past, the intermediate high-pressure casing was not always designed for sour service because the pressures were assumed to be lower and the environment was controlled to stay within NACE MR-01-75-88. The drilling fluid contains an excess of H2S-scavenging chemicals, which neutralize any H2S present when drilling. The short exposure of the intermediate casing to a small gas kick containing H2S is not sufficient to lead to a casing integrity failure. The well-control problem at the semisubmersible rig, the Ocean Odyssey, showed, however, that long-term exposure of the intermediate casing to a large volume of high-pressure gas can occur. If the high-pressure gas contains H2S at low concentrations, then the NACE limit will be exceeded-hence the requirement for sour-service design.
Reservoir Design Parameters
A clear model of the expected formation pressures is required to carry out a detailed well design. The maximum expected BHP is important because the worst-case-scenario wellhead pressure can be calculated from this pressure if the average gas gradient is known. The maximum BHP is equal to the formation pore pressure at the bottom of the hole. Other important reservoir design parameters include the gas gradient, the presence and quantity of H2S expected, and the temperature profile from surface to total well depth. Gas compositions of hydrocarbon samples from well tests in the central North Sea were analyzed, and sufficient data were available on the gas composition to accept a reservoir gas with a methane content of 85 mol% as the worst case. The average gas gradient for the design of those high-pressure exploration wells ranged from 0.135 to 0.145 psi/ft [3.05 to 3.28 kPa/m], depending on the reservoir pressure and depth. All the high-pressure exploration and appraisal wells are designed for H2S. The H2S prediction in the planned high-pressure exploration wells on the drilling sequence was reviewed.
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