Jeremy Beckman, Editor, Europe
Confidence is growing in managing hostile high-pressure, high-temperature reservoirs. In the North Sea, rising gas prices are driving development of even the most problematic fields. Doubts remain, however, about the long-term integrity of well architecture.
In response, the UK Health & Safety Executive commissioned a study by consultants Highoose into HP/HT engineering challenges and security concerns, based mainly on experience in the UK North Sea from 1987 to 2003. The recently published findings suggest that the drilling industry in this sector is generally on the right track, but more unknowns are also emerging as new techniques are put into practice.
HSE describes the UK’s HP/HT prospective development area as an “overprint” on complex geology, rather than a separate play, which in 2004 encompassed an area estimated at 38,000 sq km. Outside the large producing gas-condensate fields in the Central North Sea, there have also been HP/HT discoveries (gas and oil) in the Outer Moray Firth, Viking Grabens, the Magnus Embayment, and West of Shetland.
Based on UK Department of Trade and Industry definitions, the authors identified 227 HP/HT wells drilled across the UK shelf between 1987 and 2003, with a peak of 30 well spuds in 1997. A total of 130 safety incidents were reported from wells in this category up to the end of 2003.
Highoose confined its review to the following recurring scenarios (excluding incidents related to tophole drilling):
• Control of unplanned influxes or flows (i.e. kicks). These incidents are defined as “major” if the influx from the reservoir is greater than 20 bbl while drilling an 8 1⁄2-in, or smaller diameter hole. For other hole sizes, the volumes are adjusted according to the level of risk incurred.
During 1987-2003, 77 of these incidents were reported, although the last serious kick occurred in 2001. In 1997, kicks of varying levels were noted in just under 15% of wells drilled, compared with over 45% in 1987. This reduction was probably due to improved training and operating procedures; however, there was no further improvement in the period to end-2003.
Most of the reported unplanned influxes coincided with drilling fluid losses in other permeable zones in the open hole. In 25% of cases, leak-off strength of the intermediate casing string, or formation strength in deeper open hole, proved to be insufficient, leading to a kick and loss situation, or even abandonment of the open hole.
• Failure of blow-out preventers and ancillary equipment. In this instance, 11 incidents were reported, affecting the annular element, control, choke and kills lines, and the BOP seals. No trend emerged suggesting vulnerability of particular items, but nor was there any indication that BOP problems were being eliminated.
• Hydrogen sulfide detection. Fourteen incidents were recorded between 1987 and 1996 (reporting requirements changed thereafter). Generally low levels of H2S were noticed, initially during drill stem or production tests, or while recovering wireline samples. Higher concentrations were reported later on during pull-out with the corebarrel, but were comfortably dealt with by contingency measures included in the HP/HT well programs.
• Mechanical failure of safety-critical components (aside from the BOP stack). Twenty-five incidents were recorded on all types of wells (exploration, appraisal and development). Early failures were caused mainly by leaking seals and related assemblies or by wash-outs of surface equipment. There were also instances of a parted conductor and worn-through casing, and of leaks in packers, wellhead and flowline equipment in some of the early development wells.
Among the most recently reported incidents, pressure build-up in the annulus of a production well could not be stemmed, forcing temporary closure of all other wells and the entire platform until the affected well was killed with brine. Tubing to annulus communication was evident, but the root cause could not be identified. A similar problem occurred in another annulus during subsequent tests of the production casing, leading to a further shutdown.
As with another incident in 2003 involving a well perforation, which led to sudden loss of integrity of the production tubing conduit, failure of a critical component of a production tubular arose following submission to tensional axial and/or hoop stress conditions. But there were no indications in these or other earlier incidents that the loads applied had exceeded the equipment design specifications. The cause of the failure was attributed to environmentally-assisted cracking, which may have been initiated by material flaws.
In conclusion, HSE believes that the likelihood of well control problems is now affecting around one in six UKCS HP/HT wells - lower than previous percentages - although the problem may worsen in future when operators start drilling in depleted zones. There are no clear trends concerning BOP incidents with these types of wells, although the combination of a failure with a well control incident could have potentially catastrophic consequences.
As for incidents arising from tubular/hanger failures, the extreme production conditions of HP/HT wells will lead to increased use of less common, more exotic materials. This in turn may increase the probability of mechanical equipment failures, although there is no obvious correlation between the various metallurgical problems encountered to date.
Loading/expansion issues
Most HP/HT wells are in deep-lying formations where the extreme subsurface conditions necessitate use of heavy casing strings. HSE points out that this arrangement can create well loads higher than can be safely supported by the surface string from deck level to the sea bed. Part of the load must therefore be transferred to the marine conductor at a deeper level (normally landing collars installed just below the sea floor level).
For producing HP/HT wells, a further complication arises when the casing strings and production tubing heat up and expand at different rates while the well is flowing - above all in the surface section where the wellhead and production tubing are heated from the ambient temperature of 0-10°C to around 150°C. Above the seabed in particular, there is a strong radial temperature gradient, as the marine conductor will remain close to ambient seawater temperature at all times.
With all the strings being locked in - and depending on pre-stress applied during installation - strong axial forces may be imposed by the differing thermal expansion. These forces can be difficult to predict during the well commissioning phase, especially in the short surface section between the landing collar at seabed level and the wellhead.
One solution involves transferring only the weight of the two outer casing strings to the marine conductor at seabed level, freeing the production casing string most affected by thermal loading to expand over its full length from the wellhead downwards. But HSE believes there may be a risk of extreme thermal loading building up on the short upper section of the string, leading to mechanical or sealing failures. There is no evidence of this from incident reports to date, however.
A well’s support and foundation configuration also determines the well growth rate (rising of the wellhead when the well is heated up). Most operators in the Highoose survey found that actual well growth exceeded prediction, in some cases by 100%. This under-estimation was attributed by some to inaccurate assumptions over the security of the marine conductor as a seabed foundation column. In fact, thermal forces were causing the subsoil to shift and move upwards with the pipe from a much deeper than predicted level, especially where the subsoil had been disturbed by earlier drilling.
The solution involved using mud to prevent wash-out when drilling in the marine conductor, improving the conductor’s stability. But under-estimation of HP/HT well growth remains a danger, HSE suggests, with flowlines also at risk of rising more than allowed for in surface facilities design.
Intermediate casing
In some HP/HT areas of the North Sea, the gas-bearing chalk Hod formation, at a depth of around 14,000-ft, presents a further well engineering challenge. Cementations across the zone, as part of the intermediate/production casing string installation, have generally failed to achieve a full shut-off. As a result, says HSE, the B-annulus in the wells is permanently pressurized, although it may take up to two years after the start of production for these Hod pressures to emerge.
Another worry in HP/HT wells in production for three or more years is the risk of reservoir compaction, brought on by pressure depletion. This could lead, among other things, to collapse of the borehole; damage to the production liner above the production packer (thereby by-passing one of the well’s safety barriers); and build-up of solids in fluids, causing chokes and valves to cut out.
In the Gulf of Mexico, wells in one field facing these types of problems have been completed with liners uncemented in underreamed sections across the overlying layers. The wells’ lower completion has been strengthened structurally and hydraulically by a cemented liner tie-back. HSE claims this type of solution is increasingly under scrutiny for North Sea HP/HT fields.
The report also comments on the emergence of new technologies, and how these might impact future North Sea developments. These include:
• Managed pressure drilling, under consideration by at least two Norwegian sector operators. According to HSE, the technique appears to offer distinct advantages for HP/HT wells, as it would allow continuous active control of downhole pressures within the tight pressure window.
• Constant pressure drilling, possibly applicable to over-pressured sections of HP/HT wells
• Expandable tubulars, to install additional drilling liners in depleted zone sections with very high temperatures
• Horizontal or high angle borehole sections with interventionless completion packers
• Alloy 725, reportedly stronger and more resistant to sulfide-stress cracking than Alloy 718, although yet to be applied in North Sea HP/HT wells
• Deeper HP/HT wells, to subsurface targets beyond 20,000-ft. These will demand longer, heavier casing strings. According to HSE, one operator plans to counter this issue through use of a slim well design with drilling liners
• Deep water HP/HT wells west of the Shetlands, probably completed subsea. The complicating factors in deepwater drilling are overburden sediments which are often under-compacted and weak, further reducing the pore pressure-fracture strength window. Also, the contrast between the long riser column of heavy circulating fluid and the surrounding water column will tend to distort the well control options.
For more information, contact Donald Dobson, HSE:[email protected]
