A new liquid removal technique could make more subsea tiebacks viable
Tieback projects for marginal gas fields often face critical problems such as water and hydrocarbon condensation, which causes slugging. Larger diameter pipes are more prone to slugging, but reducing pipe bores increases friction and pushes pressures up. More problems arrive when maintenance demands temporarily reduce pressures. A tieback that works at 100% of design pressure slugs up when pressures are dropped for a turndown.
The usual solutions are to remove liquids at the wellhead, or to add compression, with its attendant power requirement, CO2 emissions and maintenance of components.
WorleyParsons group company INTECSEA, via the Group Programme Management Office (GPMO) Innovation Hub, has developed another approach, in a new technique christened “pseudo dry gas”.
The approach installs up to four piggable liquid removal units in line with the gas flow. INTECSEA is currently keeping the exact process used confidential, but the units appear to be passive, with no moving parts in the gas stream. All supporting equipment (single phase pumps, controls and power distribution) are field-proven and readily available equipment.
The first unit removes part of the liquids. As gas flows up the system changes in pressure and temperature cause additional liquids to condense, which are successively removed by later units. The residual liquid hydrocarbons are reabsorbed into the gas stream towards the surface. Liquid removal is not complete but is effective enough to create an effectively dry gas hydraulic system.
The result is less need to compromise on pipe sizes, and so larger bores and less frictional pressure. With less pressure comes savings on power as well – because pseudo dry gas operates at a lower overall pressure.
After removal the separation units pass liquids up a second pipe, which is 4-6 inches (100-150 mm) in diameter.
The new system has a natural redundancy. If one of the four units fails then the system will still work, albeit with reduced performance. Sour gas will cause problems for pseudo dry gas, as it does for other systems. Coping with sour gas would increase capex dramatically, so there is no expectation of its use with sour reserves.
As conventional deepwater long-distance gas tiebacks use two pipes anyway (to allow turndown operations), INTECSEA sees the pseudo dry gas solution as not leading to a dramatic capex increase. The material and work remain the same, but are simply distributed differently, though capex costs do rise by around 5-8%. However, it looks like this added investment can bring a production win. According to integrated modelling from the OGTC (which we have not seen), recoverable reserves in the Northern North Sea could rise by around 40 bcm using INTECSEA’s tech.
Another benefit is that pseudo dry gas allows plant to be turned down by 90% – 10-15 points more than is common today. While in standard subsea tiebacks turndown causes a substantial liquids hold-up to build up in days, with pseudo dry gas the smaller volumes of liquids being transported mean slower liquids build-up, and so quicker restarts. Finally, it may well turn out that reducing pressure on wells increases their expected lifespan.
With lower production and tieback costs on offer, pseudo dry gas might make stranded gas fields in the North of Shetland, East and West Africa, offshore Australia and New Zealand and parts of the Mediterranean commercial.
Returning to that OGTC study, results are reported to include a 26% improvement in recovery rates over conventional subsea tiebacks, driving an increase of NPV by 34% over the next best development option.
For subsea compression to achieve similar recovery rates multiple stations in different locations would be needed, with associated fuel consumption and CO2 emissions.
The first trial of the pseudo dry gas system is scheduled to take place in the first half of this year. INTECSEA is in the process of qualifying the liquid removal units, which is likely to be done as a joint project with the OGTC and to include a number of operators and contractors. The current next step in the project is building the piggable liquid removal unit for test on a flow loop.
INTECSEA is looking to identify a pilot field for a live test by 2022.