Using an expensive drilling rig for plug and abandonment (P&A) is not necessary as the same scope-of-work can be delivered using only commercially available wireline and a pump to compact joints of tubing next to another joints of tubing within the production casing to create an unobstructed space for commercially available thru-tubing cement bond logging and cement plug placement. Why take the risk and cost associated with drilling rig P&A.
"Conventional" Rigless Plug and Abandonment (P&A) has existed for many years but it does not deliver the same scope of work and has an increased risk of leakages. Drilling rigs pull the tubing from a well to remove tubing interference that prevents commercial cement bond logging and creates frictions that can prevent sealant placement. Also, "conventional" rigless P&A leaves control lines and cables that can cause leak paths. Compacting tubing removes control cables and tubing to provide the same scope of work as a drilling rig using commercially available rigless P&A equipment.
The social cost of offshore well plug and abandonment (P&A) is extreme and could escalate by 150% to 354%. As reported by the Financial Times in 2017, “UK taxpayers are facing a £24 billion bill for decommissioning that threatens to wipe out the remaining value of UK North Sea oil and gas.” About 47% of decommissioning costs are well plug and abandonment, so over £11 billion of UK P&A is attributable to well P&A.
Well P&A is, literally, putting cement into a hole-in-the-ground, so why is it so expensive?
The majority of that £11 billion cost is not for cement plugging of the wells but, instead, relates to the systematic selection of the most expensive, instead of the least expensive, offshore logistics. This fact is easily demonstrated by comparing relatively inexpensive “onshore P&A” to very expensive “offshore P&A,” for similar well architectures.
Many industry proven offshore logistical alternatives exist; however, industry systematically selects the most expensive offshore logistical means for well P&A.
Proponents of offshore drilling rigs, which account for 40% to 70% of construction and P&A costs, cite cement bond measurements and keeping risks as-low-as-reasonably-practical (ALARP); however, measuring the cement bond is regularly avoided during drilling rig P&A and quantitative risk assessment shows that lower cost well logistics, using fewer people protected by pressure containment systems, are safer.
To explain this conundrum to those financially authorising drilling rig P&A requires ordinary speech to avoid the confusing technical jargon of practitioners. With those terms of reference in mind, Oilfield Innovations Limited, a Scottish registered micro-company, seeks funding to qualify a safer and lower cost universal rigless P&A method that uses lower cost industry proven tooling and offshore production intervention logistics, combinable with the logistics of other decommissioning activities, to reduce P&A cost by 32% to 60% and put cement into a hole-in-the-ground according to present regulatory requirements and industry best practice so as to keep risks and legal liabilities as-low-as-reasonably-practicable.
Oilfield Innovations have patented a new universal rigless P&A method of in-situ cement verification and plugging shown above, which are are similar or equivalent to other common downhole operations but costs 30% to 60% less than an offshore drilling rig P&A.
Step #1 depicts vertically splitting in-situ production tubing to remove the strength of its circular shape, wherein the step requires qualification of tooling.
Oilfield Innovations have a slickline tool design that uses proven cutting wheels that are extended and hoisted up and down to vertically cut the tubing.
Step #2 illustrates the “common task” of severing the tubing above the split and circulating a cleaning fluid into the annulus space between the tubing and casing.
Severance releases tubing tension and it will slump within the bore. The distance depends upon the tension and length of tubing.
Steps #1 and #2 included routine severing of the tubing above the vertical split and circulating of a cleaning fluid into the annulus space between the tubing and casing.
Step #3 shows the common task of placing a mechanical bridge plug for the subsequent packer (piston) to push against. Afterwards, the tubing is severed above the mechanical plug to create a tubing spear that can be pushed alongside the split tubing.
Step #4 depicts the routine process of inflating a packer in the casing and hydraulically pumping fluid into the well to push the packer (piston) downward to force the tubing spear alongside the split tubing, wherein the step of using proven inflatables packers requires qualification.
When tubing slump is insufficient, the packer can be inflated inside the tubing with viscous fluids placed above it to to prevent leakages as the inflatable expands from inside the tubing to the casing diameter.
Steps #1 to #4 included routine severing of the tubing above the vertical split and circulating of a cleaning fluid into the annulus space between the tubing and casing followed by hydraulically pumping fluid against a packer to push the tubing spear alongside the split tubing.
Step #5 illustrates common through tubing logging measurements of the in-situ cement within the Rig-Equivalent-Window space created by the piston so as to measure cement bonding. Alternatively, research shows that shale or salt can also comprise an annulus barrier that can be confirmed by logging measurements.
Step #6 shows routine placement of a P&A sealant (cement) plug that is supported by the compacted tubing, whereby the packer element’s casing seal prevents gas migration during sealant curing (hardening) to provide a universally compliant P&A plug.
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