Subsea P&A

Martial Burguieres, Wild Well Control, USA, discusses some of the latest developments in subsea P&A systems.

Seeking to provide the oil and gas industry with a subsea alternative to traditional offshore plug and abandonment (P&A) services, Wild Well Control has worked to develop cost-reducing solutions. But as it has been said, one cannot cross the sea merely by standing and staring at the water.

The company’s maiden deployment for its brand new 7 ? in., 10 000 psi rated riserless intervention system, the 7Series, was indeed subsea, but not by much.

Eight wells in Angola were to be brought to full P&A status from a vessel. However, the owner required that all procedures and processes stay compliant with BSEE standards normally followed in the Gulf of Mexico. This meant the wells would have to be temporarily abandoned (TA), have their tubing severed, and have several thousand feet of tubing removed from the well.

Then, Wild Well engineers had to figure out how to place the required 200 ft cement barriers into the outer annuli. BTI Services, a sister company, offered a hot tapping solution with equipment that had been marinised for a previous job in which it had performed well.

The idea was to perforate the annulus next to the production bore – referred to herein as the B annulus – just above the top of the cement. After using the 7Series circulating lines and pressure control valves to deal with annular casing pressure, divers used the hot tapping equipment to penetrate into the B annulus from outside the wellhead.

This completed the circulation path that would enable longer than required cement plugs to be pumped into the annulus. After waiting on the cement to harden, the line connected to the hot tap was used to perform the mandated topside pressure test of the cement.

Everything went as planned, so the crew and engineers set their minds to accomplishing the goal of using the 7Series in much deeper water while maintaining the ability to perforate outer annuli and circulate cement without hot tapping. In other words, the aim was to be able to keep all operations under constant pressure control and eliminate the need for diver intervention. This is where the DeepRange system comes into play.

A new set of tools

The DeepRange system is best summarised as a very short completion. As in the Angola wells, the system is run after TA and the tubing hanger and several thousand feet of tubing have been removed.

Figure 1. Test crews installed the DeepRange system into the 9 ? in. casing assembly at a Wild Well live-firing facility to mimic an actual well scenario. The larger C annulus guns were fired and the whole assembly was pressure tested to ensure the isolation bushing and packer were unharmed. The test was performed multiple times without failure.

The isolation bushing acts as a type of tubing hanger under which a selected amount of tubing is hung – based on well geometry (Figure 1). Pre-installed on the tubing are two tubing-conveyed perforating guns. The final piece is a telescoping joint that gives a degree of up-and-down stroke when the entire upper assembly is latched into a pre-installed packer.

Wild Well has previously performed TA on three deepwater wells in the Gulf of Mexico and has significant insight into this operation and the amount of time it takes to accomplish the task of completely isolating the well. Once this has been accomplished, the upper assembly of the DeepRange system is run in and latched into the aforementioned packer.

Figure 2. Prior to firing perforation guns in the test fixture, personnel installed a 13 ? in. clamshell sleeve to ensure the B annulus guns did not compromise the outer casing string.

The two tubing-conveyed guns carry different charges. The B annulus gun carries charges specifically timed and tested to perforate the first string of casing without damaging the next string of casing (Figure 2). The C annulus guns are similarly designed to perforate through the first and second stings of casing without damaging the third.

It should be noted that significant work has been carried out with Owen Oil Tools to ensure that both annulus guns function exactly as planned. Initial tests were completed for typical 9 ? in. and 13 ? in. casings in various sizes. However, the guns can be calibrated for any commonly used casing programmes.

The first step in using the DeepRange tools is to fire the B annulus tubing-conveyed guns and then run standard decentralised wireline perforating guns below the packer. This creates a lower and upper flow path separated by the packer.

Circulation is then established down the tubing and through the packer. The flow enters the B annulus through the lower perforations and flows up the annulus, through the upper perforations, and back into the production bore. The flow then arrives at the wellhead and is diverted by the isolation bushing into the return lines back to surface.

After an appropriate amount of fluid has been circulated through the B annulus and appropriate diagnostics have been performed, the plugging materials are blended and prepared to pump.

Teamwork

Not satisfied with the shortcomings of cement as a permanent barrier, Wild Well and CSI Technologies developed a ‘binary’ plugging system that incorporates an initial volume of proprietary resin chased by a larger volume of specially formulated cement. The entire volume of plugging materials is positively displaced through the lower perforations into the B annulus (Figure 3).

Figure 3. Pumped through a 9 ? x 13 ? in. full-scale test fixture perforated with actual guns, full-scale flow tests of the plug materials verified the pumping pressures and mechanical properties of the materials.

Typical cement plugs are often contaminated at the top and bottom of the plug. This is mostly due to the turbulent flow conditions and wellbore fluids ahead of and behind the cement as it is displaced. In addition, any small flow of gas or fluid will likely cause channelling as the cement cures.

In the binary plug, the resin cap remains in a low-viscosity state after the cement has cured. During mandatory pressure testing of the cement plug, the resin is forcibly displaced into any voids and irregularities in the top of the cement plug.

The volume of resin displaced into the cement will be dictated by the competency of the cement plug. Good cement will take very little resin while a poor cement top will take more of the resin cap until the inclusions and other issues are sealed.

While the resin cap in the binary plug increases the likelihood of a successful test, it also increases the overall long-term effectiveness of the cement plug. Resin bonds to steel, has much greater tensional strength than cement, and is highly resistant to channelling.

However, its greatest strength is the fact that even when ‘contaminated’ with water during turbulent flow, the resin will settle and ‘recombine’ itself to its original characteristics when it becomes static. This is unlike cement that remains contaminated, permanently reducing a 16.5 ppg cement’s weight and strength characteristics.

Once the B annulus has been fully plugged and tested, the C annulus operations begin. The C annulus is very similar to the B annulus though the guns are calibrated to penetrate two casing strings.

Upon pumping the C annulus plugs, the cement is left in a balanced condition in which the cement levels equalise between the production bore and the C annulus. This leaves the well with a solid plug of cement and resin across all of the casing annuli.

The DeepRange tool is then unlatched from the packer and pulled out of the well. Though retrievable in design, the packer is plugged and left in the production casing as an additional barrier. A cast-iron bridge plug is placed in the production casing above the highest perforations, and cement is bailed on top to form the final surface plug.

Costs and regulations

While regulations have mandated cutting and pulling the wellhead in shallower water depths, waivers have been granted to allow them to be left in place. Wild Well strongly encourages leaving wellheads intact not only because of the costs of wellhead cutting and associated operational issues, but also to allow well re-entry in the future. A severed subsea wellhead cannot be re-entered.

The entire DeepRange operation takes place from a multi-service vessel that contains approximately 1000 m2 of back deck, a moonpool, working-class ROVs, and a heave-compensated knuckle boom crane with 60 t capacity at depth.

While this is a high-specification vessel, many of these ships are available for hire in all the major deepwater basins. The average cost for these vessels is significantly less than the cost for mobile offshore drilling units.

While on the topic of costs, a general cost figure of US$12 million per well can eliminate these P&A liabilities from the operator’s balance sheets. While the total cost can vary slightly given the total amount of work and configuration of the well and production system, it still represents a significant reduction in P&A cost.

Though it may be difficult to pin down an industry average cost for subsea well P&A, wells have been abandoned in the last year for as little as US$24 million and as much as US$100 million, depending largely on the regulatory requirements and the level of abandonment or deconstruction desired by the operator.

Wild Well remains one of the only companies to combine senior well engineers, subsea engineers, regulatory experts, cementation engineers, and experienced wellsite personnel all in-house and all working towards the goal of reducing the costs of subsea P&A. In conjunction with the tried and true 7Series, DeepRange technology represents a significant opportunity for deepwater operators.

Properly performed subsea P&A operations deliver a safe, reliable solution to well decommissioning. New technology such as the DeepRange system provides offshore operators with a viable alternative to conventional P&A while ensuring minimal impact on the environment. There are two reasons to re-enter a decommissioned well: to repair a poorly performed P&A or to use new technology to access untapped reservoirs. Operators should make sure that they only have one reason to go back in.

Step by step P&A

1. Step 1: Well has been TA’d, tubing has been cut and pulled, and a cast-iron bridge plug and packer have been installed.

1. Step 2: The upper assembly – consisting of an isolation bushing, tubing-conveyed perforating guns, and a telescoping joint – are landed and latched into the packer.

1. Step 3: The upper tubing is conveyed and the lower standard perforating guns are fired into the B annulus.

1. Step 4: Circulation is established through the tubing, into the lower perforations, up the B annulus, out through the upper perforations, and back up the production annulus. The isolation bushing diverts flow to the return lines.

1. Step 5: The binary plug is circulated into the B annulus. After waiting on the cement to harden, a mandatory pressure test is performed.

1. Step 6: The upper tubing is conveyed and the lower standard perforating guns are fired into the C annulus.

1. Step 7: Circulation is established through the C annulus as with the B annulus before.

1. Step 8: The binary plug is circulated into the C annulus. The plug is left in a ‘balanced’ condition with the production annulus. After waiting on the cement, testing is performed.

1. Step 9: The upper assembly is unlatched from the packer and pulled from the well. A cast-iron bridge plug is set above the highest perforations and cement is bailed as per regulations. Wild Well advises customers to leave the wellhead intact.

This article was adapted from the May issue of Oilfield Technology by David Bizley

Read the article online at: https://www.oilfieldtechnology.com/special-reports/07052015/subsea-panda/