Factory drilling

Drilling on Statoil’s Mariner will be a mega project – but Statoil is looking to lighten the load in ways that could only be done on such a large project. Elaine Maslin found out more.

The Mariner field concept artists’ illustration.Images from Statoil.

When drilling starts on the Mariner heavy oil field, it will become one of the biggest offshore factories constructed in the North Sea.

In the first production phase, at least 130 well targets are to be drilled over 11 years, at a rate of about 10-12 per year in the initial years, from a platform rig and jackup alongside, supported by an intervention and completion unit.

It’s going to be quite some task, costing more than US$7 billion in total. But, because of the scale of the task, operator Statoil has been able to make some upfront decisions on its approach to drilling and completions on the field, from which it stands to reap benefits during the field’s 30+ year long life.

The field

Mariner, a heavy oil field in relatively shallow Maureen and Heimdal sands, was discovered by Union Oil on the East Shetland Platform in Block 9/11, 150km east of the Shetland Islands, in 1981.

Some five seismic surveys have been shot over the license since it was first awarded in 1980, and 18 wells have been drilled by four different operators (OE: March 2015), proving up an estimated 1 billion boe in place, and 250 MMbbl recoverable oil, ranging from 67-508 centipoise viscosity.

As with a number of other heavy oilfields in the area, and despite a string of development studies and concepts, the field was left undeveloped because of the difficulties around extracting heavy oil. These difficulties are being overcome.

Statoil’s plan is a production, drilling and living quarters platform, currently being built in Korea, on a steel jacket, being completed in Spain, with a floating storage unit, supported by a jackup, with startup planned for 2017 and a 30+ year field life.

The key challenges on Mariner are the viscosity of the oil, which requires intensive drilling and therefore complex well placing, as well as artificial lift technologies, and shallow reservoirs, which make the intensive drilling all the more challenging.

In total, Statoil has identified some 147 reservoir targets, to be reached using lateral wells, and some multilaterals, from a total 98 wells from the surface. With 50 slots on the Mariner platform, that means many wells will have to be side-tracked.

“Statoil hasn’t done anything like this, with such a large drilling and well scope, and it is probably unique in the whole world,” says Rolf Arne Thom, Manager Drilling and Wells, Mariner & Bressay, for Statoil. “We are going to be drilling for 11 years full time and, for a primary drilling program, that is very large.”

The Cat J jackup design to be used on Mariner.

Drill, drill, drill

In an onshore-heavy oil environment, wells would be drilled every 20-30m with steam injection wells, to help heat and move the oil, at every other well, Thom says.

This is less easy to replicate offshore, so alternative methods are required. In the case of Mariner, the method will be intensive simultaneous operations, or SIMOPS.

Statoil will have two rigs drilling full time at Mariner, on the platform and from a jackup for at least the first 4-5 years, from 2017, with Statoil considering starting pre-drilling late 2016, as well as an intervention and completion unit (ICU), to support the rig operations. The platform rig on the Mariner platform will run throughout the 11-year drilling period. Odfjell is Statoil’s contractor for the platform drilling. The jackup, operated by Noble Drilling and currently being built to Statoil’s Cat J design in Singapore, is on contract for four years, with extension options.

Because of the height of the Mariner platform, the Cat J jackup had to be designed specifically to be able to reach the Mariner well slots. This meant its deck is some 80m from the sea surface, which had knock-on effects on the evacuation facilities on the rig – lifeboats wouldn’t just be able to free fall from that height, so they are on davits that can be lowered. Much of the design considering went into the legs, however, so that they could be tall enough and strong enough to cope with a 10,000 year wave.

An ICU, offshore

The ICU was a novel decision and something Statoil hasn’t done before and hasn’t seen others do before on this scale. Usually, a wireline, snubbing or coiled tubing unit would be brought in to help perform intervention work, but not from day one, Thom says. Because of the huge scope of work on Mariner, Statoil was able to take a decision to have capability from day one, lightening the completions load as a bonus.

It will sit in the 23m-high so-called cathedral deck, between the BOPs and the Xmas trees. It will be used to install upper completions and electric submersible pumps (ESPs) as well as for interventions and changing out ESPs.

“We need to be producing wells all the time and these heavy oil wells can get water wet very quickly. Traditionally, on older fields, your rig has to be used to maintain older wells, which means you cannot use it for drilling,” Thom says. “On this platform, we will be able to keep the drilling rigs doing what they are supposed to do and the ICU will take care of the completions and interventions.”

The ESPs, which are known to fail, across industry, on average every 2-3 years, are likely to require a lot of work. But, Statoil has created another novel solution to make the ICU’s work replacing ESPs easier, too. It has designed the Mariner wells so that the ESPs will be run on a separate 2 1/8in tubing within the 7 5/8in production tubing, which means when one fails, only that tubing string has to be pulled out by the ICU. “Traditionally, it is an integrated part of the tubing so you have to pull out the whole completion to change the ESP,” Thom says.

Otherwise, the well design will largely be traditional, Thom says. Most will be long horizontals, up to 1700m-long, and possibly longer in the future, in order to bring enough flow into the well. But, Statoil will use sand screens and gravel packs in some of the first wells. They will also deploy autonomous inflow control devices (AICD), to control water ingress into the well; as water cut increases, the AICD will gradually close off the flow from that section.

To give the viscous oil a further helping hand at reaching the topside process equipment, Statoil is also using diluent, which will be pumped down the annulus between the production tubing and the 2 1/8in tubing, joining the production flow as it enters the ESP, to thin the oil, making it easier to handle topside.

One of the challenges with having the two rigs and the ICU operating simultaneously, will be being able to move equipment between well slots without disturbing the different activities. To do this, Statoil is looking at a building a 3D “plug and play” model, into which it can plug planned moves, so that it will be able to suggest the best option for any particular move or operation. Also, because of the intensive SIMOPS on board Mariner, the platform has been designed so that the decks are closed and fluid tight, to avoid any dropped objects or environmental leakage.

Another challenge will be placing the wells. “It is going to be challenging to place well number 130,” Thom says, especially when the Mariner reservoirs are at 1200m and 1500m. “You do not have much room to build the angle and hit the target,” he says. “It is a quite unconsolidated formation. The interaction between the wells is not so much a risk, it is going to be to achieve the angle you need in this loose sand and that’s not easy. But there is quite a lot of experience in the area, such as on the Captain and Alba fields, which have similar formations types.”

A $65/bbl business case

Statoil made its decision to move forward with Mariner in a $100/bbl environment, so the firm has looked for ways to make the project more viable at today’s prices. One has been through assessing the seismic. From its latest seismic data from the field, Statoil has decided that it would be able to reduce the amount of drilling required to reach the targets it wants to, saving the limited cash there is in the current environment. The scope had been 140, but that has so far been reduced to 130, with prolonging the horizontal wells and geosteering, to target the sands, helping to more efficiently drain reservoir targets.

Statoil also selected Schlumberger as the integrated drilling services contract provider on Mariner. Thom says this has reduced the number of contractor interfaces from more than 30 to just one.

“For us now, the focus is to standardize and not to change our plans,” Thom says. “We have frozen the well design, the casing program, completion design etc., and they will be kept until we get good at them. We want to learn, and we will have a lot of monitoring, looking at weight on bit and the stability of the drill string and combine that with mud logging, and industrialize.”

The interface between onshore and offshore will also be strong, with teams monitoring drilling, well, ESP and production performance onshore, as well as offshore. When it moves into its new purpose built offices near Aberdeen next year, the firm will have a control room which connects directly offshore.

It’s a mighty undertaking, but one which is only possible thanks to technology developments over the last 20 years, Thom says. “Long horizontal multilateral wells, ESP pump reliability – and we are banking on it getting better as we go – using diluent, combined with the AICDs and the ICU, as well as subsurface work, has meant we were able to build a business for Mariner. For me, the most exciting part is the SIMOPs and the ICU, which is new.”

Statoil is the operator of the field with 65.11% equity. Other partners include JX Nippon Exploration and Production (U.K.) Limited (28.89%) and Dyas Mariner Ltd. (6%).