Rig briefs: Atwood orders new drillship, KCA Deutag wins new contracts

Atwood orders ultra-deepwater drillship for 2015 delivery

The newly ordered Atwood Archer will be identical in design to the Atwood Achiever (rendering pictured). DSME is scheduled to deliver the Atwood Achiever ultra-deepwater drillship by 31 December 2015.

An Atwood Oceanics subsidiary has entered into a turnkey construction contract with Daewoo Shipbuilding and Marine Engineering (DSME) to construct a fourth ultra-deepwater drillship to be named the Atwood Archer. Delivery is anticipated by 31 December 2015 at a total cost of $635 million. The rig will feature two blowout preventers and will be identical in design to the previously ordered Atwood Advantage, Atwood Achiever and Atwood Admiral. All four drillships are DP-3 with dual derricks and will be rated to operate in water depths up to 12,000 ft and drill wells to 40,000 ft.

Upon delivery, the Atwood Archer will become the company’s 17th mobile offshore drilling unit.

Further, the company has secured an option to construct a fifth ultra-deepwater drillship at a similar cost to the Atwood Archer and with an expected delivery in September 2016. This option must be exercised by 31 March 2014.

KCA Deutag secures work in Myanmar, Gabon

KCA Deutag has been awarded two offshore contracts for work in Southeast Asia and Gabon. The first is a two-year operating and maintenance drilling services contract for the Shwe Platform based in Myanmar with Daewoo International. The second contract, with Tullow Oil Gabon, is for the provision of KCA Deutag’s Ben Rinnes jackup. The contract scope is for two wells, and there is an option for an additional well. Work will commence in July, operating for 80 days.

“The West African market continues to be a major hub of activity for the oil and gas industry and one where we have an established presence. Establishing new relationships in countries such as Gabon demonstrates how vibrant this area continues to be,” Rune Lorentzen, president of offshore at KCA Deutag, said.

“This contract with Daewoo International Corporation is our second contract in Myanmar and strengthens our position in the region. With existing projects under way and a number of further opportunities identified, we are in a good position to continue to develop KCA Deutag in an emerging market which offers extensive oil and gas potential,” he continued.

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EIA report: North American growth helps boost global oil production to record levels

This animated map shows how world crude oil and lease condensate production, measured in millions of bbl/day, has changed since 1980 in key oil-producing regions. Growth in North American crude oil production and recovery in African and Asian markets contributed to a record global production of 75.6 million barrels bbl/day in 2012, according to an agency brief.  Source: US Energy Information AdministrationBy Katie Mazerov, contributing editor

The Middle East still ranked as the world’s No. 1 crude oil producer in 2012, but growth in North American crude oil production and recovery in African and Asian markets, specifically China, contributed to a record global production of 75.6 million bbl/day, according to a brief released on 17 June by the US Energy Information Administration (EIA). Eclipsing the Middle East, it was the strength of the North American, African and Asian markets that drove an overall 2% increase over 2011 levels in global crude oil production, including lease condensate, the brief stated.

In 2012, the Middle East produced 24.1 million bbl/day of crude oil, a basically flat number over 2011 production. Gains in several Middle Eastern nations were offset by declines in Syria and Qatar. Sanctions also contributed to a 17% decline in Iranian production.

This EIA chart shows how crude oil and condensate production has changed year on year since 2007.

The EIA report synthesized recent figures with historical data on regional production trends between 1980 and 2010, EIA analyst Stacy MacIntyre, who compiled the statistics, explained. The data came from the agency’s International Energy Statistics database, with additional trend information compiled from EIA country analysis briefs or other energy briefs published by the EIA, she said.

The former Soviet Union ranked second in global production, with 12.7 million bbl/day, followed by North America, Africa, Asia and Oceania, Central and South America and Europe. Russia, the world’s second-largest crude oil and lease condensate producer, has seen production gains since 2009 due to development of eastern Siberian oilfields, use of advanced technologies and improved recovery techniques in mature fields in western Siberia, and development of a new export infrastructure, the report stated.

In North America, average annual production rose to 12.2 million bbl/day, a reflection of increasing production in unconventional oil plays in the US and rising bitumen and synthetic crude oil production in the Canadian oil sands. North American production had dropped to 10.4 million bbl/day in 2008.

Trends in other global markets reported by the EIA include:

Africa: Recovery of Libyan production was the main driver behind a 6% increase in African production in 2012, to 9.1 million bbl/day. New production in some non-OPEC countries, such as Ghana, also has boosted oil production in the region since 2010. Ms MacIntyre also cited Niger, a landlocked nation in West Africa, as having gone from zero production in 2010 to 20,000 bbl/day in 2012.Asia and Oceania: A 2% decline in oil production in most of the region in 2011 has not recovered, with production remaining at 7.6 million bbl/day. Offsetting that, China, the region’s largest producer, saw production rise after the Peng Lai field in the Bohai Bay was brought back online. It is China’s largest offshore crude oilfield and had been shut down following a spill in 2011. “China’s production declined 0.5% 2011 and grew 1.7% in 2012,” Ms MacIntyre said. “China accounts for 57% of Asia’s production and 54% of Asia & Oceania combined.” Prior to shut-in, production rates at Penglai 19-3 had peaked at roughly 130,000 bbl/day, according to an EIA Country Analysis Brief for China, revised in April.Central and South America: Market contractions throughout the region, notably Brazil and Argentina, contributed to a 1% decline in 2012, following an increase of 3% in 2011. Production in 2012 was 6.6 million bbl/day.Europe: Continued declining production in the North Sea is the primary reason for a downward trend in Europe. Production declines averaged 9% in both 2011 and 2012, in part due to unplanned outages in the UK and a 12% tax rate increase implemented in 2011 by the British government.

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Onshore-tested MHA drilling fluid seeks offshore applications

By Katherine Scott, associate editor

ViChem’s MHA drilling fluid undergoes lubricity testing using an OFITE Extreme Pressure and Lubricity Meter at the company’s lab in Conroe, Texas.

As regulations around handling and disposal of drilling fluids get tougher around the world, ViChem Specialty Products believes its multi-hydroxyl alcohol (MHA) drilling fluid system can fill a niche need. The fluid, which was launched in 2011, is a “hybrid between OBMs and WBMs,” Dr Buddy Gaertner, ViChem director of research and development, said.  The multi-hydroxl alcohols in the system are short-chain hydrocarbons similar to oil, allowing for performance and stability comparable to oil-based muds. However, unlike petroleum products, the MHA molecule contains hydroxyl groups on each of the carbons in the chain, allowing it to be soluble in water and remain non-toxic to the environment.

So far, the MHA has been field-tested and commercially deployed onshore only, primarily in the US Marcellus and Eagle Ford plays, but ViChem is working to take the fluid system offshore for additional field testing. The company notes that lab tests have shown its L-20 lubricant, which is a non-petroleum based organic vegetable oil, will work well with the seawater used in offshore drilling. “It turns out that our lubricant is more effective in saltwater and helps it work well with multi-hydroxyl alcohols,” Dr Gaertner said.

The best application for the MHA system, he continued, is in areas where environmental drivers are strongest, such as Pennsylvania, West Virginia, Colorado and New York. “We’re working with an environmental consulting agency, Tox Strategies, on our overall strategy to quantify environmental claims and will submit our product to several companies to be tested for offshore use in the Gulf of Mexico but also to expand that to make sure that we meet North Sea regulations, as well.”

ViChem’s MHA fluid was field-tested on Nabors’ Rig 716 in Madison County, Texas. So far, the fluid system has been tested and commercially deployed primarily in the Marcellus and Eagle Ford.

In a December 2011 field trial in the Eagle Ford/Woodbine, the MHA system was used to compare the toal depth versus days in the surface-hole sections of two horizontal wells, one using the MHA and one using a conventional WBM. The MHA system drilled without incident to 13,500 ft in less than 18 days, while the offset well drilled with the conventional WBM took 29 days to reach 10,800 ft and routinely pulled tight, taking reaming upon completion to run the final string of casing. The MHA system not only saved time but also increased the production potential of the well because of the additional length of the horizontal in the payzone, according to ViChem.

The MHA system does have its limitations, particularly around cost and temperatures. “For your conventional water-based muds, where you’re operating in very shallow, easy wells, there’s still a target for it because they are very inexpensive. And because our system is natural, there’s a temperature limit of about 350°F, so in those places that are really deep and really hot, OBMs are still needed,” he said.

Dr Gaertner attributes the success of the MHA system so far to the three years of research that was done at ViChem’s Conroe, Texas, lab before it was rolled out. “That’s why we were able to take this giant leap from what has been traditionally used in the oilfield and what we’re proposing to use right now, because we started in a laboratory, backed it up with research and then combined that with field application.”

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Huisman opens 380-meter quayside in China

Posted on 26 June 2013

Huisman has opened a new 380-meter quayside in Zhangzhou, China, that was designed for loading and installation of heavy-steel construction onboard offshore vessels.

Huisman has opened a new 380-meter quayside at its production facility in Zhangzhou, China, under its subsidiary Huisman China. The quayside features a Huisman-designed and produced 2,400-mt traveling quayside crane and direct deepwater access, making it suitable for loading and installation of heavy-steel construction onboard offshore vessels, including semis.

The traveling quayside crane, “Skyhook,” has two main lifting configurations. The heavy-lift configuration is capable of lifting 2400 mT at 30-meter outreach, with a maximum lifting height of 100 meters. The extended-reach configuration enables placing a 200-mT load at 90-meter outreach, with a maximum lifting height of 140 meters. The crane can travel along the quayside while carrying maximum load in its hooks.

The quayside application and design started in 2009, and construction via reclamation started early 2011. In total, 100,000 sq meters of land was reclaimed and converted into the 380-meter-long quayside, which has a load-bearing capacity up to 40 mT/sq meter, and a storage yard of 86,000 sq meters. To facilitate transport of heavy project cargo, the quay has also been equipped with special Ro-Ro hinge foundations more than 130 meters.

The quayside was launched this week during a naming ceremony for BigLift’s new heavy-lift vessel Happy Sky. The vessel, built by Larsen & Toubro in India, features two 900-mT heavy-lift Huisman mast cranes, which were the first to be commissioned at the new quayside.

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2nd OSRL capping system delivered to Singapore base

All four of OSRL’s capping stacks are designed into a standard configuration, with common pipework, valves, chokes and spools all rated to 15kpsi. The common framework gives greater flexibility by using interchangeable gate valves and rams.

By Astrid Wynne, contributing editor

Oil Spill Response Ltd (OSRL) unveiled the Subsea Well Intervention Service (SWIS) at its new facility in Singapore on 13 June. It is the second of four OSRL systems to be delivered this year, following the delivery of the first capping system in Norway in March. A third system is expected in South Africa in the next few weeks and a fourth in Brazil by Q4. “Each of the centers was chosen because of their strategic location in relation to the major drilling regions. This one covers Asia Pacific,” said Robert Limb, OSRL chief executive officer. The location of the facility in Singapore’s Loyang area was selected for its proximity to the deepwater harbor and to Seletar airport, where a dedicated aircraft that can be used for aerial dispersant is on permanent standby.

A capping stack toolbox and a subsea dispersant hardware toolbox are the main components of the SWIS. Both were developed by the Subsea Well Response Project (SWRP), a consortium of experts from nine oil and gas companies that worked to improve the industry’s subsea well control incident intervention capabilities outside of the US Gulf of Mexico. Houston-based Trendsetter Engineering  was selected to manufacture the four capping systems, which were designed to be adaptable to a range of well and metocean conditions. The 7 1/16-in. stack in Singapore is currently set up in a 10,000-psi configuraton but can become a 15,000-psi stack by changing out a central gate valve system with the dual-ram system.

“The connectors are similar to those in use in the US GOM in that they are provided with H4 and HC connectors, but we needed our system to be modular to accommodate the different well scenarios,” Keith Lewis, project manager for SWRP, said. “The rams were included to deal with gas volume and expansion, and the 7-in. gate valves offer lower weight and faster closing time, providing benefits for oil wells with a lower gas/oil ratio.”

Singapore is also a strategic location for storage of the subsea dispersant hardware kits. Manufactured by Oceaneering, the kits are designed for the subsea application of dispersant if the rig fails to close off the BOP. They include tools for site surveys, such as 2D and 3D sonar debris-clearing equipment with cutting, grappling and dragging tools, flying leads, distribution manifold and dispersant wands to inject dispersant at multiple locations, and high-pressure, high-volume accumulators for closing the existing BOP.

The new SWIS forms part of the permanent “Tier 3” preparedness and response capability of OSRL, a not-for-profit industry-owned cooperative with 18 deepwater capping members worldwide. The tiered approach integrates the contingency plans of the operator, government agencies and other stakeholders to ensure sufficient capabilities are in place. “Tier 3 is global response “big guns.” Tier 2 is regional or occasionally for a specific oilfield/installation, and Tier 1 is equipment at or very close to the location of the activity,” Mr Limb said.

In addition to the capping stack and a subsea dispersant hardware, OSRL’s Singapore facility has a Hercules aircraft on standby 24/7 at Selatar Airport, sea access for its two 20-meter catamarans and other specialized response equipment. The center employ two incident managers and 28 spill response specialists, all full-time, with additional response backup by 53 technical staff trained in oilfield response.

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Cimarex enters joint development agreement with Chevron

Posted on 25 June 2013

Cimarex Energy has entered into an agreement with Chevron USA, a subsidiary of Chevron Corp, for the joint development of their combined Delaware Basin acreage in Culberson County, Texas. Cimarex will act as operator of the joint development, which covers 104,000 acres.

Chevron will contribute acreage and pay Cimarex approximately US $60 million for a 50% interest in the Cimarex-built Triple Crown gas gathering and processing system and wells drilled on the acreage in 2013.  The contract has an eight-year term.

“Collaborative development of this ‘checkerboard’ acreage ownership makes perfect sense. Optimal well placement for both Second Bone Spring wells and longer-lateral Wolfcamp shale tests can now be achieved,” Tom Jorden, CEO of Cimarex, said.

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BP/Maersk look outside industry to develop HPHT drilling technology

By Astrid Wynne, contributing editor

A main challenge in Maersk’s project with BP will be to create a full package for HPHT, particularly with well control, Maersk Drilling chief technical officer Frederik Smidth said.

A partnership between BP and Maersk Drilling to develop conceptual engineering designs for HPHT drilling technology is looking beyond industry norms. “Higher pressure can be taken care of with more steel, to put it in simple terms, but the high temperatures have implications on the seal technology within the risers, the material technology inside the BOP and the rams to take the high temperatures. That’s where we might have to look a little bit outside our industry for solutions,” Frederik Smidth, chief technical officer at Maersk Drilling, told Drilling Contractor.

As the project is just beginning – the two companies announced their partnership agreement in February – much still needs to be explored. However, Mr Smidth said he already sees that one major challenge will be to create a reliable package for HPHT, even if certain technology components are already available. Major vendors, for example, have development of 20,000-psi well control equipment and driller risers under way.

“I see the main challenge is to get the full well control package safe and efficient to operate. We will need a hookload capacity beyond the current 2.5 million lbs for these types of wells, but the challenge is finding the well control and lifting structure equipment and the flexible hoses and connections used in the drilling system.”

Under Maersk’s agreement with BP, the initial studies will outline the basic design criteria, such as hookload capacity and the vessel size and type that will be capable of operating in a 20,000-psi and 350?F environment, as well as the safety systems needed to protect and train crews. Phase 1 of the project is expected to last approximately one year, with a potential extension into a contract for a finalized design that could culminate in an order by late 2015 or early 2016.

“The first units would begin drilling the US Gulf of Mexico (GOM) in 2018 or 2019, with possible additional requirements in Egypt and Azerbaijan if a contract is awarded,” Mr Smidth said.

He added that this joint project with BP is also providing Maersk Drilling with valuable insight into the deepwater cost structure from an operator’s perspective. Knowledge found within BP’s deepwater well database, for example, is helping Maersk to design systems to reduce nonproductive time.

“The total cost of drilling a deepwater well in the US GOM is around $1.2 to $1.3 million a day. We, as the drilling company, account for only 50% of the costs for an oil company,” Mr Smidth explained. “It is interesting to understand the other half of those costs, like for example the 30% to 40% nonproductive time when drilling deepwater wells. We expect to gain a knowledge that can be used in more traditional rig designs. The aim of the process is to build rigs which are safer, faster and cheaper to operate.”

Going forward, Mr Smidth sees the potential for more collaborative technical projects between drilling contractors and oil companies. “For the new frontiers – 20k, Arctic Sea, Barent Sea, the high H2S drilling in the northern Caspian – I think this kind of cooperation is essential. Drilling costs are increasing, and we can only reduce them by understanding each other’s cost structure.”

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