Ship shape

Jurong Shipyard, a subsidiary of Sembcorp Marine, has orders for nine jackups and four semisubmersibles at its yard in Singapore. Sembcorp is also building a new yard, Estaleiro Jurong Aracruz in Brazil, that’s scheduled for completion by the end of 2014. Contracts already include seven drillships for Sete BrasilBy Katie Mazerov, contributing edito,

Ultra-deepwater drives thriving activity, higher-capacity rig designs at established shipyards as Brazil makes a splash

By Katie Mazerov, contributing editor

The world’s offshore rig fleet is getting a makeover. The recovering global economy, healthy commodity prices, a burgeoning ultra-deepwater market and plans to venture into more harsh-environment fields have converged in a perfect storm of newbuild activity at the world’s major shipbuilding yards. Add to the equation an aging jackup fleet and a push by operators for rigs with state-of-the-art technologies and increasing automation, builders are touting a bullish outlook reminiscent of the boom years of 2004 to 2005, when the newbuild trend began, only to be interrupted by the global recession.

Post-recession, the newbuild story has again picked up with strong demand for high-specification jackups, semisubmersibles for harsh-environment drilling and drillships that can accommodate heavier subsea equipment for high-pressure, ultra-deepwater reservoirs in the Golden Triangle – Gulf of Mexico (GOM), West Africa and Brazil.

Above and below: The OSX Açu Shipbuilding Unit in São João de Barra, in the northern sector of Rio de Janeiro, is scheduled to begin operationAs this year. The company believes it will be the largest shipyard in the Americas. It will cover 3.2 million sq meters and have a 2,400-meter waterfront, expandable to 3,525 meters. Hyundai Heavy Industries has a 10% stake in the project.

“A trend that is quite clear on the rigs being designed for high-pressure, ultra-deepwater drilling is the increase in derrick ratings, with both the drawworks and the derricks getting bigger and heavier,” said Karsten B. Meling, sales director for National Oilwell Varco (NOV). “Derrick ratings have gone from 1,000 tons to 1,250 tons of maximum lifting capacity, but on the new drillships being ordered, we’re seeing dual derricks, with each drill center having a rating of 1,400 tons that can lift 1,250 tons in the elevator that hangs below the top drive, and both centers with active heave compensated drawworks.”

At the center of this evolution is anticipation of the 20,000-psi blowout preventer (BOP), which in turn is impacting the weight of all related systems and equipment. “Today’s vessels have BOPs rated for 15,000 psi, and the systems related to that rating have a certain weight,” Mr Meling said. “Four years from now, BOPs will be rated for 20,000 psi. They will be three to four meters taller and weigh between 150 and 200 metric tons, more than the current 15,000-psi stacks, resulting in the need for increased capacity of the BOP-handling equipment, riser and derrick.”

These changing needs are resulting in increased levels in specific designs from both the shipyards and firms such as Moss Maritime and Friede & Goldman (F&G), following a period where standardization of many features played a key role in delivering on-time and on-budget jackups and drillships from some shipyards, said NOV’s David Reid, chief of sales and senior vice president for global accounts. “That previous trend meant investment companies were able to fund growth cycles, allowing them to take risks to invest on speculation in jackups that were attractive to drilling contractors,” he said. “Standards have not been as prevalent in semisubmersibles unless they are led by a specific driller who repeats a unique design.”

Beyond rig design trends, another change is on the horizon. Brazil is revitalizing its shipbuilding industry in a big way, with 11 shipyards currently under construction in attempt to meet the production needs of what is poised to become the world’s largest offshore market. Brazil’s move deeper into the rig-building industry is in line with the government’s desire to bring work into the country, said Mr Reid, who also serves as IADC’s division VP of drilling and well services. He notes that many of the Brazilian shipyard ventures have formed partnerships with the more prolific rig-building companies.

OSX, a subsidiary of Brazilian conglomerate EBX Group, has formed an exclusive partnership with Korean shipyard Hyundai Heavy Industries (HHI), which has a 10% stake in developing the massive OSX Açu Shipbuilding Unit in São João de Barra, in the northern sector of the state of Rio de Janeiro. OSX operates in the naval and offshore segments and provides integrated solutions for the oil and gas E&P sector.

“Hyundai, a global leader in naval construction, is providing OSX with state-of-the-art technology and know-how, bringing the latest-generation Asian technology to Brazil,” said Carlos Bellot, CEO of OSX. The São João de Barra facility, which is scheduled to begin operations in the first half this year, will be the largest shipyard in the Americas, with 3.2 million sq meters. It will have a steel-processing capacity of 180,000 tons/year, expandable to 400,000 per year, and the capacity to integrate up to 11 floating production storage and offloading (FPSO) units and eight wellhead platforms simultaneously, with a 2,400-meter waterfront, expandable to 3,525 meters.

Although OSX is not currently building any drilling rigs, the company’s portfolio encompasses FPSOs, fixed platforms, special vessels and oil tankers for Petrobras and OGX, as well as service companies like Malaysia-based SapuraCrest and Kingfish do Brasil, according to Mr Bellot. Of the 23 orders, 18 vessels are scheduled to be built and/or integrated at the OSX shipyard.

For the near term, however, HHI has scaled back its outlook for demand in Brazil. “The Brazilian market is developing differently than what we had expected,” said Kang Young-Seog, senior vice president for HHI’s Ship Sales Department. “Petrobras announced recently that it will be concentrating more on existing field production capacity rather than exploring the pre-salt areas, as they had planned earlier. Therefore, we don’t expect high demand from the Brazilian market, at least for awhile, unless Petrobras changes its strategy.”

Due to the large number of rigs currently under construction around the world, with many still seeking contracts, Mr Kang also anticipates contractors taking a “wait-and-see” position for the time being. “I understand that 47 out of 75 drillships under construction globally have secured contracts, meaning 40% remain unchartered,” he noted. “Therefore, our outlook on demand depends on how early and the terms drillers can secure charter contracts for newbuilds deliverable in the year to come. Longer term, however, I think the deepwater newbuild market will be bright due to continuing high oil prices, providing incentives for operators to invest in deepwater exploration.”

Hyundai Heavy Industries’ (HHI) Offshore Yard is located next to its main shipbuilding yard in Ulsan. HHI is focusing on building new commercial vessels and offshore-related vessels such as drillships, semisubmersibles and FPSOs.

HHI currently has 13 drillships under construction for Diamond Offshore Drilling, Rowan Companies, Noble Drilling and Fred Olsen Energy, along with  two semis for Fred Olsen and Seadrill.

“Drillers are seeking drillships that can drill deeper than 10,000 ft and accommodate heavier subsea equipment, such as 20,000-psi blowout preventers,” Mr Kang said. “They also prefer purpose-built and operation-friendly designs, like the HHI-Gusto P10000 we are building, that reduce downtime.” The rig is capable of operating in water depths up to 12,000 ft and features two complete ram BOP systems. It is equipped

No. 1 Drydock is one of 10 drydocks at the HHI shipbuilding yard in Ulsan, South Korea. The dock is 2,200 ft (672 meters) long, 302 ft (92 meters) wide and 44 ft (13.4 meters) deep. HHI has 13 drillships and two semisubmersibles under construction.

with a 165-ton, heave-compensated crane to enable deployment of subsea production equipment. HHI also has developed a wider beam design, the HD 12000, which features an eco-friendly, high-capacity new hull form for deeper waters and

heavier subsea equipment.

“When it comes to semis, it is obvious that drillers prefer robust rigs, suitable for operating in harsh environments like the North Sea, Australia and Canada,” Mr Kang continued. “With this market trend in mind, we took a semi design, the CS60, from Moss Maritime, to build two semis, one at our Gunsan Shipyard, the other at Hyundai Samho Heavy Industries, our sister

company in Samho-eup,” an administrative division in southwestern Korea.

HHI, which has 10% ownership in the OSX Açu Shipbuilding Unit in Brazil, sees increasing demand for drillships that can drill deeper than 10,000 ft (3,048 meters) and accommodate heavier subsea equipment.

HHI’s customers typically have their own technical requirements and operational philosophy, customizing their newbuilds with features to give them competitive and operational advantages, he added. “Once they standardize their own fleets, they are not inclined to take other rig designs for the purpose of avoiding any inconvenience in the rig operation and maintaining commercial advantage,” Mr Kang said. The company is seeing a heightened focus on safety, with drilling contractors asking for such features as upgraded and/or spare BOPs for well control systems on newbuilds and even existing fleets.

Jurong Shipyard, a subsidiary of Sembcorp Marine, ventured into rig building in 2003 and has since delivered a series of semisubmersibles, including 12 units of the F&G ExD design, two units of the Bingo 9000 design, and two units of the Moss Maritime CS50 MKII harsh-

environment design. It has also completed several jackups, including four units of the Pacific Class 375 design and a Gusto MSC CJ70 harsh-environment unit.

Current orders include nine jackups, comprising six F&G JU3000N units, two F&G JU2000E units and a Gusto MSC CJ70 harsh-environment unit, and four semisubmersible rig projects. In

addition, more than $6.3 billion in contracts has been secured for the Brazilian market by Sembcorp Marine’s new yard, Estaleiro Jurong Aracruz, currently under construction by Jurong Shipyard in Espirito Santo and scheduled for completion by the end of 2014. Its contracts include seven drillships worth $5.3 billion for Sete Brasil to be chartered to Petrobras, as well as module construction and integration for two FPSOs for the Petrobras-led consortium Tupi BV.

“The construction of Estaleiro Jurong Aracruz will substantially strengthen our capabilities in meeting the needs of Brazil’s offshore sector in developing the giant pre-salt oil and gas reservoirs,” William Gu, general manager for Jurong Shipyard’s offshore division, said. “We have two decades of experience servicing Brazil’s oil and gas industry, and the new yard will further reinforce our position as a leading player and key partner for the country’s E&P sector. There is a huge demand for platforms in the region, and we are extremely pleased to be part of this significant growing industry.”

Maintaining market position

Above: Rig building accounts for 50% of revenues for Singapore-based Jurong Shipyard. Its parent company, Sembcorp Marine, is building the Estaleiro Jurong Aracruz yard in Brazil. Below: DSME currently has 15 deepwater units under construction, including five semisubmersibles and 10 drillships, at its shipyard in South Korea. The company has seen an uptick in demand over the past year, both in actual newbuild activity and in inquiries for new rigs.

Sembcorp Marine also is building a new 206-hectare (0.8 sq miles) shipyard in Singapore’s new port development, Tuas View Extension. First-phase construction, which spans 73.3 hectares (.28 sq miles), is under way and scheduled to begin operations in the second half of this year. The yard will more than double the group’s current ship repair, conversion and offshore capacity of 1.9 million deadweight tons, and will provide faster turnaround time, increased productivity, improved logistics, efficient workflow and introduction of new automation.

Mr Gu sees the current market turnaround as a trend going forward due to strong fundamentals in the offshore arena. Demand in all sectors is up, and he sees a shift among major drilling contractors to order more rigs on speculation, rather than wait for a contract. “The push is coming from the major operators who want rigs that are less than five years old,” he said. “Contractors want to maintain their market positions by replacing aging fleets with higher-capacity assets that can accommodate features such as high-pressure BOPs.” This is in contrast to the years preceding the recession, when the spec rig market was driven by investors, he noted.

He also sees a remaining niche for lower-specification models even as high-spec rigs gaining popularity among operators. “We have a broad mix of customers, with some wanting more automated features and others not. It depends on where they are drilling,” Mr Gu said. “More automation means the crews need to be well-trained, and that can mean higher operating costs.”

Jurong Shipyard anticipates a continued uptick in rig building in the next 12 to 18 months, he indicated; good news since rig building accounts for more than 50% of the shipyard’s revenues.

The jackup market is especially strong in Asia Pacific, Mexico, India, Southeast Asia and the Middle East. Jurong Shipyard is also seeing more demand for heavy-duty, harsh-weather rigs, Mr Gu said, noting that some Arctic exploration will commence this summer.

The shipyard is building a second Gusto MSC CJ70 harsh-environment jackup for Seadrill, with delivery set for Q4 this year, and a harsh-environment Moss Maritime CS60 ultra-deepwater semisubmersible for North Atlantic Drilling, with delivery scheduled for Q1 2015. The semi, being designed for year-round drilling, will have a water depth rating of 10,000 ft, a maximum drilling depth of 40,000 ft and the ability to operate in -25°F and strong winds. Other projects include an intervention semi for Helix in the GOM and two accommodation semis for Prosafe, for North Sea harsh-environment conditions.

Jurong Shipyard also has a robust upgrade and conversion business, currently upgrading one semisubmersible for Diamond Offshore Drilling and converting two FPSOs. “Some choose to convert and upgrade as the turnaround is relatively faster compared to newbuilding. To them, time is money,” Mr Gu said, adding that Jurong Shipyard is the only yard in the world constructing newbuilds and carrying out rig conversions at the same location.

Deepwater investment

DSME, whose shipyard is located on the southeastern tip of the Korean Peninsula, is anticipating a return to the jackup market after receiving inquiries for high-end, heavy-duty jackups for harsh-environment drilling.

Daewoo Shipbuilding & Marine Engineering Co (DSME) has seen an uptick in demand over the past year, both in actual newbuild activity and in inquiries, for deepwater and ultra-deepwater rigs, said Justin Y.S. Joe, general manager and head of offshore marketing, drilling. “Many drilling contractors want to retire their older, inefficient semi and jackup fleets, and we believe they will be investing more capital in deepwater drilling units,” he said. “This is especially true for the large and mid-size drilling contractors, but the smaller companies will need to replace their older units, as well.”

DSME currently has 15 deepwater units under construction, including five semisubmersibles and 10 drillships. Mr Joe attributes the increasing demand to indicators that suggest prices will remain strong, a result of industry’s focus on deepwater drilling.

“We’ve seen newbuild orders and inquiries continue to increase, especially in the fourth quarter of 2012 and the first quarter of this year,” he said. “Newbuild orders aren’t at the levels of 2011 but definitely are coming in at a higher pace than in 2009 and 2010, when the industry experienced the downturn due to the recession and subsequent fall in oil prices.” In 2011, DSME saw a 10-fold increase over 2010 in the number of inquires from potential clients, then an additional 30% increase in inquiries in 2012.

“We think the number of orders this year will be similar to where they were in 2012, mostly from existing clients but also from new customers ordering rigs on speculation and new players who want to be part of the ultra-deepwater market,” Mr Joe continued. “Our analysis shows that many of these units won’t be drilling in ultra-deepwater reservoirs yet, but companies want to be ready for that market when it starts to take off.”

Taking a long-term view, customers are requesting rigs to accommodate dual derricks, dual BOPs and 20,000-psi BOPs. “In 2004 and 2005,

With 36 jackups and six semisubmersibles under construction at its yard in Singapore, Keppel Offshore & Marine is anticipating strong demand for newbuilds driven by sustained high oil prices, new exploration and a shortage of high-spec rigs.

when the newbuild boom started, rigs featured primarily single-derrick designs, but dual-drilling packages are now the trend,” he noted. “Operators may not require the dual BOP packages and 20,000 psi now, but they want to have that capability in the future.” Of the rigs under construction at DSME, half will be delivered in 2014 and half in 2015. Most of the drillships targeted for 2014 delivery will be contracted this year, he said.

Mr Joe also sees an emerging market for harsh-environment mid-water semisubmersibles. “Normally, harsh environments require semis, not drillships,” he said. “The existing aging mid-water semi fleet needs to be replaced, and it is unlikely that stacked units will return to the market due to safety, cost and efficiency reasons.

“The newer and relatively lighter semisub designs for mid-water will be required for this type of drilling,” he continued. “In addition, there will be more interest and demand to drill in Arctic areas, with some operators moving into this sector already. We may see some newbuild activities for the Arctic area in the near future.”

While DSME has not been active in the conventional jackup space for many years, the company is anticipating a return to that sector after receiving a number of inquires for heavy-duty jackups for high-end markets in harsh environments, Mr Joe indicated.

 Upgrading jackup fleet

Keppel Offshore & Marine, another established company in the offshore rig-building space, has 36 jackups under construction and is anticipating strong demand for newbuilds driven by sustained high oil prices, exploration in new arenas and a shortage of high-spec rigs. “Analysts are estimating that the jackup market will

The R&D team at Keppel has developed new technologies to support E&P in deeper waters and harsher frontiers, such as an Arctic jackup being co-designed with ConocoPhillips.

remain undersupplied over the next two years, and there is still high demand for high-spec jackups,” said Wong Kok Seng, managing director, offshore, for Keppel Offshore & Marine and managing director of Keppel FELS. “Even after accounting for some 80 deliveries by 2015, more than half of the world’s jackup fleet will be over 30 years old, driving the replacement cycle for further rig orders and upgrades.

“Post-Macondo, the industry is more acutely aware of the importance of safety and reliability,” he continued. “This has resulted in a rig replacement cycle being driven by operators’ growing preference for newer, high-spec rigs that boast strong safety and efficiency features.”

Other features include longer leg lengths, from 350 ft to 400 ft; bigger spud cans for soft soil conditions and harsh climates; accommodations for up to 150 people; higher hookloads for the  drilling package; better escape means and protection from the drill floor; and an increase in mud pit tank capacity and design density. The company also is manufacturing CJ70 jackups, six DSS 38E semisubmersibles, one semi tender drilling rig and two floating accommodation vessels. Rig modifications are specific to site conditions, and upgrades are done to meet new contract requirements and regulations in specific markets.

Left and above: NOV supplied controls systems, top drives, iron roughnecks and drawworks for both the Seadrill West Callisto jackup and the ENSCO DS-6 drillship. Both the drawworks and derricks are trending bigger and heavier on newbuilds, with derrick ratings going from 1,000 tons to 1,250 tons of maximum lifting capacity. New drillships are also often coming with dual derricks.

PEMEX’s recent announcement to increase its jackup fleet and ongoing business from Brazil, particularly in the repair, maintenance and rig upgrade sectors, as other indicators of demand. Keppel also is building several harsh-environment jackups for the North Sea and is seeing interest in expanding fleets in the Caspian Sea, Asia Pacific and West African markets.Over the past decade, Keppel has invested more than $1.5 billion in expansion and upgrades of its shipyards, including the addition of new floating docks in some yards, and enhancing facilities with increased technology and automation, including automated pipe shops. The company also is embarking on the phase two expansion of the Keppel Nantong shipyard in the Jiangsu Province of China to increase the yard’s capacity for offshore projects.

DSS is a trademarked term of Keppel FELS.

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Automated control system integrates preventive and predictive maintenance functions

Integrated Drilling Equipment’s second-generation, automated Centurion drilling system has been installed on a rig for Lewis Energy in the Eagle Ford play.

By Katie Mazerov, contributing editor

Integrated Drilling Equipment (IDE) has introduced the second-generation, automated Centurion drilling control system on a new 1,500-hp AC Sparta rig for Lewis Energy in the Eagle Ford Shale.

The new system, developed by IDE’s Automation and Controls division, combines preventive and predictive maintenance functions, such as coriolis flow meters, to measure real-time drilling fluid density, mass flow and temperature and pressure readings. It is designed in an open architecture software platform to deliver real-time information and control to drilling contractors, operators and service companies.

“Using this type of platform enables service companies to employ specialized applications for control of the auto-driller and pressure control aspects of rigs,” IDE CEO Steve Cope said. “The use of customer-supplied applications allows for optimal rate of penetration while maintaining zone management and the safety of personnel and machinery.”

The software technology used with the Centurion system also eliminates the need for customers to learn another interface, he added. Information can be accessed onsite and offsite via the  internet or by using a personal computer, smartphone or tablet.

“With this system, we’re taking existing technology and implementing it in a new way on land-based rigs to increase efficiency, accuracy and predictability,” said Charlie Piper, IDE vice president of technical products. “For example, the system can perform oil analysis to give us the real-time properties or viscosity of the diesel powering the rig so we know how much life is left in the diesel before it needs to be changed,” he said. Data from the new system to better understand the trigger points for preventive maintenance and measure the system’s economic viability is being collected and analyzed at 60- and 90-day intervals.

The Centurion system package for the Lewis rig is outfitted with a full package of options, including an integrated, self-aligning satellite system with high-speed broadband; offsite access to all systems; full communication systems with voice over IP; telephone; IP camera and DVR system; fire and gas detection; real-time logging, and offsite data collection and reporting. “By using our own satellite system, we are able to collect and aggregate the data and transfer it quickly to our monitoring facility,” Mr Piper added.

The Sparta Drilling System, one of IDE’s engineered rig packages offered in 500-kip, 750-kip and 1,000-kip (a kip is 1,000 lbs of force) load ratings, features a modular self-elevating mast and a substructure with an integrated walking system. It is designed to be fast-moving for efficient rig moves from pad to pad and well to well. The rig also features the latest AC variable frequency drive technology, proprietary drilling controls and automated options.

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Environmentally friendly proppant technology to improve hydraulic fracturing efficiency

Preferred Sands uses non-phenolic, resin-coating technology at its plant in Genoa, Neb. The technology is designed to be more environmentally friendly and efficient than conventional phenolic-based resins and has been introduced in five US basins, including the Permian, Bakken, Mid-Continent, Utica and Eagle Ford, and in central Alberta, Canada. Preferred Sands plans to open a second processing plant in May.

By Katie Mazerov, contributing editor

Preferred Sands has launched a non-phenolic, resin-coating technology designed to be more environmentally friendly and efficient than conventional phenolic-based resins.

The technology, developed in collaboration with Dow Chemical Company, has been introduced in five US basins, including the Permian, Bakken, Mid-Continent, Utica and Eagle Ford, and in central Alberta, Canada, said Preferred Sands founder and CEO Michael O’Neill. The product has been used by more than 50 operators in more than 100 wells.

“This innovative process allows for coated sand to be produced in a manufacturing process that requires less energy while minimizing environmental impact compared to current phenolic resins,” he said. “It also provides the industry with an outstanding performance-to-cost value, enabling users to substantially improve operations while still curtailing expenses.”

The resin was developed to meet three critical needs of the oil and gas industry. “Not only does it perform well under a range of conditions and depths, it is also cost-effective and contributes to the sustainability of the drilling process,” Mr O’Neill continued.

Phenolic-based resins, which contain phenol and formaldehyde, can leach into well water or impact viscosity or cross-linking fracturing fluids used to place the proppant, he explained. In addition, partially cured phenolics often fully cure before the fracture has the opportunity to close and force particle-to-particle contact, thus are unable to create a strong consolidation or bond.

The non-phenolic products do not bond until they achieve closure stress, so they can hold all the bond strength ability to consolidate in the fracture, resulting in greater efficiency and reduced cost.

The technology marks two new product lines for the company, each addressing specific well conditions. The RCS Garnet is designed to control flowback in low-temperature reservoirs and includes a built-in ability to bond at low temperatures that does not require additional chemical treatment. “Phenolics came out of the foundry industry and were made for very hot temperatures, so they struggle to perform at lower temperatures,” Mr O’Neill explained.

Activators, which can be added to conventional phenolic resins to help them create a low-temperature bond, often cause the surface of the resin to deform under stress and so perform with mixed results. “Weakening the surface lowers the conductivity of the phenolic,” Mr O’Neill said. “The RCS Garnet doesn’t require an activator, so it holds its strength and conductivity and will bond all the way to down to below 80°F,” he said.

A conveyor belt transports sand before it is coated with Preferred Sands’ non-phenolic resin technology.

The RCS Pearl was developed to deliver better bond strength and flowback protection in hotter, deeper wells. Preferred Sands expects to introduce two additional products in September, Mr O’Neill said. The company also will open a second processing plant in May and has been approached by operators in several countries interested in using the non-phenolic resin technology. Germany and several other European countries don’t allow phenolics to be pumped into wells.

“The future of hydraulic fracturing is going to be about who delivers the most value for clients and the greatest technical efficiency, and the ability to innovate and create new products,” Mr O’Neill said. “For hydraulic fracturing to be sustainable for the long term and stand up to scrutiny, industry needs to continually look at improving all aspects of the process.”

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DOI to encourage RD&D of oil shale, tar sands resources

Posted on 28 May 2013

The US Department of the Interior (DOI) has finalized a plan to encourage research, development and demonstration (RD&D) of oil shale and tar sands resources on Bureau of Land Management (BLM) lands in Colorado, Utah and Wyoming.

The Record of Decision and plan amendments make nearly 700,000 acres in Colorado, Utah and Wyoming available for potential oil shale leasing and about 130,000 acres available for potential tar sands leasing in Utah. In November 2012, the BLM signed two additional leases for RD&D oil shale proposals to encourage industry to develop and test technologies aimed at developing oil shale resources on a commercial scale.

“This plan maintains a strong focus on research and development to promote new technologies that may eventually lead to safe and responsible commercial development of these domestic energy resources,” DOI Secretary Ken Salazar said. “It will help ensure that we acquire critically important information about these technologies and their potential effects on the landscape, especially our scarce water resources in the West.”

The BLM will also begin soliciting public comments on proposed revisions to the commercial oil shale regulations.  The proposed revisions are designed to ensure a fair return to the American taxpayer, encourage responsible development of federal oil shale resources, and evaluate necessary safeguards to protect scarce water resources and important wildlife habitat.

The proposed rule identifies several options for amending the royalty rates for commercial oil shale production. The BLM will consider whether to retain flexibility to adjust royalty rates when more information is available about costs of production, energy inputs, and impacts associated with various extraction technologies.

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Real-time data, reservoir model combination addresses GOM challenges

Schlumberger is focusing on addressing geological and reservoir challenges in the Gulf of Mexico that lead to narrow operating environments, Wallace Pescarini, vice president, deepwater operations at Schlumberger, said. “As you access the reservoir, drilling through the salt, in the pore and frac gradient, and in very narrow operations, the weight window adds challenges during the drilling process.”

By Joanne Liou, associate editor

Growing activity in the Gulf of Mexico (GOM) reflects the industry’s capability to meet increasing operational challenges in deepwater, where activity has returned to pre-moratorium levels despite more stringent regulations. Schlumberger, which relocated resources to other basins during the moratorium period, has moved resources back to the GOM as activity returned and is continuing focus on geological and reservoir challenges that lead to narrow operating environments.

“That is a challenge for the GOM, and some potential shallow hazards, such as shallow water flow or near-surface faults, add more complexity to the operation. As you access the reservoir, drilling through the salt, compounded by uncertainty on the pore and frac gradients and very narrow operation mud weight window, adds challenges during the drilling process,” Wallace Pescarini, vice president, deepwater operations, said.

To address such challenges, Schlumberger is combining real-time drilling evaluation data with the reservoir model using advanced interpretation techniques to analyze and act on the data in real time. Seismic-guided drilling is one example, in which the LWD checkshot data are used to constrain the surface seismic model in real time to help narrow down the depth uncertainty and to identify overpressure zones in front of the drill bit, Mr Pescarini said.

In the GOM, petrophysical and seismic data from offset wells are used to create a model of the formation pressures. “By leveraging the latest advances in computing power, we are now able to re-migrate the seismic model around the well while drilling,” he stated. “This allows us to predict the formation pressure up to 1,500 ft (457 meters) in front of the drill bit.” The drilling program can then be modified to reflect the real-time predictions.

Another trend that continues to evolve, mainly to respond to the described operational complexity, is the capability to bring drilling experts together as an integrated team during the planning and execution phases, supported by real-time workflows. “This is a trend you are seeing in the market. Specifically in the GOM, we are very well supplied with these experts and have located them in our PetroTechnical Engineering Centers to ensure that a collaborative environment is created.”

Andy Hawthorn, Schlumberger business development manager, earth model building, explained that there is a four-fold increase in deepwater NPT due to wellbore instability and mechanical instability, during a presentation at the company’s re-launch of its Digital Technology Theater in Houston in March.

The ultimate aim is to drill fewer wells but produce more oil. “To be successful, every well has to be in the right place and be able to produce over the entire life of the field,” Andy Hawthorn, Schlumberger business development manager, earth model building, said during a presentation at the company’s re-launch of its Digital Technology Theater in Houston in March. “Industry statistics show that with GOM wells in over 3,000-ft water depth, about 45% to 48% of all wells require a sidetrack. Of those, 50% require more than one sidetrack, which means we’re not getting it right the first time, all the time.”

Close collaboration among operators, contractors and service providers will be key going forward, as downhole nonproductive time (NPT) continues to increase, driven by the increasing geological complexity of deepwater E&P. “There is a four-fold increase in NPT due to wellbore instability and mechanical instability,” Mr Hawthorn said. “There is also a four-fold increase in the number of times BOPs are activated as the complexity of wells increases.”

Reducing NPT will require a combination of efficiencies within the drilling operation, coupled with putting wells in the right place the first time so it can produce over the entire life of the field. “You have to combine softwares and combine disciplines and expertise. You have to understand how much uncertainty you have in your measurement and the assumptions you made in your workflows before you hand it to the next set of people to do the next sequence of processing.”

For a project in the subsalt Wilcox structure in the GOM, Schlumberger generated 1,000 models of what the top Wilcox would look like. “This is the starting point because attempting to quantify on the amount of uncertainty allows you to make the correct measurements that drive the uncertainty down, allowing you to make objective decisions,” Mr Hawthorn explained. A simple one-dimensional stretch in most cases is no longer adequate. “We are dealing with a 3D, and increasingly, 4D environments. This requires a better approach.”

Digital Technology Theater

The Digital Technology Theater (DTT) in Houston is a key platform Schlumberger is using to help operators in the Gulf of Mexico. A re-launch event in March focused on showcasing the company’s deepwater technologies and services. The upgraded DTT features a 25-ft-wide screen powered by six high-resolution Barco projectors.

“With so many disparate groups and disciplines involved in deepwater projects, collaboration is absolutely fundamental to ensure that the project is carried out safely and successfully. The DTT is a good example of how the various groups can integrate and communicate,” Keith Tushingham, Schlumberger Information Solutions (SIS) DTT producer, said.

In April, the DTT was used to connect to the Schlumberger office in Aachen, Germany, to connect a client to the basin modeling experts. “Global tele-presence is common place today, but being able to transmit large amounts of data to remote locations is a different matter,” he said. “That requires good latency connectivity and cloud-based collaboration capabilities. This is the difference that the DTT brings to an organization”

Schlumberger will open another DTT in Kuala Lumpur in July to serve the Asia market, and other centers are planned for Oslo, London, Dubai and Calgary by the end of this year. Each center will address specific regional challenges.

“As SIS is focused on these industry challenges, it’s catalyzed a broader integration across our organization,” Mr Tushingham stated. “This allows us to integrate and get access to the breadth of all our expertise.”

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Case study: Planning enables remote-area drilling campaign

Operators share rig, services for exploratory, appraisal program offshore Falkland Islands

By J.W. Jenner, A. Morrison, Rockhopper Exploration; R. Lyons, Desire Petroleum; L. Phillips, AGR Petroleum Services; I. McBean, Diamond Offshore Drilling (UK)

Figure 1 shows the structural configuration of the North Falkland Basin’s Sea Lion area, where the Sea Lion 14/10-2 exploration well was drilled in 2010. Extensive 2D seismic surveys were conducted by the operators after obtaining licenses and in preparation for the drilling campaign.

Offshore the Falkland Islands, approximately 650 km southeast of the South American continent, two small UK operators with limited in-house operational resources conducted a successful drilling campaign. The project was made possible through teamwork and the continuity provided by using a drilling project management company and a single drilling contractor.

This article will summarize the geological conditions encountered in the North Falklands Basin and discuss the drilling engineering and well planning. It will also discuss the importance of the logistics planning and supply chain management, which included the enhancement of limited onshore support facilities in Port Stanley, the main population center, and the introduction of industry standard safe operating procedures.

The area discussed in this article is referred to as the North Falklands Basin (NFB). Water depth across the basin varies from 100 meters in the south to 500 meters in the north. Most wells have been drilled in water depths between 200-500 meters. Metocean conditions are similar to the Santos Basin offshore Brazil and generally more benign than the UK Central North Sea.

It had been acknowledged for some time that the NFB is a significant petroliferous basin, but its remoteness had deterred any extensive exploration activities. In the mid-1990s, a licensing scheme similar to that in the UK North Sea was introduced by the Falkland Islands Government (FIG). Four major oil companies were awarded blocks north of the islands and, after conducting extensive seismic surveys, decided to jointly contract a rig to drill six exploration wells in 1998.

Oil and gas were encountered in five of the six wells drilled; however, the volumes did not maintain interest, and the licenses were dropped.

In 2004, when the licenses became available again, Desire Petroleum and Rockhopper Exploration applied for blocks in the NFB and conducted 2D and 3D seismic surveys. By 2008, interpretation of the survey data along with previously acquired data revealed a number of structures potentially containing billions of barrels of recoverable hydrocarbons.

At the time, however, there was a shortage of available semisubmersibles with 1,000-meter water depth capacity. There was also little interest from drilling contractors for a short-duration exploration drilling program in a remote location.

In August 2009, Desire Petroleum signed a Letter of Intent for Diamond Offshore’s Ocean Guardian semi. The initial contract provided for four firm wells, plus four priced options.

Table 1: At the beginning of the Falkland Islands drilling campaign when Diamond Offshore mobilized the Ocean Guardian semi, there were prospects for only four wells. Just two years later, the rig had completed an evolving and significantly expanded program of exploration and appraisal wells.

The NFB is a north-south trending Atlantic rift filled primarily by Early Cretaceous lacustrine organic claystones and shales interspersed with sandstones that are primarily lacustrine turbidites, approximately 130 million years old. The basin, approximately 300 km by 50 km, is high-relief and structurally simple, with a deep graben bounded by shallow basement highs.

The oblique lineations become more pronounced toward the Falkland Islands coast, where Paleozoic rocks come to surface. A shallow anticlinal axis runs north-south along the center of the basin, and this axis, a relatively late-stage structural inversion, was drilled in two places by Shell in 1998. The Barremian turbidite fan systems that form the main hydrocarbon reservoirs discovered so far are sourced from the Paleozoic and older basement rocks of the eastern basin flank. The sands were initially deposited on the shallow basement highs, where they were winnowed, sorted and cleaned before being transported under high energy turbidite flows into the freshwater lake system in the basin. The reservoir sands, which were cleaned and sorted before being deposited within the contiguous organic source rocks and sealing shales that envelope the sands, are clean, uncemented, well sorted and free from clays within the pore spaces. The Sea Lion 14/10-2 exploration well drilled in 2010 was the first test of this play type in the NFB (Figure 1).

Figure 2: A generic well design was developed for the North Falkland Basin wells based on information from a previous drilling campaign. The design incorporated a 36-in. surface hole to approximately 164 ft (50 meters) below the seabed, where a 30-in. (76-cm) conductor with a 20-in. (51-cm) casing shoe would be run and cemented.

Desire had contracted AGR Petroleum Services to provide project management services covering permitting, well planning, engineering and programming, on-site supervision, logistics management and support and financial forecasts and well cost tracking on a daily basis.

The Ocean Guardian readied for departure on 26 November 2009. At the same time, AGR was setting up an office in Port Stanley and working with local companies to build a supply base near the harbor with storage facilities for casing, wellheads, mud, cement and other drilling consumables. An operations office was established with satellite communications with the rig and Aberdeen to manage the operation.

In December 2009, Rockhopper Exploration joined Desire Petroleum with an assigned contract for the Ocean Guardian to drill two additional exploration wells. The initial program was for the rig to drill up to six firm wells in the NFB for Desire and Rockhopper.

AGR then developed a generic well design, and sufficient consumables for four wells were ordered. This together with rental tools and excess rig equipment was transported via two large coaster vessels from Aberdeen to the South Atlantic. The three-week voyage was timed so the equipment would arrive well in advance of the rig.

Marine support was provided by two anchor-handling supply vessels (AHSV). An additional large platform supply vessel sailed independently from Aberdeen carrying extra high-value rental equipment and spud equipment for the first well; they were to be unloaded directly onto the rig in case of any delays in discharging the first coaster. Both AHSVs were equipped with a fast rescue craft and emergency life-saving equipment as it was planned at least one would be at the rig acting as standby vessel while drilling or either could be used for crew change if needed.

For routine crew change and offshore support, a dedicated S61N helicopter was contracted from a company that was already operating similar machines in the islands in support of the military. The rig crew and service company personnel would be working a 28/28 day shift cycle, and an arrangement was made to use excess capacity on the twice weekly military passenger charter flights from the UK to transport these personnel to and from the islands.

Midway through the two-year campaign, the demand to efficiently move personnel between the UK and the Falkland Islands on a regular basis had increased significantly. The companies then set up a fortnightly dedicated charter flight and replaced the S61N helicopter with two Super Puma AS332L aircrafts that were more modern and had greater range and capacity. The units were mobilized from Europe to a dedicated operating base at Stanley Airport.

Throughout the two-year campaign, emphasis was placed on minimizing any disruption to crew changes. This resulted in a low turnover rate in rig personnel.

In the lead up to the arrival of the Ocean Guardian and start of drilling operations, senior executives from both Desire and Rockhopper visited Stanley on a regular basis to provide progress updates to the Falkland Islands government and the Department of Mineral Resources (DMR).

Further, public “town hall” meetings were held to keep the islands’ residents informed and to answer any questions about how the drilling campaign might affect them or the local environment. Rockhopper also placed an industry veteran in Stanley to liaise between the company and local authorities and local community.

Legislation relating to offshore drilling activity in the NFB is the responsibility of the Falkland Islands DMR. Wells-related programs, environmental assessments, oil spill plans and permits to locate and drill were submitted to the DMR, which in turn referred them to various UK agencies for review before issuing approvals. Environmental Impact Assessments, which had been carried out for the earlier seismic surveys, were revisited and upgraded prior to the start of the exploration drilling program.

An oil spill contingency plan (OSCP) was also put in place by the individual operators.

Figure 3a : A pipe yard and equipment storage and maintenance area was constructed west of Port Stanley.

A generic well design was initially developed based on information available from the previous drilling campaign. No major drilling problems had been encountered and, with an expected total depth of less than 3,000 meters, a North Sea-type exploration well design was adopted (Figure 2). This incorporated a 36-in. surface hole to approximately 50 meters below the seabed, into which a 30-in. conductor with a 20-in. casing shoe was to be run and cemented.

Figure 3b: All the cargo and fishing vessels calling at the islands used a floating interim port and storage system.

Shallow gas had not been previously encountered, and the 3D seismic survey over the area showed no indication of its presence. The formations to be drilled were expected to be mainly claystones with occasional limestone stringers, which showed as good reflectors on the seismic profile, and sandstone intervals increasing with depth. With returns to the seabed, the 17-½-in. hole would be drilled riserless to approximately 1,200-meter TVD, where there was a good seismic reflector and the casing point selected on penetration rate.

After running and cementing the 13 3/8-in. casing and 18 ¾-in. wellhead, the BOP and riser would be run before drilling a 12-¼-in. hole to just above the projected reservoir at approximately 2,200 meters and setting 9 5/8-in. casing. An 8-½-in. hole would be drilled through the reservoir section to TD at approximately 2,700 to 2,850 meters. Leak-off tests would be carried out after drilling out each casing shoe to determine the kick tolerance and ensure well integrity.

While drilling with no returns, bentonite sweeps would be used to clean the borehole. With the riser in place and full circulation established, an Ultradril premium water-based mud system would be used. From the earlier wells, it was determined there were no serious drilling hazards, although caving of loose sands, washouts, lost circulation and some tight hole had been experienced. The team decided that those hazards could be controlled via good drilling practice and the water-based mud system.

Drilling motors and MWD/LWD tools would also be run in the drill string to improve performance and provide continuous gamma-ray and resistivity logs and directional data.

There was no evidence of abnormal or overpressured formations in the prospects to be drilled. Pore pressure studies had been carried out in Desire’s license area immediately south of the Rockhopper blocks using MDT/FMT and leak-off data from the wells drilled in 1998. This was augmented by a burial history and basin modeling study, which concluded that there may have been 1,000 meters of late inversion uplift across the previously drilled area but confirmed there was no evidence from existing data of overpressure in the depocenter in the Desire license area.

As the proposed wells in the Desire acreage were to be deeper than those in the Rockhopper area, it was concluded that overpressure across the basin was not expected.

The operators committed to gather as much wellbore data as economically possible because revisiting the area with a rig may not be possible in the short term. Besides the use of MWD/LWD tools in the drill string as previously mentioned, the operators also used regular open-hole wireline logging tools – gamma ray, resistivity, calliper, density, neutron, including SP in the 12 ¼-in. and 8 ½-in. open-hole and side-wall cores and seismic profilers at TD if required. In the event of success, formation pressures and samples could be taken in the reservoir.

A decision had been made not to send rotary coring and well-testing equipment to the islands due to cost factors. Suppliers also were reluctant to commit this relatively scarce equipment during a period of high demand in the North Sea.

To complement the well data that had been obtained, a data repository system was used to provide a secure off-site electronic records and data storage service. All well-related reports, logs and logistics data would be transmitted daily to this facility, minimizing recordkeeping. This was supplemented by real-time drilling and well data transmission services that enabled supervisors in Stanley, management personnel in Aberdeen and operators senior staff to monitor progress. The system recorded and transmitted a full range of well data, including drilling parameters, mud logging and MWD/LWD, providing continuously updated screens.

Shortly after the Letter of Intent for the rig was signed, personnel from Desire and AGR moved to Port Stanley to set up a shore base to provide logistics and operational support for the drilling of up to four wells. This was soon extended to eight wells by Rockhopper’s agreement to participate in the rig contract.

Because there were no suitable facilities in place, a pipe yard and equipment storage and maintenance area (Figure 3a) was constructed to the west of Stanley by a local logistics company, which also provided the handling equipment and personnel. The base would provide easy access to the main commercial jetty, the floating interim port and storage system (Figure 3b), a floating structure used by all cargo and fishing vessels calling at the islands.

By the time the rig arrived in mid-February 2010, the operations office and base were fully functional. With the arrival of the coasters from Aberdeen and discharge of the first consignments of well consumables, the supply chain was also established.

Local personnel were employed at the base when possible, but due to their lack of experience in handling oilfield equipment, experienced personnel were initially contracted from Aberdeen.

Figure 4: After a first round of wells were drilled by Desire and Rockhopper in the NFB, the well design was revised. Hole conditions and leak-off tests were good enough to continue drilling the 12 ¼-in. hole to TD after setting 13 3/8-in. casing.

The Ocean Guardian arrived on its first location north of the Falkland Islands on 19 February 2010. The local operations office was being manned by the drilling superintendent, drilling engineer and logistics supervisor. All were AGR personnel, with additional support from the Diamond rig manager and logistics controller. AGR also provided the day and night drilling supervisors and logistics coordinator on the rig.

This team remained relatively constant throughout the drilling campaign, ensuring continuity of personnel from well to well and the same operating standards and procedures.

A daily conference call hosted by the AGR well team leader in Aberdeen was instituted once the rig was on location. Participants included the senior rig-based personnel – OIM, senior drilling supervisor, toolpusher, logistics coordinator and safety officer – the team in Stanley and Aberdeen-based personnel. Operator staff were encouraged to participate and contribute when necessary.

Drilling started on the Desire 14/19-1 “Liz” exploration well on 22 February 2010. Despite information from pore pressure studies, some time was lost to unprognosed formation overpressure and to control a gas kick. The team completed and abandoned the first and deepest well in the program in about 53 days.

The rig then moved to the “Sea Lion” 14/10-2 location and spudded the first well to be drilled by Rockhopper on 16 April 2010. Following the standard design, the well was drilled virtually trouble-free to a TD of 2,744 meters in 18 days from spud, making what was eventually judged to be a commercial oil discovery. This was an unusual achievement for a company’s first ever well.

As drilling progressed toward the potential reservoir, the real-time data system proved invaluable, recording increasing gas levels in the mud returns and alerting the rig geologist and Rockhopper personnel in the UK to the situation. It was possible to remotely monitor what was happening as the sands were penetrated and the extent of the hydrocarbon column was revealed, enabling the rig geologist and the UK-based exploration manager to make timely and informed decisions regarding the well TD and to set up the wireline logging program. At TD, a full suite of wireline logs was run, side-wall cores were taken and reservoir fluid samples collected before conducting a final VSP survey.

Having confirmed that a considerable oil column had been penetrated, a well test was necessary to determine the nature of the fluids and potential productivity of the reservoir. As noted earlier, no testing equipment had been mobilized, and it would be at least three months before it could be shipped to the Falkland Islands.

Throughout the two-year drilling program, the operators experienced approximately 9.4% NPT and 5.8% waiting on weather averages. Figure 5a (above) charts the time versus depth for all wells in the Sea Lion, and Figure 5b(below) charts time versus depth for all exploration wells in the campaign except Sea Lion wells.

A 7-in. liner was run across the reservoir, and it was suspended for later re-entry and test. The total time from spud to move off location was 32 days. The rig was moved south of the islands to drill a well for a third operator before returning to the NFB to drill the Rockhopper Ernest 26/6-1 exploration well.

This interval provided sufficient time to mobilize the basic test equipment, prepare the testing program and get the necessary approvals.

Following the re-entry and testing of the Sea Lion discovery well, a sequence of Desire exploration wells was drilled, including one sidetrack, completing the first period of the rig contract.

With the success of the Sea Lion discovery well, Rockhopper and Desire jointly contracted a two-vessel 3D seismic program to cover the area around the discovery and fill in gaps in the existing seismic data. The survey south of the Sea Lion discovery later revealed the southerly extent of the structure and whether it stretched into the Desire 14/15 license block. The companies decided to fast-track interpretation of the new data to determine the best locations for the program of appraisal wells.

They extended the rig contract, allowing Desire to drill one more exploration well and Rockhopper to carry out an eight-well appraisal drilling program that included a more detailed test on one of the wells. The project terminated in early 2012, with the drilling of the 14/15-4 appraisal well by Rockhopper that proved the southern extension of the Sea Lion sands into the Desire 14/15 license block and revealed additional sand bodies containing hydrocarbons.

On completion of the well, the rig was released and returned to the North Sea after drilling 15 wells, including four sidetracks, and carrying out two well tests.

With experience from the first wells, appraisal well designs were modified. After setting 13 3/8-in. casing, hole conditions and leak-off tests were good enough to continue drilling 12 ¼-in. hole to TD. (Figure 4). In the later wells, the extent of prospective pay zones was identified by first drilling vertically to TD and logging before plugging back and sidetracking to take cores across the reservoir interval.

There were very little nonproductive time (NPT) or waiting on weather (WOW), with averages of 9.4% and 5.8%, respectively, throughout the two-year drilling campaign (Figures 5a and 5b). NPT was mainly attributed to wellhead problems, one stuck casing event and the loss of rig power on one occasion. Most WOW was attributed to weather interrupting running or pulling the BOP stack and riser or delaying anchor handling when moving location. BOP and riser handling were affected both by rough seas and by flat calm conditions, which were generally accompanied by thick fog that prevented the standby vessel from approaching the rig.

When the extent of the Sea Lion discovery well was realized, steps were taken to enable the well to be tested. A standard North Sea subsea testing package and tubing string were assembled and shipped from Aberdeen to arrive on location before the end of the Rockhopper Ernest exploration well, a window of approximately three months. Well test planning meetings were convened to discuss the test and the information to be gathered. These meetings were attended by reservoir engineering and well test consultants, Rockhopper operations advisers and AGR testing engineers, who would compile the detailed well test program and procedures.

The reservoir samples recovered from the discovery well revealed that the crude oil was waxy and had a pour point around 68°C. This had the potential to create problems in the low ambient temperature environment surrounding the riser and wellhead, where the water temperature at the seabed had been measured at 4°C, and for some distance below the wellhead. An interruption of flow during the test would result in a tubing string plugged with solidified waxy crude oil.

To counter this eventuality, a restricted test procedure was evolved that would provide the minimum reservoir data required with a short flow period, sufficient to bring reservoir fluids to surface under controlled conditions. Provision was also made for solvent chemicals to be injected into the subsea test tree within the BOP stack if necessary. The basic nature of the testing string made chemical injection anywhere below the tree impossible.

The rig moved back onto the 14/10-2 location in September 2010 and re-entered and cleaned out the suspended discovery well. From the logging data, there appeared to be two separate zones in the reservoir with slightly different pressure gradients (Figure 6). However, because of the restrictions posed by the testing equipment, it was only possible to carry out one test, combining flow from both zones and the tubing-conveyed perforating guns on the test string were spaced out accordingly. After the test string had been set and the perforating guns activated, a 300-bbl cushion of diesel oil was injected into the formation and shut in to heat up over a period of 12 hours before being back-flowed to stimulate the well at the start of the test.

A successful but limited test was carried out with sufficient flow to surface to measure the well parameters needed and collect samples of reservoir crude oil and gas. As soon as the flow was stopped, the contents of the tubing were reversed out to avoid any build-up of wax, and the well was killed.

When the test string was recovered, it revealed that the perforating guns across the lower zone had not fired and all the flow (approximately 2,000 bbl/day) had come from the upper zone. On completion of the test, the well was plugged and abandoned.

In June 2011, a second well test was carried out on the 14/10-5 Sea Lion appraisal well. To make it as comprehensive and representative as possible of production conditions, a fully engineered test package was assembled to mitigate the combined effects of the waxy crude oil and low ambient temperatures. By using an electric submersible pump set approximately 200 meters above the 7-in. liner top on a combination 5 ½-in. by 4 ½-in./4 ½-in. by 3 ½-in. vacuum-insulated tubing string, heat loss could be minimized and the test period safely extended.

The surface equipment was also upgraded and trace heating of pipework installed from the rig floor to the test equipment to help maintain flow. The test was successful, yielding a flow rate of 5,500 bbl/day under controlled conditions and approximately 9,000 bbl/day under open flow and maximum pump rate. On completion of the test, the well was abandoned and the testing spread returned to Aberdeen. Reservoir data was successfully acquired from the subsequent appraisal wells by the more economic combination of extensive coring in the reservoir and mini open-hole drill stem tests using the MDT dual packer wireline testing tool.

In the drilling program prepared for every NFB well was a statement that the principle objective was “to design, drill and evaluate the well to ensure zero LTAs and zero spills or releases during the well construction process.” With the operation being located in a remote area, attention to safety was critical. To ensure a consistent approach to operational safety when conducting a drilling program for two operators and switching between them while using the same personnel, a safety management system was adopted that ensured continuity of responsibility.

During drilling operations:

• The Diamond Offshore Drilling safety management system was followed when controlling activities on the drilling rig;

• The AGR management system was used to control preparation of the drilling and testing programs and to manage supervision of the work both onshore and offshore; and

• Diamond Offshore Drilling implemented the safety case for the Ocean Guardian as accepted and approved by the UK Health and Safety Executive.

In addition, AGR developed a management system interface document (MSID) to clarify the relationship between the operator (Desire or Rockhopper), the drilling contractor (Diamond Offshore) and the project management company (AGR) during drilling operations in the NFB. The MSID was agreed on and authorized by all parties and

• Set out and agreed environmental, health and safety arrangements to be applied during NFB offshore drilling operations;

• Ensured management and communication channels (both offshore and onshore) were established;

• Identified arrangements for emergency response;

• Identified how changes to procedures or work would be controlled under management of change; and

• Ensured full compliance with all statutory requirements was understood and followed.

During the drilling campaign, the Diamond Offshore well control manual was the primary source for well control issues other than where exceptions were specifically mentioned within the MSID.

The drilling contractor, with full support from the two operating companies and AGR, achieved a highly creditable record and standard of safety. This included an effective safety card system that encouraged all members of the crew to recognize both good and bad safety practices. By the end of the operation, some 7,748 cards had been submitted; 5,037 desirable and 2,711 undesirable, which promoted changes to working procedures and improvements to safety equipment. This resulted in only one lost-time incident (LTI) and one restricted day case throughout the campaign.

At the onshore supply base, an industry standard safety culture was introduced and training implemented for personnel with no oil industry experience. During more than two years of operations involving 822,159 manhours worked, only 107 incidents were recorded with two LTIs.

Figure 6: Logging data from Sea Lion 14/10-2 showed two separate zones in the reservoir with different pressure gradients.

When the Ocean Guardian departed Invergordon for the South Atlantic, it did so with the prospect of less than a year’s work, drilling only four wells for one operator. By the time it arrived on its first location, a second operator had joined the program, and two wells had been added to the schedule. Just over two years later, it returned north having successfully completed an evolving program of exploration and appraisal wells, including two unique well tests. This was made possible by the project management model adopted by the operators.

Neither Desire nor Rockhopper employed significant staff, particularly those with experience in offshore drilling or exploration drilling operations. Instead, they relied on a drilling project management company to provide the services normally associated with the in-house drilling, logistics, contracts, purchasing and well accounting departments of a major oil company. This service has evolved to meet the requirements of small exploration companies that have emerged in the industry. Common contracts for services and for the rig were also agreed by the operators, which allowed responsibility to pass seamlessly between them from well to well.

The relatively benign subsurface drilling conditions across the NFB also allowed a similar well design to be adopted for all wells, simplifying the supply and stocking of well consumables. Although the supply chain stretched back to Aberdeen, this posed no problems as consumable materials and service company equipment could be sourced and checked before shipment to Stanley.

Although it may have been possible to source some materials closer to the NFB, long-term rentals and bulk shipments from Europe were deemed to be cost effective and more reliable.

With modern communication systems, contact among the rig, the operations base and the management centers in the UK was easily maintained with continuous and up-to-date well data from the rig. However, despite this ease of contact, the previously agreed lines of communication established under the AGR management system were maintained throughout the campaign.

The similarity of legislation at the Falkland Islands with that of the UK also helped but could not be taken for granted. Maintaining local contact ensured that local requirements were understood. Having a Rockhopper representative in Stanley proved effective.

The successful two-year drilling campaign in the South Atlantic demonstrated the viability of conducting a remote operation without the necessity of setting up a large-scale local base or of locating large numbers of support personnel in the area. The model developed in this case was fit for purpose and could be repeated in the future.

For author acknowledgments and additional images/graphs from this project, please visit www.DrillingContractor.org.

SPE/IADC 163415, “Exploration and Appraisal Drilling Operations in the South Atlantic,” was presented at the 2013 SPE/IADC Drilling Conference and Exhibition, 5-7 March, Amsterdam.

Ultradril is a trademark of Schlumberger/M-I SWACO.

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Honghua developing new-generation shale-drilling rig, plans testing of frac pump

By Katherine Scott, associate editor

Zhang Mi, chairman and president of Honghua Group, spoke with Drilling Contractor at the 2013 OTC. He noted that while his company’s current focus is on the US onshore market, he believes Honghua can eventually deploy the same technologies in China once unconventionals development expands in that country.

Honghua Group and its US subsidiary Honghua America are developing a next-generation onshore rig for shale drilling called the US #1; a prototype is under construction at the company’s Houston factory and scheduled for completion in late 2013 or early 2014. Further, the company is working with Baker Hughes to field test Honghua’s 6,000-hp hydraulic fracturing pump in Texas. Speaking during an exclusive interview with Drilling Contractor at the 2013 OTC, Zhang Mi, chairman and president of Honghua Group, noted that such technologies are examples of his company’s focus on the US onshore market; yet, they are also technologies that he believes Honghua can eventually deploy in China once development of unconventionals expands in that country.

The US #1 rig has been designed to be highly mechanized and highly automated, Mr Zhang explained, and one technology that will be incorporated is Honghua’s new direct-drive triplex mud pump. The pump is driven by a top-mounted AC motor that powers the pinion shaft. This removes the intermediate transmission (e.g. belt, chain and gear), reducing maintenance and vibrations and lowering noise.  A smaller environmental footprint is another key feature of the US #1 rig. Mr Zhang noted that it has been designed to be powered with natural gas and LNG, and perhaps even grid power in some cases. “If (US #1 is) successful, it will be an example for Honghua’s next-generation rigs.”

The company also continues work on its 6,000-hp frac pump, introduced at last year’s OTC. Honghua is now working with Baker Hughes to bring this technology to the US market for field-testing, Mr Zhang said. “Once the field tests are complete, I believe it will also bring about step-changes for shale drilling in the US.” Field-testing will likely take place in Texas around August, he said.

Honghua Group’s triplex direct-drive pump, exhibited at the 2013 OTC, reduces maintenance, increases service life and reduces noise emissions and vibrations. The pump will be integrated into Honghua’s next-generation rig, the US #1.

Looking toward the Chinese market, Mr Zhang explained that although there are approximately 2,000 land drilling rigs operating in China, most of them are older mechanical or SCR-style rigs. “There is a significant need for renewal of the fleet,” he said, adding that he believes innovations such as Honghua’s direct-drive triplex pump will be able to impact the Chinese market once it’s proven in the US. “The locations in China where there’s potential for shale gas are not like Texas, where you have wide spaces where you can build wellsites. In China, they are located in mountainous regions, so access to shale gas reserves is more difficult. Being able to reduce the footprint is especially important.”

Although onshore rigs and technology remain at the core of Honghua’s business, the company is also pushing ahead with its entry into the offshore rig construction segment, with the large-capacity Honghai mobile crane the centerpiece technology driving their efforts. “When our Honghai crane is completed with a lifting capacity of 22,000 metric tons, you can construct the entire platform on land and then transport it offshore as a complete piece… We believe this will be a first in the world,” Mr Zhang said.

Construction of the crane began in October 2012 near Shanghai. Once completed, Honghua plans to use it for large-scale and simultaneous production of five to 10 offshore rigs, he said. The crane will be completed by the end of 2013 or Q1 2014, and Mr Zhang noted that discussions for offshore rig orders are ongoing, primarily with non-Chinese companies.

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