Depth perception

Need for efficiency drives shift toward standardized, automated subsea completion systems, faster product cycles

By Katie Mazerov, contributing editor

FMC Technologies’ through tubing rotary drilling intervention system enables efficient drilling, intervention and completion work on wells through existing subsea completion systems.

The business of finding and producing oil and gas is all about safe and responsible recovery, reliability and return on investment. Nowhere is that mission more important than the world of subsea completions. Today’s subsea completion operations are being ratcheted up a notch to meet another mandate: efficiency. What 20 years ago took 40 or more days from a fixed platform, with multiple trips, using wireline, coiled tubing, tractors and mechanical tools, is now being done in less than half the time using remotely operated tools, automated equipment and new wellhead designs. The vision is having systems that can operate on the seabed floor, eliminating the need for platforms.

To achieve this, operators and service companies are joining forces in a new level of collaboration and upfront planning. High-end solutions for both new and mature fields are hitting the marketplace in record time, bringing greater efficiency and safety to production in wells that are longer, deeper, hotter, more pressurized and more diverse than ever.

“The outlook for the subsea sector is good,” said Tassos Vlassopoulos, marketing director, subsea systems, for GE Oil & Gas, a global provider of advanced production technologies and services. “According to recent analyst data, orders for subsea trees are expected to grow an impressive 25% this year versus 2012.”

Africa is growing in importance, while investments in Brazil, Australasia, the Gulf of Mexico (GOM) and the North Sea are continuing with varying degrees of intensity, he noted. “Key industry challenges include insufficient engineering capacity to satisfy industry demand and technology development to open up the next frontiers of our industry, for example, power and processing. Furthermore, operators are looking to the supply chain to provide wellheads and production equipment that can reliably withstand increasing depths and pressure requirements.”

GE Oil and Gas is seeing an uptick in orders for subsea trees. Analysts data indicate that overall orders for subsea trees are expected to grow by 25% this year versus 2012, according to GE.

GE is making a number of large-scale investments, developing subsea equipment rated to 20,000-psi yield and enhancing the loading capacity of the subsea wellhead range to support increased casing loading and fatigue requirements. “We have a structured portfolio, but we are completing the ‘family’ with a deepwater vertical completion variant to help our customers push the boundaries of what is technically possible in terms of field development,” Mr Vlassopoulos said.

In addition to the extensive green-field opportunity in Africa, Australia, Brazil and the North Sea, GE is placing focus on brownfield extensions. “GE is in the final execution phase of a significant brownfield extension for a North Sea operator,” he said. “There is also increasing acknowledgment of the low recovery rates for subsea fields, which operators are addressing with targeted oil recovery programs.”

The need for greater efficiency and cost-effectiveness is driving a shift toward standardized equipment that will lead to improved cycle times, reduced complexity and greater consistency of field procedures, he added. Innovation is also occurring in the subsea processing field to locate equipment, such as multi-phase pumps and compressors normally found on the platform, onto the seabed floor. “An increasing number of field developments will only be economical with the application of subsea processing technologies,” Mr Vlassopoulos noted.

Safety is also a key driver of innovation. “Redundancy has always been a feature of subsea equipment, and we are now seeing even more emphasis and layering in this area per recent safety guidelines,” he said. “Well construction has evolved to include additional risk mitigation steps, with more safety factors, redundancy during drilling and additional casing strings and loads applied to the wellhead system.”

Tiny radio frequency identification device (RFID) tags are being used to actuate downhole tools for subsea completions. Weatherford’s RFID platform can open and close sliding sleeves and barrier valves and set production packers.

Despite the high degree of innovation, technology adoption has been and will remain cautious, Mr Vlassopoulos indicated. In addition to equipment for higher pressures and subsea processing, subsea control equipment needs the capability to process increasing amounts of reservoir and well data, while the service sector finds better ways to optimize equipment performance and ultimate recovery.

New subsea completion tools and technologies also come with a high price tag. Increasingly, however, the endgame is not the cost of the actual equipment but the cost of overall operation. “The economics have totally skewed to reducing the time spent completing wells, which drives a greater level of sophistication in the technology,” said Paul Day, global director of business development, well completions technology, for Weatherford. “Reliability is absolutely key because the equipment in these wells has to work the first time and also work for the life of the well. To that end, we’re finding that the level of operator engagement in the design, development and testing of equipment has grown 10-fold over the last five to 10 years to ensure the integrity of the equipment being installed.”

Whereas in the past, rig costs and actual drilling accounted for the biggest portion of a well construction budget, the current focus is on investing in completion equipment to reduce installation time and eliminate the need for intervention, even on the simplest of operations. Proper completion design and installation can shave millions off of the well construction cost.

“For example, we’ve developed tools that allow us to plug a well without any intervention,” Mr Day said. “Previously, we would have run a well plug downhole on wireline, an operation that would have taken eight to 10 hours, using a rig at a (spread) rate of approximately $1 million to $2 million per day. That $10,000 or $15,000 plug would have cost upwards of $500,000 to install. So it makes commercial sense to use a remotely operated tool that may cost 10 times the cost of the wireline but can save $350,000 to $500,000 in overall well costs.”

Through focused collaboration, operators and service companies are designing and developing tools for specific challenges and bringing those tools to market in a matter of months, a process that 20 years ago would have taken at least two years, Mr Day noted. For a 10-well injector program for a major operator off the coast of Angola, Weatherford deployed a sophisticated open-hole packer, allowing a one-trip sand face completion, cutting days off the completion time and saving the customer $300 million over the 10-well program.

FMC Technologies’ riserless light well intervention technology enables intervention operations to be conducted on existing subsea wells, resulting in additional production volumes from mature subsea fields.

The same operator, for another project in Norway, deployed an advanced water and gas injector, nine open-hole packers and 27 remote sand face tools. The net well savings was estimated at between $10 million to $15 million. A further deployment is planned for this year, with six more to follow. “A great well” as described by the operator provides a foretaste of further advances to come, Mr Day said.

Weatherford is also active in the GOM, which presents a number of completion challenges. “As we look at completing the GOM, technologies that provide improvement in operational reliability, flexibility and cost, and which mitigate risk, are critical,” said Yvonne McAnally, product line director, upper completions, for Weatherford. “For the GOM’s Lower Tertiary, industry doesn’t yet have the tools to develop the more difficult reservoirs, where bottomhole temperatures are more than 30,000 psi. That will drive us to develop new solutions; operators are already asking for equipment that is rated above 15,000 psi and 350°F.”

The company’s new radio-frequency identification (RFID) platform uses tags to actuate downhole tools, such as opening and closing sliding sleeves and barrier valves and set production packers, Ms McAnally said. The RFID-based Keystone platform is a tubing-mounted control module that uses remotely operated tags to actuate multiple tools in the well, significantly reducing  trip time. “We’re trying to automate the process and avoid the need for intervention.”

The RFID device tells tools to do things that previously required the use of intervention services, such as wireline and coiled tubing. “We’re developing smarter systems,” Mr Day said. “We’re trying to maintain the same level of reliability we had 20 years ago with simple mechanical tools – and so, far, we’re achieving that goal.”

FMC Technologies also is optimistic about the future of subsea production systems, anticipating a growing  new development market and the need to increase recovery from older fields. “There is a significant backlog of new fields to be developed in all regions, and many of the long-producing existing fields are adding satellite fields and systems to support infrastructures already in place,” said Tore Halvorsen, FMC Technologies senior vice president, subsea technologies.

A second trend centers on the service side of subsea completions, driven by the need for increased recovery, maintenance and upgrades of older fields. Many operators have launched dedicated programs to increase uptime of older fields, introduce upgrades to more modern technology and life-extension programs, he noted.

The company also is seeing a push for efficiency, reflecting the increase of marginal fields. “Innovation comes through the need for improved efficiencies and reduced costs,” Mr Halvorsen said. “The practice of running trees on a wire from a small vessel is an example where cost efficiency led to riserless light well intervention systems, moving non-drilling activities off the rig to a mono-hull vessel.

Two Oceaneering Millennium remotely operated vehicles in the Gulf of Mexico are used for maintenance work for a tension leg production platform, the Olympic Intervention IV, which was chartered since it was built in 2008 by Oceaneering.

Among’s FMC Technologies recently launched offerings are a landing string that is a subsea test tree for cleanup and well testing and a non-penetrating annulus-monitoring system to detect pressure buildup outside the main production casing. “We also are developing all-electric systems on the seabed, replacing hydraulic systems with electric actuators, primarily for manifolds but also for subsea trees,” Mr  Halvorsen said.

Challenging subsea reservoirs also are forcing operators to rethink their requirements for wellhead systems. “Larger, taller and heavier blowout preventers (BOPs) connected to the wellbore on top of the tree impose more force to wellhead systems,” he explained. “In the old days, reservoirs were shallow, and we drilled straight down and stayed on the wellhead for a few days, with hardly any workover activity required. Now, with long horizontals, ultra-deep wells and the large number of workovers, we have to think differently about how we design the wellhead system, which becomes the anchor point for all activity. We are seeing a clear shift from conventional wellhead systems to rigid lock systems, where the wellhead is rigidly connected to the conductor to better transfer bending load.”

In addition, FMC Technologies has developed a reactive flex joint, a device that can be bolted on top of the BOP to neutralize bending of the wellhead. When the rig moves, the device sets up a negative bending action to minimize the loading on the wellhead itself. It has been tested and is in the application phase.

For the growing HPHT market, the company has introduced a 20,000-psi wellhead. However, as operators consider 25,000-psi and even 30,000-psi wellheads, it is clear the HPHT sector has yet to be fully developed. Particularly on the temperature side, challenges remain, Mr Halvorsen believes. “The BOP drilling business has been elastomeric-based, and that won’t be adequate for ultra-high-temperature fields.”

For ultra-deep wells, “everything from the hang-off shoulders in the wellhead to the casing threads must be reviewed to see how deep it is possible to go,” he added. “Add a salt layer to the equation, and collapsed pressure also becomes an issue with ultra-deep wells.”

Down the road, Mr Halvorsen believes there will be more focus on increased recovery techniques. “The idea of producing 30% of the reservoir and leaving 70% behind won’t be acceptable,” he said. The longer-term vision is to do everything on the seabed floor, eliminating the need for platforms. “Robotics and condition-based monitoring will play a key role in maintenance on the seabed, where prediction of maintenance will be essential for quick replacement of modules. This will be especially true in extreme environments, such as the Arctic, where operators will have to access fields beneath heavy ice caps.”

A key aspect of the industry’s ability to go into deeper and more challenging reservoirs has been the remotely operated vehicle (ROV) that, when outfitted with the appropriate tools, can perform tasks that promote safety, asset integrity and reduce costs by providing completion support to ensure reliable production through the life of the well.

“The ROV has been a great enabler of the deepwater boom that the industry is engaged in right now,” said Clyde Hewlett, senior vice president, subsea projects for Oceaneering International, a global provider of ROVs, specialty subsea hardware, installation services, asset integrity management and other services, with a focus on deepwater applications. “At the end of the day, the only way to really know what is happening under water is with an ROV.” Since it was first introduced as an experimental technology in the 1970s, the ROV has evolved into a necessary tool for delivering vision and stereo for depth perception, manipulating large objects, clearing debris, deploying sophisticated telemetry and other subsea tasks.

“We’re increasingly seeing two ROVs on a rig to provide redundancy and to perform specialty tasks, such as those associated with the BOP,” Mr Hewlett said. “For example, if control is lost in the normal remote-control BOP operation, the backup ROV can be used as a secondary means of keeping the BOP running according to specifications, so operations can proceed.  Otherwise, the operator might have to pull the BOP.” A second ROV also can be used for more general purpose work, such as checking the wellhead or surveying the riser.

One of the ROV’s most important functions is enabling remediation services when there is a problem after the well has been completed. Flowline remediation tools, for example, can address issues such as hydrates, which are common in deepwater environments due to the cold temperatures at depth. “Gaseous hydrocarbons in the presence of water turn into ice, or hydrates,” Mr Hewlett said. “An ROV with a suite of hydrate remediation tools, such as hydrate skids, can disassociate the hydrates and open up the flowline to re-establish production.”

Such services increasingly are being provided from separate vessels, often at a fraction of the cost of a deepwater drilling rig. “One of our objectives is keeping the rig doing what it does best, drilling and completing the well, while doing other work from smaller vessels using ROVs and specialty tools.”

Another important consideration in the subsea sector is making equipment capable of operating at water depths of 10,000  ft or more. In that regard, Oceaneering provides installation workover control systems (IWOCS) during the final phase of a downhole completion to perform such tasks as landing the tubing hanger. “We can run IWOCS off the side of the rig, away from the drill center, so activities can be done in ‘hidden time,’ outside the critical path,” he explained.

Asset integrity, the assurance that equipment is functioning properly, efficiently and safely is an area that will grow for subsea fields, Mr Hewlett believes. “Just because we can’t see the equipment, we know it’s there, and we need to know that the integrity of those tools is good,“ he said. “As industry continues to push into ultra-deepwater environments, one of the next big challenges will be to demonstrate that the tree, the manifolds, flowlines, umbilicals and other equipment can be inspected and monitored in such a way that every stakeholder has the assurance those assets have integrity.”

Keystone is a trademarked term of Weatherford.

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DEPA Privatization Process Provides More Suspense

The privatization process of DEPA has met a further delay.  Privatization of Greek public gas company, which should have concluded the binding offer submission process by mid-December, has taken another postponement by the Greek agency for privatizations (TAIPED) without any official explanation.

Unofficially, pundits in Greece cite the political complications on EU regulations that this privatization has ensured due to the speculated offer by Gazprom which outstrips the competition by far, although the particulars of offers have yet to be made public.

An interesting aspect that came about recently is the intention of Sintez Group which participates through its subsidiary Negusmeft, to acquire a larger role than previously thought. Although it was seen as an outsider when compared to Gazprom, SOCAR or the Greece’s M & M Gas, Sintez’s CEO Andrei Korolev relayed to the press that his company has serious intentions and strives to be a winner.

Sintez-Negusneft is a holding of the Russian multi-billionaire Alexander Lebedev, who has a wide range of activities, especially in UK and Russia. According to the company, Sintez wants to make DEPA a global gas player, while Gazprom’s and SOCAR’s intentions as Korolev put it, will be to just monopolize the local market.

Moreover, Korolev stated that his company has a distinct advantage, which is the intention to buy both DEPA and the subsidiary DESFA which is the gas network manager. He estimates that ultimately Gazprom and SOCAR as well will fail to acquire DESFA due to EU rules of competition, thus their efforts would not constitute a full-fledged privatization process.

Another interesting aspect from Sintez point of view, is the belief that SOCAR may eventually ally with M&M gas, an assumption quite interesting judging by the fact that one of the shareholders of the Greek company, the Vardinoyannis family has developed over the years cordial relations with the leadership of Azerbaijan and the Aliyev Presidency in particular, a fact not well-knownintendified by Natural Gas Europe a few weeks ago.

That points out that the Sintez group has developed its business intelligence tactics to “feel out” the competition before venturing at the last moment to become a favorite. It’s not by coincidence that British media have talked about Alexander Lebedev’s past as a high -ranking KGB officer in London in the 1980's, whilst over the past few years he has been in a sort of a conflict with the Kremlin and Putin’s presidency. Therefore Sintez-Negusneft stance in the Greek privatization surely clashed with that of Gazprom and has a Russian political flavor as well.

Sintez’s CEO Korolev also noted on the capabilities of his company to assist DEPA into interconnecting its network with that of neighboring countries and also to expand into LNG trade. By that DEPA could become a sort of a global player and a hub for the gas commodity. At that point it is also interesting to note that Sintez operates electricity power stations in Russia and in the Balkans of 2,800 MW capacity, and gets its gas from Gazprom and in favorable terms, presenting another view of the complicated relations between the two gas companies.

In respect to DEPA’s privatization, Gazprom that came first as a favorite keeps a low profile, along with SOCAR which seems to prefer an overall delay of the competition so as to coincide with the early 2013 announcement of the Southern Corridor for the transfer of Azeri gas to Europe. In case Trans-Adriatic pipeline is selected, that will surely elevate Baku’s interest for Greece, since the pipeline would run from there to the EU.

Lastly the Greek M&M is elevating its lobbying activities within the Greek government and media world, although it has to battles the growing unpopularity of the leading Greek business families, a role which was negatively described in certain high-level reports by Reuters andStern magazine recently. Suspicion-wary Greek experts believed these attacks were related to DEPA’s privatization and aimed against the shareholders of M&M Company.

Moreover, the competition of all these companies has gripped the attention of the Athens-based diplomatic community of most major EU countries and USA which consult on a regular basis local media and politicians in order to examine what lies ahead for DEPA and how the interests of their own country conform or not with the strategies of the players involved. Up to date according to all available and reliable information, German diplomacy seems neutral in the competition , while the American is adamant in accepting a leading role for Gazprom in Greece, citing fears of geopolitical nature. Other European countries such as Italy are in favor of both Russian and Azeri gas, due to the importance of Greece as a traverse point for the commodity to the Italian market.

Neighboring countries such as Bulgaria, Serbia, seem to be favoring Gazprom either due to political reasons or due to South Stream’s project evolution prospects. Lastly the EU’s Commission seems to be divided between the Energy directory and the Competition one, in a period where crucial negotiations are underway with the main EU’s supplier, Gazprom.

In overall, judging by the reluctance of the Greek state to proceed with the privatization of DEPA, it is likely that until binding offers are concluded, upturns and surprising alliances could not be excluded. Sintez latest appearance indicates that this competition may not have a definite outcome.

Cited from http://www.naturalgaseurope.com/

May 2013

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Cuadrilla Says Research Shows Public Coming Around to Blackpool Fracking

Cuadrilla Resources, the company pioneering shale gas extraction in Britain, says the results of research it commissioned show that public opinion is shifting towards its work.

A survey by research company BritainThinks reveals that local residents in Fylde, Blackpool and West Lancashire are feeling more knowledgeable about shale gas, and more supportive of continued exploration in their local area to understand the potential for shale gas in the UK.

After a moratorium, the British government announced recently that shale gas extraction involving hydraulic fracturing could go ahead, under strict regulations. Fracking at a site operated by Cuadrilla was stopped last year after minor earthquakes occurred in the area.

Cuadrilla Resources commissioned BritainThinks to conduct 500 telephone interviews with people living in three areas. It said the purpose of the survey was to understand attitudes about shale gas in the context of recent announcements.

Francis Egan, the company’s chief executive, commented: “Clearly the more people hear about and talk about shale gas in Lancashire the more informed they are about the potential advantages it can bring, as well as the environmental considerations that need to be managed.

“A well-informed community can have the constructive public discourse this industry needs to be successful in the UK.”

Cited from http://www.naturalgaseurope.com/

May 2013

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Natural gas futures plunge to 3-month low on warm January weather

Natural gas futures fell more than 3% on Wednesday to trade at a three-month low, as forecasts showing warmer-than-normal weather across most parts of the U.S. in January weighed on sentiment.

Natural gas prices have closely tracked weather forecasts in recent weeks, as traders try to gauge the impact of shifting forecasts on winter heating demand.

On the New York Mercantile Exchange, natural gas futures for delivery in February traded at USD3.228 per million British thermal units during U.S. morning trade, down 3.65% on the day.

It earlier fell by as much as 4.5% to trade at a session low of USD3.190 per million British thermal units, the weakest level since September 26.

Updated weather forecasts released Tuesday showed that warmer-than-normal weather was expected across key parts of the U.S. during the first two weeks of January, dampening sentiment on the heating fuel.

The U.S. National Weather Service’s six-to-10 outlook called for above-normal temperatures for a little more than the eastern half of the nation, with below-normal readings in the West.

Bearish speculators are betting on the mild weather reducing winter demand for the heating fuel. The heating season from November through March is the peak demand period for U.S. gas consumption.

Meanwhile, investors remained concerned over bloated U.S. inventory levels. Total U.S. natural gas stockpiles stood at 3.652 trillion cubic feet as of last week, 2.5% higher than last year at this time and 13% above the five-year average.

Early withdrawal estimates for this week’s storage data range from 100 billion cubic feet to 141 billion cubic feet.

Inventories fell by 77 billion cubic feet in the same week a year earlier, while the five-year average change for the week is a decline of 111 billion cubic feet.

The EIA report will be released on Friday, a day later than usual due to the New Year holiday.

Elsewhere on the NYMEX, light sweet crude oil futures for delivery in February rallied 1.85% to trade at USD93.51 a barrel, while heating oil for February delivery rose 0.85% to trade at USD3.056 per gallon.

Cited from http://www.investing.com/news/

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Natural gas plummets as forecasts point to warmer weather

Natural gas futures tanked on Monday after meteorologists tweaked their forecasts for the next two weeks to the warmer side.

On the New York Mercantile Exchange, natural gas futures for delivery in February traded at USD3.374 per million British thermal units, down 2.72%.

Recent forecasts calling for cold weather to return in January moderated somewhat Monday.

Weather service provider MDA Weather said that it expected temperatures to warm up in the coming days through the second week of January.

Natural gas futures are very sensitive to weather reports in the U.S. winter.

The heating season from November through March sees peak demand for U.S. gas.

About half of U.S. households use gas for heating purposes, according to Energy Department data.

Meanwhile, U.S. natural gas storage fell less than expected in the week before last, official data revealed on Friday, though weather forecasts served as the market’s chief weather vane.

In a report, the Energy Information Administration said that U.S. natural gas storage fell by 72 billion cubic feet last week to 3.652 trillion cubic feet, less than a decline of 82 billion cubic feet in the preceding week.

Analysts had expected U.S. natural gas storage to fall 76 billion cubic feet last week, though markets focused more on weather forecasts

Elsewhere on the NYMEX, light sweet crude oil futures for delivery in February were up 0.83% and trading at USD91.55 a barrel, while heating oil for February delivery were up 0.41% and trading at USD3.0337 per gallon.

Cited from http://www.investing.com/news/

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Russia Touts Unconventional Gas Promise

Russia may have 2 1/2 times more unconventional gas resources than conventional supplies, according to OAO Gazprom.

The country may hold as much as 680 trillion cubic meters of unconventional resources, which include gas from shale, sandstones and coal beds, Viktor Skorobogatov, director of the gas resources center at Gazprom’s VNIIGAZ research unit, said in an interview in the company’s corporate magazine.

“No country in the world can compete with Russia in terms of the volume of natural-gas reserves and its vast resource potential in both traditional and unconventional,” commented Skorobogatov. Russia’s conventional gas resources total at least 250 trillion cubic meters, out of a global total of 600 trillion to 650 trillion cubic meters, he said.

The holder of the world’s biggest natural-gas reserves, Russia has concentrated on conventional gas production.  However, that focus saw the nation overtaken by the U.S. as No. 1 gas producer in 2009, as advances in technology made shale drilling economically feasible in North America.

Gazprom and Russian officials had originally downplayed the prospects and impact of the unconventional gas “revolution”.  However, President Vladimir Putin shifted course this past April, urging Russian energy producers to “rise to the challenge” of a changing market.  With Putin’s acknowledgment of the impact of shale-gas production, Russia says it is now “actively studying,” the hydraulic fracturing process.

Russia’s shale-gas resources are estimated at about 5 trillion to 20 trillion cubic meters, Skorobogatov said. Hydrates account for about 75 percent of all the nation’s unconventional resources, or 500 trillion cubic meters, followed by tight gas at 110 trillion cubic meters and coal-bed methane at 50 trillion cubic meters, he said.

As much as 90 percent of Russia’s unconventional resources are located in the east, mainly in the Urals and Siberia, according to Skorobogatov. Coal-bed methane and tight-gas ventures, already under development as pilot projects, may start producing after 2020, while development of hydrates and shale won’t start before 2025 or 2030, he said.

Cited from http://www.naturalgaseurope.com/

May 2013

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California’s new oil rush

It remains unclear how quickly fracking could be ramped up in the state, and the geological problems with the Monterey shale are still challenging. But California is definitely not off-limits

California has some of the most stringent environmental regulations in the United States, so it might seem an unlikely place to welcome fracking. On Dec. 18, however, the state Department of Conservation published draft rules that could lead to widespread hydraulic fracturing for oil and gas.

The state is known for tough gasoline standards, an ambitious cap-and-trade scheme to cut carbon emissions and strong interest in developing renewable resources such as wind, solar and geothermal as well as stringent energy efficiency requirements for everything from new buildings to refrigerators.

But it was once the second-largest oil producing state in the union and still ranks fourth behind Texas, North Dakota and Alaska, with output of more than 200 million barrels a year (over 500,000 barrels per day), according to the federal Energy Information Administration (EIA) and state regulators.

Speaking to a conference last year, California Governor Jerry Brown, a Democrat, said he would look into issuing more permits for fracking if it could be done in a safe manner. “I’m an optimist”, that environmental concerns can be resolved, he said. “California is the fourth-largest oil-producing state, and we want to continue that.”

Issuing draft regulation could be a first step towards a big expansion of the practice.

KERN COUNTY

In 2010, California had more than 51,000 active wells – 41,000 of them in Kern County, which accounted for three quarters of total oil production.

Centred on Bakersfield at the south end of California’s Central Valley, Kern is one of the country’s biggest producers of grapes, almonds, carrots and citrus fruit. But it also sits atop five of the state’s oldest and largest oil fields: Midway-Sunset (discovered in 1894), Belridge (1911), Kern River (1899), Cymric (1909) and Elk Hills (1911).

Like the rest of California’s oil industry, Kern has long appeared to be in a state of terminal decline. Statewide output has almost halved since 1985. Production continued to slide even as fracking resulted in sharp increases elsewhere. Output from Kern’s big five fell by 68,000 bpd (17 percent) between 2005 and 2009.

California’s oil is very heavy. Typically it has a specific gravity of less 20 degrees API compared with almost 40 degrees for benchmark West Texas Intermediate.

Most wells are exhausted “strippers”, which now yield less than 10 bpd. Fewer than 300 wells produced more than 100 bpd in 2009.

And California wells produce lots of briny water that must be re-injected or otherwise disposed of safely. The average California well produces eight or nine barrels of undrinkable water for every barrel of crude.

The state long ago had to resort to water flooding (secondary recovery) to maintain output from its aging oil fields. In 2009, California producers injected 1.4 billion barrels of water into oil-bearing formations to drive the remaining crude towards the wells, up from less than 1 billion barrels at the turn of the century.

Much of the oil is so viscous that the state also injected 500 million barrels of hot steam (tertiary recovery) to make it flow better.

Cited from http://business.financialpost.com/

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Gazprom to Buy Majority State in Kyrgyzstan’s Gas Company

Gazprom, Russia’s state-backed energy giant, could buy three-quarters of Kyrgystan’s national gas producer for one dollar, reports say.

Russia’s state-run news agency RIA Novosti reports that Gazprom is examining an offer to buy 75% of Kyrgyzgaz for $1 to help the company settle debts and work toward energy diversity. “The deal to buy Kyrgyzgas would allow Gazprom to start prospecting and developing … two gas deposits,” the report, also carried by UPI and other sources,stated.

Other agencies reported the deal was certain, and would relieve supply worries in the mountainous nation of 5 million, which also borders China.

AP quoted Kyrgyzgaz general director Turgunbek Kulmurzayev saying the sale of the company to the Russian gas giant would be completed by April 1.

At a meeting in Moscow last week, Gazprom CEO Alexei Miller discussed a possible deal with Kyrgyz President Almazbek Atambayev. In a statement, Gazprom said it was interested in future prospects in the oil and natural gas sector in the former Soviet republic.

“The meeting discussed Gazprom’s possible participation in privatization of Kyrgyz oil and gas facilities,” Gazprom said. “Special consideration was given to the company’s entry in the shareholding structure of [natural gas company] Kyrgyzgaz.”

Gazprom said it estimated the proven natural gas reserves in the republic at around 211 billion cubic feet, but said development is hindered by the lack of infrastructure and “geological peculiarities”.

Cited from http://www.naturalgaseurope.com/

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Oil price jumps as U.S. averts “fiscal cliff”

The price of oil rose Wednesday by almost 2 percent before pulling back, as traders cheered a deal in Washington to avert the dreaded “fiscal cliff.”

The House voted near midnight to send the bill to President Barack Obama after a tense day of political brinksmanship on Capitol Hill.

In afternoon trading U.S. benchmark crude for February delivery rose $1.03 to $92.85 a barrel on the New York Mercantile Exchange. It was as high as $93.87 a barrel at one point.

More hurdles are ahead for the U.S. economy, including a new deadline for more spending cuts in two months. Oil analyst Phil Flynn says in the meantime, “ignorance is bliss and this deal should propel oil…near $96 a barrel.”

Brent crude, used to price various kinds of international oil, was up $1.07 to $112.18 a barrel on the ICE Futures exchange in London.

Economists had warned that if Congress did not take action, a series of tax increases and spending cuts due to automatically start this year could have pushed the U.S. into recession. A spike in unemployment and less consumer spending would likely depress energy demand.

Some House Republicans opposed the bill, which drops middle-class tax increases and $24 billion in spending cuts set to take effect, while raising taxes on the wealthy. A majority in the House eventually agreed to a simple yes-or-no vote on the bill, which had already passed the Senate by a wide margin.

In other energy futures trading on the New York Mercantile Exchange:

- Wholesale gasoline rose 4 cents to $2.80 a gallon.

- Heating oil added a penny at $3.05 a gallon.

- Natural gas fell 14 cents to $3.22 per 1,000 cubic feet.

Cited from http://www.cbsnews.com/

May 2013

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Richard Moorman: Notes from the Shale Gas Trenches

The former CEO of Tamboran Resources, Richard Moorman was determined to convince the public in Ireland of the benefits of developing their unconventional gas resources. It was not an easy job, but for months he was on the ground at public forums engaging with locals and answering their questions – a formidable task.

At the end of September this year, Mr. Moorman stepped down as CEO, but remains a technical advisor at Tamboran.

Of the change he comments, “The company’s going in a bit of a different direction. They’re aggressively pursuing a joint venture party for the Australian assets and so the company is essentially going slower in Ireland. It became impossible to keep the pace there.”

Ahead of the European Unconventional Gas Summit, taking place in Vienna, Austria 29-31 January 2013, Mr. Moorman offered Natural Gas Europe his perspectives on shale gas in Europe.

You were on the ground and engaging the public face-to-face in Ireland. How would you assess the public’s mood there today towards the development of unconventional gas?

I think the mood is positive. We have to be careful when we talk about this, because the exploration companies shouldn’t be considered a consumer product – we’re not trying to sell a beverage to a wide spread of people.

We really need to provide a product that meets safety requirements, that provides essential energy – but to say it simply, the typical person on the street probably doesn’t need to be any more for or against natural gas than they are for electricity, for example. It’s just a product that’s a part of life.

The opposition forces tend to try and isolate – shale gas, sometimes even wind, or coal – and those are personal opinions which are very important to them, and part of the process, but it really isn’t the battle for 50% of the public’s support; it’s really about, is this an essential product that’s needed, and then how do we go about making sure that it’s done safely?

So I spent a lot of time considering public opinion in Ireland, mainly because it was so new to Ireland – considering having its own supply of natural gas and the industry that comes with that. But otherwise it’s not really about working to get people to like gas; it is the way it is: almost one quarter of the island’s total energy is powered by natural gas.

Given your experiences in Ireland, how would you assess the overall prospects for the development of unconventional gas in Europe?

The European experience so far has been frustrating.

Certainly Cuadrilla in the UK, sitting on what appears to be a very viable asset, had the misfortune of setting off tremors on their first fracture stimulation and subsequently the report has come out that showed that there were steps they could take to prevent that from happening, but that’s in the record.

In Poland I think it was overemphasized in the beginning – kind of like a land rush – and everybody got out of perspective on it, forgetting how long it took for things to actually succeed in the United States and that new projects require a lot of effort.

Unfortunately, in Poland we’ve seen operators like ExxonMobil drill two wells and then back out. That’s just poor practice. The bottom line is, in the US most of these shale projects took dozens of wells and it’s not realistic to think that someone can solve these problems in a couple of wells.

It’s been disappointing in the sense that some companies exaggerated the ease with which it would come. I think that most of them believed it themselves, because most of those companies didn’t actually have hands-on, self-generated experience in the US. Exxon had acquired companies there such as XTO, but they themselves were not significant unconventional developers.

In Poland, only BNK has real hands-on experience that they’ve brought over from the US, and I think their approach is consistent with the way you need to do these things: you keep working at it. And as long as people are willing to do that, I think that Poland will be successful, the UK play will be successful and I think when the Irish government finally has its rules in place that shale gas will be successful there, too, but unfortunately all these things take time.

There are movements, but it looks uncertain whether the EU will enact regulation specifically for shale gas. Do you think such broader regulation could reassure policymakers?

I say yes, but regulation means different things to me than it does to other people. Some hear that word and they run away from it, because they think it just means ‘red tape’, extra bureaucrats and more forms to be filled.

The kind of regulation I think Europe needs more of with respect to unconventional gas are related to a clear monitoring of what’s going on, a clear presentation of development plans before they are initiated and a clear enforcement procedure for companies that violate their own commitments and the rules that are put out.

It really can’t be useful for people to take risks with water or air contamination. There’s no reason that that has to happen – the technology and the processes are there to prevent all of this. So while the situational occurrences are quite rare in the US, even if one were to say it happens in one in a thousand wells, that’s still one in a thousand too many times and can be prevented.

In Europe a lot more can be done by the regulatory authorities to really try and understand unconventional gas, to make sure that companies declare what they’re going to do upfront, that they are monitored while they’re doing it – that we don’t have any surprises, and finally so that there’s enforcement, because without that there’s no way that the public can trust that the rules mean anything.

Recently an official from OMV was quoted as saying Europe risks its competitiveness by not developing unconventional gas. What are your thoughts regarding that?

I think it’s a fair statement, but I’d probably broaden it to say that at all times, countries are all dependent on energy, and lowering the cost of that energy makes them more competitive; unfortunately, the reality is that the world is continuing to grow aggressively, particularly in Asia and that represents a significant pull on energy and keeps the price of energy rising.

In the US, the shale gas effect has substantially reduced the price of natural gas, going from about USD 14/TCF in 2008 to less than USD 2/TCF within the last year – that’s a substantial savings, and when you get about one quarter of your energy from natural gas, that does make you overall much more competitive as a nation.

Europe’s challenge is that it is ultimately dependent upon imports. Some 40% of their natural gas comes from Russia and the Middle East, and that will only rise over time without shale. Since those prices are guaranteed to be closer to oil-indexed pricing, whereas the US natural gas prices are completely broken from oil prices, then it’s almost a certainty that Europe’s prices will be much higher, making it less competitive.

Does that mean you should spend every penny you can to develop shale gas? No. It still has to be done in perspective, done responsibly. But if your energy costs keep rising and other countries have that under control, then you’re not going to be as competitive. I think western nations are already under pressure from the role of Asia – they can’t afford to have expensive energy.

What would you suggest to the industry in Europe to help push things forward?

First of all, I think the industry needs to do a much better job of communicating what it’s actually doing and intends to do rather than relying on government regulators to provide cover. The reality is, that’s not the government’s business. If we’re working in someone’s community, then it’s our business to make sure that the community knows what we intend to do; the government needs to make sure that we do it, but it’s our responsibility to do that and a lot more.

Several European shale companies do this in their local communities, but it’s not necessarily seen beyond those, and there’s a lot more work that could be done there.

The other thing is, they could do well to stop blanket opposition to any kind of regulation. It seems like the knee-jerk response for every industry when asked for more regulations to protect the public is to oppose them instead of working with the responsible authorities to make sure they’re better for both sides. So I think the industry could do a lot more to cooperate.

One of the challenges is, all these business are competitive and so to a certain extent you have people feeling that they have to hold on to their technologies or their efforts, minimize their spending and participating in all these things can be expensive. That attitude has to change about the public – it needs to be recognized that the public is essential to the success of energy; really in terms of all science, if we don’t start getting more public support for what we’re doing and the chance to understand it – if we don’t do that as a society, we’ll find it increasingly difficult to do those projects that are essential to society. And I think the natural gas industry is no exception to this.

People have taken too long to get shale gas off the ground already to the point that some people believe it won’t happen now. At the same time, it’s so important that we get lower cost and more plentiful energy supplies, especially in Europe for an economic boost.

What are your views on natural gas and competition from subsidized renewables in Europe?

Subsidies are a policy decision and they should reflect what people want. Sometimes people want more than we can afford, so the challenge, I think, for government is to balance a sufficient amount of investment in renewables and subsidization for the future, with the current need to keep energy costs as low as possible, and certainly to keep industries going today that do provide jobs.

That’s a tricky business, and that’s why I’m glad I’m not in politics. Ultimately, governments have to find a balance. I think there’s a lot more work to be done in the renewables space, because we have to be realistic; hydrocarbons will not last forever, they will not keep growing past 100 years, so one way or another we’re going to need more sustainable energy products.

My personal opinion is that today, on average, renewables cannot supply a substantial amount of the energy needed at an affordable cost; a lot more work is needed to prove them up and to keep us going until renewables can take over the load.

Cited from http://www.naturalgaseurope.com/

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Fluxys to Buy Stake in Medgaz

Fluxys SA, the Belgiun-based energy company, says it has reached a €230 million agreement with Spanish companies Endesa and Iberdrola for stakes in Medgaz, owner and operator of the subsea pipeline which brings gas from Algeria into Spain.

In a press statement, Fluxys said it expects to close both transactions in the first half of 2013.  The transaction requires the other shareholders in Medgaz (Sonatrach, Cepsa and GDF SUEZ) not to execute their preferential acquisition rights and the consent of the European Investment Bank, which has granted a loan for building the pipeline.

The deal will make Fluxys a 32% partner in Medgaz for an acquisition price of approximately €233 million. Fluxys’ financial strength is to remain unaffected by the transaction as by the end of 2012 the company will have carried through a capital increase of over €140 million. The capital increase allows Fluxys to maintain a solid equity/debt ratio while continuing its development in Europe.

The Medgaz pipeline was commissioned in April 2011 and can carry 8 billion cubic metres of gas per year. The pipeline is a strategically important link for bringing Algerian gas to Europe.

Cited from http://www.naturalgaseurope.com/

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Can’t keep the offshore industry down

Rig utilization, dayrates continue ascent in vibrant global market

By Katherine Scott, associate editor

Vantage Drilling’s Platinum Explorer drillship is working for ONGC in India on a five-year contract at a dayrate of $590,000. The drillship is equipped to operate in up to 10,000 ft.

The global offshore industry is undeniably enjoying another renaissance. Both the deepwater and jackup segments are benefitting from high utilization and climbing dayrates in almost every market around the world, and few doubt this positive outlook will continue for the foreseeable future. In deepwater, prospects continue to soar as operators and contractors subtly shift focus from exploratory drilling to development drilling – even while a vast amount of untapped deepwater acreage still awaits development. For jackups, which appear to be operating at a historically high point globally, demand is exploding and dayrates have in some cases nearly doubled versus just two years ago.

“The general feeling is it’s still very much vibrant. E&P spending is still rising, perhaps not as fast as last year, but somewhere close to 10% is expected for 2013,” Sven Ziegler, head of offshore research for RS Platou, said. “When it comes to offshore and the rig universe, global utilization is still very high for both jackups and floaters.” As of March, utilization for the worldwide jackup fleet was around 93%, with full utilization for modern units. “And floaters are basically fully booked, so at the moment it’s good for rig owners.”

According to an RS Platou rig report, in 2012, deepwater dayrates in the Gulf of Mexico, South America and Africa spiked in the second half of the year. So far in 2013, deepwater dayrates have reached highs of $423,000 in the Gulf of Mexico, $410,000 in South America and $515,000 in Africa.

RS Platou defines shallow water as up to 400 ft, mid-water from 400 ft to 3,000 ft, deepwater from 3,000 ft to 7,500 ft and ultra-deepwater as deeper than 7,500 ft. Mr Ziegler noted that although the offshore industry is continuously progressing deeper, most ultra-deepwater units today are still operating only in deepwater. “Units that have over 7,500-ft capability are mainly being used between 3,000 and 7,500 ft… Ultra-deepwater is still coming. Once the deepwater discoveries become smaller and less frequent, then companies will move to ultra-deepwater.”

For the wells that are being drilled in deepwater, Mr Ziegler noted that more contractors are turning their focus to development drilling. “Oil companies are likely to reallocate drilling resources (rigs) from exploration to development. If they can’t do that, they have to go into the market and find new ultra-deepwater rigs. At the same time, dayrates in ultra-deepwater have gone up basically 50% to around $600,000 in the last year and a half.”

Opportunities abound not only for drilling contractors but operators as well, with a vast amount of deepwater and ultra-deepwater “virgin territory” remaining in the Gulf of Mexico (GOM), African east and west coasts, Brazil, the Mediterranean, Australia and parts of Asia. “One thing that is certain: Oil companies see the deep and ultra-deepwater discoveries as very attractive investments,” Mr Ziegler said. “At the same time, many of these discoveries that have been made in the last five to 10 years are moving into the development stage now.”

RS Platou’s April rig report charts dayrates for jackups operating in less than 300 ft. The top graph illustrates high dayrates for the past year for modern jackups while the bottom graph charts the lowest rates for jackups built before 1998.

For companies interested in the promises of ultra-deepwater, the focus remains on drillships, Doug Halkett, COO for Vantage Drilling said. “Unless you need a rig for harsh environments, the drillship is definitely the ultra-deepwater rig of choice just because it’s more flexible, you can put more equipment onboard and transit is better. There are not very many semisubmersibles being built, certainly not for international operations.”

A relatively new company, Vantage Drilling became operational in February 2009. “Since we started, I don’t think there have been many other start-up drilling contractors offshore. I think people have learned that it’s not very easy to start an offshore drilling contractor. It takes a lot of money, and it takes a huge amount of effort to build the systems and to get the teams together,” Mr Halkett said.

Vantage Drilling currently owns and manages four jackups and three drillships in different parts of the world, including Thailand, Malaysia, Indonesia, the Ivory Coast, India and the GOM.

A newbuild drillship, the Tungsten Explorer, is expected to be delivered at the end of May in South Korea. It has a contract for an unnamed operator for two years, plus two years of options, commencing in mid-2014 in West Africa. Prior to that contract commencement, Vantage is marketing the rig for short-term “fill in” work. The rig is being built by Daewoo Shipbuilding and Marine Engineering (DSME); it will be capable of drilling wells up to 40,000 ft deep and operating in up to 12,000 ft of water.

Frigstad Engineering recently launched its D90 design. “The D90 has an extremely neat, open, large deck with a focus on rational logistics solutions,” Øystein Bondevik, managing director, said. Frigstad believes the D90 may be the world’s largest ultra-deepwater semi.

Vantage also won a contract last year from Oro Negro, a Mexican drilling contractor, to manage four jackups in Mexico for PEMEX. “We get to expand our operating fleet size without spending our capital,” Mr Halkett said of the contract. “The management business is a little bit trickier, and there are not many drilling contractors interested in that, but we are one of those that are interested.”

New ultra-deepwater rig design, record signal more to come

Frigstad Engineering, a Cyprus-based offshore rig engineering company, recently launched its latest D90 design for a new ultra-deepwater semisubmersible that the company calls the world’s largest. “The D90 has an extremely neat, open, large deck with a focus on rational logistics solutions, which makes it perhaps also the most efficient rig in the world,” Øystein Bondevik, the company’s managing director, said.

Frigstad started with the base of its current design, the recently delivered Scarabeo 9, then scaled it up by approximately 25%. “We worked together with Aker and NOV in order to develop a drilling system that we feel was more efficient than any other existing rigs. We see the trend going towards deeper water and that you’re going to operate for a longer period on your own. It has to be more efficient because you’re further from the shore for the operation, and the rig has to be self-sustaining for a certain period of time,” Mr Bondevik said.

To design the rig, Frigstad took the base of Saipem’s Scarabeo 9, designed by Frigstad, then scaled it up by approximately 25%.

Frigstad Deepwater, a privately owned strand of the Frigstad Group, has already ordered two D90s that  are being built at CIMC Raffles in Yantai, China. The order includes options for four more units. Deliveries are scheduled for Q4 2015 and Q2 2016, respectively.

The D90 will be able to operate in up to 95% of ultra-deepwater basins around the world, Mr Bondevik said, although the current D90 rigs on order will not be prepared for the Arctic. “Right now, most ultra-deepwater rigs are drilling in deepwater and mid-water, so there’s still an untapped demand for ultra-deepwater newbuilds. Plus, most newbuilds are based on an older design, and when they upgrade, it can make the rigs not as efficient,” he said. The two new D90 rigs are built around an NOV Dual Activity Rig with 2 x 1,400 ton lifting capacity and two 7-ram BOPs. They will have the capacity to operate in up to 12,000 ft of water and a 53,000-ft drilling depths, with a vertical racking capacity for 10,100 ft of drilling riser in 106-ft stands and 53,000 ft of drill pipe in quad stands.

Frigstad’s design also took into account the need for more people onboard as contractors bring in further service personnel. “On smaller rigs, it used to 100, then it came to 150. We have accounted for 200 people onboard, which can also be increased.” The rigs will have 200 single beds, each cabin with its own window for crew comfort and safety.

Taking notice of the opportunities present in deeper waters, India’s ONGC set a record earlier this year for drilling a well in the deepest water. The operations were conducted using Transocean’s Dhirubhai Deepwater KG1 (DDKG1) drillship in a water depth of 3,165 meters (10,385 ft). “This is a back-to-back deepwater record for India, as the previous water-depth record was held by rig DDKG2 at 3,107 meters (10,194 ft) in Cauvery Basin, also on the east coast of India. These developments show that Indian operators are very optimistic about the deepwater future in India and is sure to revive the interest of international players in Indian deepwaters,” Shashi Shanker, ONGC director of technology & field services, said. “The ultra-deepwater market has expanded over the initial years in India but is presently at a plateau. However, in coming years, it is expected to boom again.”

Hercules Offshore’s Hercules 266 jackup is drilling offshore Saudi Arabia.

To achieve the deepwater drilling record, the DDKG1 drillship was provided with additional inputs, including mobilization of 2,000 ft of risers and upgrading telemetry cans of the ROV for increased water depths, as well as a risk-sharing model to address issues such as repair of the subsea BOP and its control system at great water depths. The rig, contracted to ONGC until July 2013, was designed for well depths up to 37,500 ft and water depths to 12,000 ft, Mr Shanker said. He added that the record set this year was the 19th well drilled by DDKG1 and that ONGC plans to use the rig to drill more wells in waters beyond 10,000 ft. ONGC also has another ultra-deepwater rig, Vantage Drilling’s Platinum Explorer, on contract until December 2015.

The Hercules 260 jackup is on contract in the Democratic Republic of Congo. Both rigs are capable of drilling in water depths up to 250 ft. The company has seen jackup activity explode, especially outside the Gulf of Mexico.

Although the industry spotlight often shines on ultra-deepwater activities, the strength of the jackup market is also formidable. In the global jackup market, approximately 50 newbuilds are under construction, of which roughly 40 will be delivered in 2013, Greg Lewis, research analyst with Credit Suisse, stated.

Hercules Offshore has seen jackup activity explode, especially outside the GOM. “There’s more jackups working outside the US Gulf of Mexico than there ever has been. We’re at an all-time peak globally; there are 375 jackups working outside the Gulf of Mexico, and you’ve got a global demand in excess of 400 rigs,” John Rynd, president and CEO of Hercules Offshore, said.

New rig orders for the past year, according to RS Platou’s April rig report, has mostly been for premium jackups and ultra-deepwater drillships.

Every major jackup market is short on rigs, he noted. “If you look globally, there are three companies that use the most rigs: PEMEX, Saudi Aramco and ONGC. They will run easily 25% of the world’s jackup fleet, and they all need more rigs,” he said. “The first place you look is what are the demands from the big consumers, because if they’re letting equipment go, that’s going to cause weakness in the markets. But if they’re trying to grow rigs, they’re going to attract rigs and tighten the market up.”

Hercules Offshore currently has 38 rigs in its global fleet. In the Gulf of Mexico (GOM), 19 are under contract (18 operating and one set to enter service in May 2013) and 10 are cold-stacked. Outside the GOM, nine rigs, of which six are on contract, are spread out in Myanmar, Cameroon, Saudi Arabia, Gabon, Bahrain and Malaysia.

Hercules Offshore also has 32% ownership in a new company called Discovery Offshore that was established in 2011. “We’re building two high-capacity, harsh-environment HPHT jackups that can work anywhere in the world except for Norway,” Mr Rynd said of Discovery Offshore. The rigs are under construction at the Keppel FELS yard in Singapore, with deliveries set for June and October of this year. Both will have a 2-million-lb hookload drilling system, 15,000-psi blowout preventer systems and will be capable of operating in water depths up to 400 ft and drilling wells up to 35,000 ft.

“We’re close to securing work for them when they come out of the yard, targeting the Middle East and the North Sea,” Mr Rynd said.

The Energy Endeavour, a harsh-environment jackup designed for year-round operations in the southern North Sea and seasonally in the central North Sea in water depths up to 300 ft, is operating in the Danish sector of the southern North Sea for Maersk Oil until May 2013. Under a new contract with ADTI, the rig will mobilize to the UK Sector of the North Sea; the contract is scheduled to commence in mid-June.

Improvement in dayrates is another metric that’s pointing to a continued positive future for the global jackup market. “As an example, dayrates for standard jackups in the North Sea have climbed significantly to the $160,000 range from mid-$80,000 or lower two or so years ago, so they’ve had quite a bit of improvement in their demand. It’s rather a very dynamic market right now,” Paul Ravesies, senior vice president of marketing and business development for Northern Offshore, said. Mr Ravesies also believes that, despite an increasing supply, jackup dayrates have significantly increased in other markets around the world as well.

On Northern Offshore’s Energy Endeavour, workers stop to hold essential safety meetings – “Time Out For Safety” and “Toolbox Talks” – to assess any potential conflicts with a specific job.

Northern Offshore currently operates two jackups in the Danish sector of the southern North Sea, a mid-water semisubmersible in India and a mid-water drillship offshore Vietnam. “There is a limited supply of rigs that are qualified to work in the North Sea, and the barriers to entry are rather high. We were fortunate enough to get through the low point in 2009 to 2010 when there wasn’t a lot of work, and now we are benefitting from increased demand and higher dayrates,” he said. “In 2010, the North Sea standard jackup market was $65,000 to $80,000 a day, which is really not much more than your operating costs. Currently, rates are in the range of $155,000 to $165,000, and we’re seeing longer-term contracts of a year or more being tendered for.”

Northern Offshore has a safety policy of “back to basics,” where it holds one-day workshops focusing on expectations and identifying good practices, as well as barriers to success, quarterly management reviews and benchmarking.

Although Northern Offshore believes that the continued addition of larger, heavy-duty jackups to the global market will not significantly impact its current fleet, the company does see a need to eventually transition to a newer asset base. “As we move into the next phase, we expect to open up other geographic areas, and we will grow the organization as we need to. But we’re not going to get ahead of ourselves, so our focus is and will remain to manage an efficient, lean and professionally run operation.”

Mr Halkett of Vantage Drilling, which has four jackups operating in Thailand, Malaysia, Indonesia and the Ivory Coast, said that just four or five years ago, ultra-premium jackups were considered special in the market. “Now, those rigs have become the standard jackup rig that many operators want to use; they are the workhorse of the industry. It’s become more of the standard rather than the exception. Ultimately, the 30- to 35-year-old jackups will be forced out and retired because they’ve become too expensive to maintain and less efficient to operate.”

Currently, older equipment is spread out between West Africa, the Middle East, Asia and the Gulf of Mexico, he continued, noting that he foresees “a gravitation of some of the newer jackups to all of these areas over the coming years” in addition to the North Sea.

The Emerald Driller jackup is operating in Thailand for PTTEP through Q2 2013 at a dayrate of $130,000. The Vantage Drilling unit can work in maximum water depths of 375 ft and has a maximum drilling depth of 40,000 ft.

Another changing trend within the jackup market is construction location. Although most new jackups are still built in Singapore, more work is now moving to Chinese shipyards. “Singapore has really been the shipyard location of choice for many people to build jackups, but they’re going to partly see that market eaten up by the Chinese,” Mr Halkett said. “The Chinese are aggressive pricing-wise and can also potentially bring some financing. That attracts some drilling contractors, but it also attracts a lot of the speculators. They think they can order a cheap rig with low down payments and then sell it on for a profit later to more established drilling contractors at $20 million to $30 million more later.” (Read more about the shipyard boom on Page 62.)

Vantage Drilling’s Titanium Explorer drillship is working for Petrobras in the Gulf of Mexico on an eight-year contract at a dayrate of $572,000. The drillship is equipped to operate in up to 12,000 ft of water and has a maximum drilling depth of 40,000 ft.

In a recent discussion with investors, Kevin Robert, Ensco SVP of marketing, described a “very bullish outlook in terms of customer demand for both deepwater and shallow-water offshore markets. We expect that visible demand should keep the market fairly balanced for the foreseeable future, even with the increase in rig supply resulting from newbuild deliveries,” he said.

For the US Gulf of Mexico, jackups ENSCO 86, ENSCO 90 and ENSCO 99 all recently obtained six- to nine-month contracts at approximately $110,000/day, which represented increases of up to $30,000/day from their previous contracts. “We expect the US Gulf jackup market to remain strong in 2013 as drilling activity continues to be bolstered by strong oil prices and a lack of available rig capacity. We expect the floater market in the US Gulf to remain very active during 2013. More than a half-dozen clients are looking for rigs to drill programs starting this year,” Mr Robert stated.

Transocean’s Discoverer Clear Leader ultra-deepwater drillship is operating in the US GOM under a five-year contract with Chevron. The rig was the first of Transocean’s five newbuild enhanced Enterprise-class drillships put into service. Image courtesy of Transocean

In Mexico, the UK North Sea, Denmark and the Middle East, Ensco also expects strong jackup demand. “PEMEX plans to add six to eight incremental jackups to its fleet of rigs currently under contract.  PEMEX’s increasing demand for jackups enabled us to extend all four of Ensco’s 250-ft independent cantilever jackups working in Mexico at rates in the low $90,000s. PEMEX is also planning to add to their mid-water fleet,” he continued.

In the Asia Pacific region, Ensco believes jackup dayrates will continue to increase, as evidenced by contracts obtained on its premium rigs. “We expect the Asia Pacific jackup market to remain tightly balanced in 2013 even after considering 34 competitive newbuild jackups delivered this year, since we believe the majority of these rigs are already committed. The Asia Pacific region has always been an active floater market and is now showing some deepwater growth,” Mr Robert reported.

RS Platou charts show that year-over-year global demand for jackups has remained mostly steady. Demand is broken down in the bottom chart by region: North Atlantic, GOM, South America, West/South Africa, the Pacific Rim and what RS Platou calls “rest of the world” (ROW), including India, the Mediterranean, the Black Sea, North and East Africa, and the Middle East.

Turning to the West Africa floater markets, Mr Robert said the company continues to see high levels of tender activity for floaters commencing operations into 2015. Final contract approval for the ENSCO DS-7 drillship in Angola was received in February. “The dayrate will average in the high $640,000 range over the three-year term. We agreed with the client on the dayrate in the third quarter of 2012, and it took some time to receive all the necessary approvals. Looking ahead, we believe Angola still has unfulfilled demand of four to six floaters, and we expect other countries in West Africa to pick up three to five rigs in 2013.”

In New Zealand, the company contracted ENSCO 107 to OMV for the Maari Field development at $230,000/day, plus mobilization and demobilization costs. “This is a significant contract for many reasons,” Mr Robert explained. “The presence of ENSCO 107 in New Zealand is expected to attract other operators to utilize the rig, resulting in a longer-term stay in the country than the initial 10-month term. And the dayrate is a leading-edge rate for this rig class and approaches the peak rate achieved during the last market up cycle, which bodes well for the future jackup market in the region.”

Global offshore technology & HSE

Drilling offshore is not without its challenges, but industry is proactively developing solutions. At Chevron, well control is a significant focus area. “Chevron Drilling and Completions is formulating a comprehensive well control assurance process called WELLSAFE, which holistically focuses on critical aspects of well control for the operations we manage, including influx prevention, equipment integrity, procedures and personnel competency,” Eric Wagner, Chevron general manager, Global Drilling & Completions Category Management, said. “Another critical challenge is equipment reliability. Operators and their drilling business partners need to continue to collaborate in eliminating significant events and reducing nonproductive time.”

Image courtesy of Pacific Drilling
Pacific Drilling’s Pacific Santa Ana drillship commenced its five-year contract with Chevron in March 2012 and began operations in the US Gulf of Mexico in May that year.

Chevron currently has 34 offshore rigs on contract with a mix of base business, major capital projects and exploration activities in areas including the US Gulf of Mexico, Canada, Brazil, the UK sector, West Africa, Thailand, Indonesia, China and Australia. Mr Wagner said he believes the “hot spot” markets of West Africa, US Gulf of Mexico and Brazil will continue to remain robust for the industry, and Chevron expects to add ultra-deepwater rigs in Indonesia and West Africa at the end of 2013 and the beginning of 2014. “We see the current offshore dayrates as steady and have cooled off from the 2012 market demands, but we are closely monitoring the market through 2014, when a significant number of newbuild rigs arrive on the market.”

The company’s strategy, Mr Wagner said, is to implement the most advanced technology and to contract recently constructed rigs. “In addition to safety and environmental protection, reducing between-well cycle time, increasing up-time on the rig operation’s critical path and preventing significant lost-time events are all important drivers for us.  We believe cutting-edge technology and newer assets advance these objectives.”

Global rig demand for floaters, according to RS Platou’s April rig report, has had a positive year-over-year change over the past 12 months. Regional demand in the bottom graph shows that demand for floaters has been especially high in West and South Africa, the Pacific Rim (Southeast Asia and Australia) and the rest of the world (ROW) category, which in this case includes India, the Mediterranean, the Black Sea and North Africa.

In today’s offshore markets, in whatever part of the world with whatever rig, operators want increased reliability, Thor Arne Haverstad, executive vice president and head of drilling technologies for Aker Solutions, said. “The really big step-change that we are trying to work with is to look more into the efficiency picture, which for a drilling contractor means better uptime and more stable income, but if you ask the oil companies, it’s about deliverable wells, and that’s where MPO (managed pressure operations) technology fits in.”

Aker Solutions recently acquired Managed Pressure Operations International, a company that specializes in continuous circulation, riser gas handling and managed pressure drilling (MPD) systems. In offshore operations globally, Mr Haverstad said, Aker Solutions has seen that MPD is becoming an increasingly common request from oil companies and that they will need it more and more going forward. “We are sure about that, so in a way we found a competent environment with some clever people that could help us.”

Especially in deepwater, MPD is more and more being used to enhance kick detection, Charles Orbell, president and CEO of Managed Pressure Operations, noted. “With the deal with Aker Solutions, it allows us now to build an integrated MPD system rather than offer separate services.” The system, which is still under development, can isolate the well in five seconds, he said, which could be especially useful for fractured carbonates in Angola, Asia or Brazil. “There’s a step-change coming in understanding from the operators and the drilling contractors for this type of technology.”

Mr Orbell believes new rig designs will require both riser safety systems and MPD systems built into the rig. “You look at the rigs coming out of shipyards now with the same technology we had 20 years ago for monitoring the well, and the operators are no longer going to accept that. We’re sitting on 12,000 ft and already people are looking out to 20,000 ft – what do we need to do to get there? There are ongoing projects looking at what technology we need to drill in those environments. I believe personally, in the coming years, that if drilling contractors want their deepwater rigs hired, they will have riser safety systems and MPD built into the rig.”

According to an April rig report by RS Platou, demand for ultra-deepwater units has significantly increased over the past year, particularly in areas such as the Gulf of Mexico, South America, and West and South Africa.

Regardless, companies will want to build flexibility into new rigs, Glenn Ellis, senior vice president and head of Aker Solutions’ drilling technologies business in the US, said, even if rigs are built against a contract. For instance, consider the US GOM being shut down after Macondo. Mr Ellis believes that flexibility of the rigs provided contractors and operators the opportunity to move them out of the Gulf and into another market to continue working. “They need to have options… Ultimately, the strategy is to develop something that is global.”

Like technology, safety is another evolving element of offshore drilling being pushed to adapt to increasingly harsh drilling environments and complex operations. In To further enhance offshore drilling safety, contractors with multinational operations have been working to develop HSE programs that can be used across the whole organization. Odfjell Drilling, which predominately operates on the Norwegian Continental Shelf, decided to develop a standardized QHSE program when three of its newbuilds were contracted to new operational regions. “Two years ago, we had three newbuild units, the Deepsea Metro I in Tanzania, the Deepsea Stavanger in Tanzania then to Angola, and then we had Deepsea Metro II in Brazil,” said Tove Spjeld, manager of QHSE competence & improvement for Odfjell Drilling. “We saw that we needed to be hands-on with regards to establishing a common HSE culture and to give qualified support to the units.”

Aker Solutions’s MH DDM 1000 AC top drive onboard Seadrill’s West Hercules semisubmersible is one of the company’s best-selling drilling machines. Aker delivered the complete drilling equipment package for the rig in 2008.

Just launched this year, the Odfjell Drilling coaching program started with the company’s core values: to develop committed and motivated employees, to be safety conscious, to be creative in handling challenges, to be competent and result oriented, as well as having a desire for open communication lines. “When we are open, then we can really get a chance to move forward,” Ms Spjeld said.

The program’s curriculum includes offshore leadership, a buddy system, permit to work, housekeeping, managing risk and safety tools like safety checklists, stopping the job and HSE meetings. Employees undergo the program before the rig is mobilized to the operations, and it can take months to cover the rig’s entire crew. “We know, due to studies, that implementing an HSE culture takes time; it takes years if you’re not putting any extra effort into it. We want to be ahead of that and put an extra effort in and implement the HSE culture as early as possible.”

At the DSME yard in South Korea, five rigs have been outfitted with complete drilling packages from Aker Solutions: (clockwise from top left) Grupo R’s Bicentenario and La Muralla IV, Vantage Drilling’s Platinum Explorer, Odebrecht Oil & Gas’s Norbe VIII and Petroserv’s Carolina. Image courtesy of DSME

Odfjell Drilling’s goal is to achieve its QHSE principles by developing an HSE culture based on competence, involvement and commitment in applying company HSE rules, Ms Spjeld said, which are: “I will always comply with rules and procedures. I will always risk assess my work, and I will always act when I see unsafe behavior and conditions.”

The company believes that openness, dialogue and exchange of views and experience are important requirements for continual improvement within all operations. “When we are implementing our HSE culture, we are expecting the same from every operation, and we do have the same requirements, so we stay ahead. When we are open with our reporting, then we can really get a chance to move forward,” Ms Spjeld said. “This is a prerequisite for our growth and strategy as a company that we are able to operate in the same safe way whatever country or region that we operate in.”

D90 is a trademark of Frigstad Engineering.

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2013 OTC Spotlight on New Technology Awards

The Offshore Technology Conference has announced the 15 winning technologies that will receive the 2013 Spotlight on New Technology Awards recognizing innovative technologies significantly impacting offshore exploration and production.

Winning technologies are selected based on five criteria:

• New: The technology must be less than two years old.

• Innovative: The technology must be original, groundbreaking and capable of revolutionizing the offshore E&P industry.

• Proven: The technology must be proven, either through full-scale application or successful prototype testing.

• Broad interest: The technology must have broad interest and appeal for the industry.

• Significant impact: The technology must provide significant benefits beyond existing technologies.

ABB’s Onboard DC-Grid is an innovative marine technology that uses direct currents to transport energy to different consumers onboard the vessel. It enables variable speed operation of generator sets, significantly reduced fuel oil consumption, improved emissions reduction, reduced maintenance and new operational modes with a more responsive vessel system.

Baker Hughes’ FASTrak logging-while-drilling (LWD) fluid analysis sampling and testing service provides knowledge of reservoir fluid properties that enhances critical decision-making about the reservoir. FASTrak addresses the growing need to acquire fluid samples in LWD environments, such as horizontal or extended-reach wells, resulting in significant time and cost savings.

DOW NEPTUNE Advanced Subsea Flow Assurance Insulation System, developed by Bayou Wasco Insulation, Dow Oil & Gas, PIH and Trelleborg Offshore, is a simple, robust, end-to-end flow assurance solution offering enhanced performance safety with its two-layer application. It protects equipment, line pipe and field joints across a wide application and in-service temperature range, which runs from-40°C to 160°C, or -40°F to 320°F, withstanding hydrostatic compression greater than 400 bar.

FMC Technologies and Sulzer Pumps have developed a high-speed, helico-axial multiphase subsea boosting system optimized for subsea applications. This system combines field-proven pump hydraulics from Sulzer Pumps with FMC Technologies’ permanent magnet technology from Direct Drive Systems for less maintenance with greater speed, efficiency and power.

GE Oil & Gas has developed the next-generation technology for shearing and sealing wellbore tubulars. The patent-pending Blind Shear Ram is designed for use with GE’s ram blowout preventers in offshore drilling. It provides an industry-first capability to shear some 6 5/8-in. drill pipe tool joints while achieving a wellbore seal holding up to 15,000-psi pressure differential.

GE Oil & Gas’ RamTel Plus provides operators with a direct method of determining ram position. The ROV Display allows the ROV to read stack sensor data, including wellbore temperature and ram position subsea indicators.

FMC Technologies’ Condition and Performance Monitoring (CPM) is a surveillance system that enables proactive maintenance of subsea production and processing systems associated with a 24/7 collaborative expert environment for diagnosis and problem solving. CPM combines continuous monitoring of sensors and subsea instrumentation with a historic database to identify fault condition and deviations from normal operating conditions.

Reelwell’s RDM-Riserless system enables drilling in 9,843 ft (3,000 meters) water depths from third-generation drilling units due to the reduced weight related to omitting the riser. This is possible because the cuttings are transported to surface inside the dual drill string, i.e., the dual drill string acts as the riser.

Wärtsilä has developed a system to turn VOCs or associated gases that were previously considered as waste into a source of energy. The Wärtsilä GasReformer enables self-sustaining power generation for the offshore operation. It provides cost savings and environmental sustainability.

SBM Offshore’s Drilling Riser Trip Saver is a rail-mounted transport system that relocates a suspended drilling riser with a drilling riser tensioner system and surface blowout preventer in place. The apparatus and method for drilling multiple subsea wells consecutively saves time and cost and reduces risk by avoiding removal of the suspended drilling riser from the well bay.

Bredero Shaw’s Mobile Robotic Cutback System is an innovative end machining technology for insulated pipe. It replaces manual processes that form the cutback, including wire brushing, grinding and scraping. The technology is safer, quieter, requires less labor and produces consistent high-quality cutback profiles while generating recyclable waste.

WeST Drilling Products’ Continuous Motion Rig (CMR) is a fully robotized rig and offers continuous drilling operations. CMR reduces overall drilling time by up to 50% and facilitates managed pressure drilling. CMR substantially reduces downhole problems associated with differential sticking and pressure fluctuations and eliminates personnel safety risk.

Statoil’s remote-controlled hot tap operation consists of a robot welding a T-piece on to the pipe while gas is flowing through it. Afterwards, a remote-controlled drilling machine will drill holes in the producing pipeline, with no effect on pressure and production.

Superior Energy Services’ Complete Automated Technology Systems (CATS) is an onshore and offshore completion services rig that uses remote-operated or pre-programmed robotics to control various completion components, including a snubbing unit, BOP/well control stack, pumps, circulation tanks, top drive, closing systems and pipe handling systems as part of one unit.

Welltec’s Well Cutter enables efficient drill pipe and casing recovery without explosives. No shavings are generated, a smooth surface re­mains after the cut and e-line conveyance ensures accurate depth control. Click here to read about the Well Cutter from the Sept/Oct 2012 DC.

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ASTM subcommittee to develop hydraulic fracturing standards

By Katie Mazerov, contributing editor

ASTM International has formed a subcommittee to develop standards for hydraulic fracturing. Subcommittee D18.26, which held its first meeting in January, includes 230 volunteer members from operating companies, service companies, geotechnical and geo-environmental firms and regulators, said Robert Morgan, director of technical committee operations for ASTM. Member companies include BP, Chevron, Chesapeake Energy, Schlumberger and Halliburton.

The committee has identified several areas of focus:

• Site investigation;

• Site construction;

• Permitting;

• Drilling;

• Fracturing and stimulation;

• Drilling fluid characteristics;

• Waste management of completion fluid;

• Site monitoring and well abandonment; and

• Cementing and grouting.

The standards are strictly voluntary. Once they are developed, they will be ASTM standards that can be used in the marketplace and potentially cited in federal regulations, which currently reference some 2,500 standards.

“One of the reasons ASTM has been so successful is that it gets industry involved in the process and brings the regulatory community to the table to develop standards everyone can live with,” Mr Morgan said. “The process allows industry to be proactive rather than have a governmental entity determine what the standards should be. ASTM is an open and transparent organization, and anyone who has an interest in the process can get involved.”

The subcommittee, formed after an exploratory task force reached out to industry stakeholders, also works closely with related organizations to avoid duplicative efforts. One of the first endeavors of the task force was to review existing API documents related to hydraulic fracturing. “If another organization is meeting a marketplace need, ASTM typically does not get involved,” Mr Morgan noted. “We looked for voids in the API documents where ASTM standards could supplement the work that has already been done.

“Another objective in this effort is that ASTM does not want it to come across as an environmental watchdog activity but rather as a way to make the practice of hydraulic fracturing safe and efficient,” he continued. For example, one issue discussed at the initial meeting was proppant shape, which can make a significant difference in keeping fractures open for better flow of hydrocarbons.

The standards development process could potentially take more than a year, depending on the complexity of the topics being addressed. “The process depends on the urgency of the needs the members have identified,” Mr Morgan said. “The ASTM process has a proven history, and one of the reasons it has lasted so long is because of the professionals involved. This is a level playing field where everyone has an equal say.”

For more information on how to get involved in Subcommittee D18.26, please visit www.astm.org/COMMIT/D1826.htm.

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