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Published By NEWS COMMUNICATIONS since 1977 Saturday August 18, 2012
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DEEP OCEAN LURE GROWTHBooming like never before, the offshore oil and gas industry is exploring ever deeper into the ocean and drilling further under the sea bed, bringing strikes like one this week off Brazil that may be one o f t h e b i g g e s t y e t i n t h e region. "Ultra-deep" wells, drilled in water at least 1.5 km (4,500 feet) deep into several more kilometres of rock to the reservoir below, have reached a landmark in 2012 to date, accounting for more than half of all the world's new discoveries so far this year, data from IHS Offshore Rig Consulting shows. And from a global fleet of over 1,200 rigs and drilling vessels tracked by rigzone.com, more than 80 rigs on contract now have the ability to work in ocean depths of more than 7,500 feet. That compares to fewer than 10 at the turn of the century and double the number at work just two years ago, IHS says. It is not hard to see where the funds are coming from: the world's biggest offshore oil players, from the likes of BP, Royal Dutch/Shell and Chevron to national oil companies with promising offshore waters such as Petrobras in Brazil, India's ONGC and Mexico's Pemex - are using the proceeds of high oil prices to spend at a pace. Petrobras's new Carcara strike was 2
km below the surface of the Atlantic in an area causing much excitement. Data from analysts at Wood Mackenzie puts total exploration spending among the Western oil majors alone at over $80 billion this year, more than four times the level in 2002 - and up 25 percent compared to 2010. Much of that is going offshore, and the results are coming thicker and faster than many expected. As well as the news from Brazil, this week also saw unexpectedly strong results announced by Norwegian oil services company Aker Solutions, an offshore specialist. "The market seems better than anyone had hoped," said Christian Frederik Lunde, an analyst at brokerage Carnegie. The factors driving private oil and gas companies into the ocean have been around for decades; resource nationalism denies them access to three quarters of the world's known reserves, the economics and politics of offshore development are simpler than on land, and the finds are big and economically viable. A sustained period of high oil prices have pushed this latest boom, but technological breakthroughs have accelerated it, too. This week's Brazilian breakthrough is an example. Drilled in 2,027 metres of water to a depth of 6,213 metres, the Carcara well is in a so-called subsaltfield, underneath salt layers that once hid the hydrocarbon deposits from seismologists. It was all so different 30 years ago, when the North Sea between Britain and Norway was still new exploration territory. Engineers wondered then how they would ever drill from a sea bed deeper than a man could dive, and into reservoir pressures that would be higher than that diver's oxygen tank. "We thought we were pretty amazing when we did it," recalls Eamonn O'Connell, a veteran of the pioneering era and now BP's director for
pressures up to 18,000 psi -- more than three times what the North Sea geologists had to worry about. The risks are great, as demonstrated by BP's Macondo well, of 2010 Gulf oil spill infamy. Drilled in just below 5,000 feet of water and encountering pressure of 12,000 psi, it was not a record breaker. Yet the Transocean -managed Deepwater Horizon rig exploded, killing 11 people. The pipework collapsed, buckling, and the blowout preventer failed. A spewing, broken Macondo took months to cap, set off the United States' worst offshore environmental disaster, and is set to cost BP bil l ions of dollars in
well interventions and integrity. Today, those achievements in 140 metres or 400-plus feet of water look like child's play beside wells in the deep oceans. The world's deepest offshore production well, operated by Shell from the Perdido platform in the U.S. Gulf, is 9,356 feet - almost three km - below the waves. The water pressure alone at that depth is 4,500 pounds per square inch (psi), or 310 bar - similar to that inside those North Sea wells of the 1980s. The reservoirs themselves in the U.S. Gulf, off West Africa, Brazil and elsewhere, are several kilometres deeper again below the seabed, testing engineering ingenuity at
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compensat ion and f ines. I t a lso overshadows the financial future of TransOcean, the world number one rig operator. But the potential rewards offshore are equally enormous. Since 2002, WoodMac data shows, the average "shelf", or shallow offshore exploration, well has added 21 million barrels of oil equivalent (boe) in reserves, compared with just 12 million for the average conventional onshore well. In deep water - defined as deeper than 1,200 feet - the average leaps to 55 million boe. IHS data maps the average ultra-deep find, 4,500 feet down, higher again - at 140 million. That is 11.5 times more effective than an onshore rig, and at $100 a barrel, amounts to $14 billion worth of oil per discovery in the ultra-deep - enough to repay a whole year of capital spending for some of the world's top oil companies. "It's not too surprising. The deeper you go, the bigger the reservoir you need to make drilling worthwhile," says IHS
data analyst Tom Kellock. "The good news is, people are finding what they are looking for." For all the potential foreseen for onshore shale techniques in the United States, there is nothing marginal about the importance of offshore oil and gas to future energy supplies. On a production basis alone, Woodmac expects known deep and ultra-deep offshore finds to be producing twice what they are today in 10 years time, at 15 million boe of oil and gas a day. That is double last year's total U.S. oil output. Thunder Horse in the U.S. Gulf is BP's flagship well for the ultra-deep generation. The company's Eamonn O'Connell kisses his fingertips in fond recollection of the quality of the 1999 discovery which eventually went into production in 2008. The Thunder Horse platform is not in the deepest water, at 6,000 feet, but the wells it serves extend as much as 19,000 feet below the seabed and are among the deepest ever drilled, on- or offshore. The
well pressures range from 13,000 to 18,000 psi at temperatures up to 132 degrees Celsius (270 Fahrenheit) - right at the limit of current offshore capability. They are not stopping here. BP launched this year a project it calls 20K - aimed at the next generation of even deeper, higher pressure, higher temperature wells at pressures of more than 20,000 psi. Supercomputers, new materials, coatings and sub-sea sensors are being developed to exploit oil at these depths, and platform designers are looking at basin more gear on the sea floor so that pressures can be reduced on the way to the surface. Quite what will be possible is unclear. For the energy to be harnessed, engineers will have to get amazing again.
OIL PIPELINE CRUNCH SHIFTSRACE FROM DRILLBITS TO VALVES
The U.S. shale oil revolution can't be stopped, but it could be delayed by a potential shortfall of 10-ton valves and giant
pipeline pumps essential for rebalancing markets upended by the surge in production. Amid an unanticipated boom in inland oil output that turned the domestic market upside down last year, firms from Enterprise Products Partners to Shell Pipeline and Plains All American have launched a $20 billion bonanza to build, expand or reverse two dozen pipelines in the past year. But as they help effectively to switch the flow of oil from the north to southern refineries and relieve the glut of cut-price, landlocked crude, concerns are growing that the firms that make key pipeline components may be straining to keep pace. "The supply chain hasn't quite caught up," said Terry McGill, president of Enbridge Energy Co Inc, the U.S. division of Canadian pipeline giant Enbridge Inc, which has some $4 billion worth of U.S. projects on the books. Thus far, there are no signs of project delays or cost overruns in what is the biggest build-out of oil and liquid pipelines
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since World War II. Executives say they are building in plenty of lead time to produce dozens of multi-ton valves and massive pumps essential for maintaining pipeline flow. Underutilized steel mills, meanwhile, can rev up furnaces to forge the pipes -- which have a diameter of up to 42 inches. But the task is enormous. After decades of moving U.S. offshore or Middle East crude from the Gulf Coast to inland refineries, pipelines must flow in the opposite direction to accommodate surging output from Canada and shale oilfields such as North Dakota's Bakken. It all makes for a historic boom, said Larry Schwartz, senior analyst for natural gas liquids at consultancy Wood Mackenzie: "Midstream, which was the redheaded stepchild, is now in vogue." Spending has already accelerated far faster than many expected. A year ago, the Interstate Natural Gas Association of America (INGAA) estimated North America would add 19,000 miles of oil pipelines at a cost of $31.4 billion by 2035 as production surged 50 percent to 12.7 million barrels per day. But industry monitor IIR Energy now estimates that $10 billion a year will be spent on crude oil pipeline projects in 2012 and 2013, four times the average of the previous seven years. "You're not just connecting in to existing grids," Enbridge's McGill said. "The grid is being built." The biggest projects, those pumping 1 million barrels daily or more, face the greatest risk of delay, experts say. Each of the dozens of valves required on something like TransCanada Corp's proposed $7.6 billion Keystone XL pipeline -- which has a 36-inch diameter -- usually must be custom-made. "We definitely consider ours an ‘engineered to spec' product," said John Starck, vice president of sales for M&J Valve, a division of multi-industry manufacturer SPX Corp that operators say is a leading valvemaker for liquids pipelines. "We do not actually build the product and keep it on the shelf because each customer has their own unique set of specs." Meanwhile, the market is consolidating as bigger companies snap up industry-favored manufacturers. That shrinks the already small field of venders in the brand- and manufacturer-loyal industry, threatening higher prices as demand swells. Operators saw prices for parts shoot up sharply in 2007 and 2008, the apex of the last huge pipeline build-out that brought on thousands of miles of new natural gas pipelines. "The price just goes up the more projects are out there," said Leon Zupan, president of gas pipelines for Enbridge's U.S. division. "Whenever you need big castings for pumps or valves, there's only so many people who can do it." At SPX, valves and pumps make up part of its fast-growing global flow technology business that the company has said it expects overall to contribute $1 billion to sales this year. SPX has given no specific sales data on parts involved in the U.S. liquids pipeline boom. The first huge build-out in the United States came during World War II when the federal government ordered a two-pipeline system, the Big Inch and Little Big Inch, to carry oil and refined products to the Northeast from the Gulf Coast. The network, created largely to thwart German submarines that had repeatedly torpedoed tankers along the Atlantic Coast, later had its lines converted to carry natural gas. Postwar prosperity generated industrial demand for natural gas, and pipeline
construction flourished for another 20 years. Big one-off oil projects included the Colonial refined product pipelines linking Gulf Coast refiners to the Northeast market and the 48-inch, 800-mile Trans-Alaska Pipeline System (TAPS) to bring newfound Alaskan crude to that state's coast. After that, pipeline construction slowed dramatically as refinery construction stopped and steady oil production n e c e s s i t a t e d o n l y i n c r e m e n t a l improvements in the network. Then came the natural-gas shale frenzy that spurred a huge wave of pipeline construction from 2006 until 2008, when the financial crisis and a collapse in prices halted investment, leaving some parts distributors nursing heavy losses. MRC Global Inc, the largest global distributor of pipe, valve and fittings to the energy industry, recorded a $46.5 million writedown in 2009 on an overhang of unused inventory as customers dried up. The company declined to comment on its business. Now the focus is on crude as drillers apply the same hydraulic fracturing technology that upended the natural gas market five years ago to neglected onshore oilfields, unleashing a burst in production unimagined a few years ago. Output in the Bakken alone has surged from nothing to more than 600,000 barrels per day in five years, and may double by 2015. Texas is on pace to issue the most drilling permits since 1985 as output from Eagle Ford, the Permian Basin and the Granite Wash surges. More liquids may emerge from the gas-heavy Marcellus shale in the Northeast or Ohio's nascent Utica shale. Much of that increased production is in remote areas far from refining hubs or in the Midwest and Northern Tier, turning the traditional south-to-north flow pattern on its head. Producers were forced to turn to costly rail, barge and even truck tankers to move oil from the wellhead to refineries. "New infrastructure is going to be critical to push these commodities around the country where they need to be," said David Seaton, chairman and CEO of engineering company Fluor Corp. "It's going to be the lifeblood of economic growth for my lifetime." The aim is to eliminate the bottlenecks and reduce transportation costs, shrinking the discount of benchmark inland in Cushing, Oklahoma to global prices. At $15 a barrel last week, the gap remains historically wide. The first such project, Phase I of the reversal of the Seaway Pipeline to move crude from Cushing to the Texas coast, began pumping on time in mid-May. It will require a host of additional pumps and valves -- but no major pipeline sections -- to reach 450,000 bpd by the first quarter of 2013. It's not just oil pipes. Some $6.5 billion is being spent on natural gas liquids pipelines needed to accommodate output growth in propane, butane, hexane and other NGLs that emerge from shale plays and feed hungry petrochemical complexes, according to IIR. "By carefully managing those rare instances when we've had an issue with a valve or a pump, we have been able to complete the vast majority of our projects on time or even ahead of schedule," said Leonard Mallett, senior vice president of engineering for Enterprise Products Partners. His company is one of the largest U.S. operators with planned projects totaling some $7 billion across pipelines, terminals and storage. As manufacturers see orders for critical inputs increase, some are hiring more workers,
U.S. crude
from welders to salespeople. Others are soaking up current capacity to produce more by adding shifts and some seem to be expanding, cautiously. A valve for a 20-inch pipeline can weigh 3,000 pounds (1,360 kg) to 4,100 pounds, while one for a 36-inch line can weigh 15,500 to 19,000 pounds, depending on whether flanges are included. The biggest valves for the largest pipes are heftier, plus they cost about $120,000 each. It can take 20 to 22 weeks of lead time to build a 42-inch valve, said M&J Valve's Starck. Enbridge's McGill said for big pressure pumps, "it would be a year." John Lenander, vice president of oil and gas
valves for another major valve and pump supplier, Dallas-based Flowserve, said t im ing depends on the leve l o f specialization, the amount of valves needed, and pipe size. For example, 10 valves for 200 miles of 42-inch pipe could be supplied in six to eight months. But 60 valves for 1,200 miles of 42-inch pipe would more likely be quoted with partial deliveries starting in six months, with everything completed in about a year, he said. "We've been putting a lot of additional resources into supply-chain management, project management and engineering," he said. Flowserve, which reports second-quarter
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results on Tuesday, is also expanding plant capacity, he said, but declined to provide details. Flowserve has said U.S. and Canadian
"You need to diversify your supplier base. That's being done right now, and it should have been done a long time ago," said Elis Zhonga, a senior U.S. sales representatives for Valvitalia, which distributes Italian- and Chinese-made valves. He said the company is hiring more sales and distribution staff at its U.S. operations in response to increased demand. But Zhonga said that despite the complaints, pipeline companies are loyal to tried-and-true suppliers, and he doesn't expect that to change even if manufacturing times lengthen. The most basic raw material for pipelines and a majority of mainline valves -- steel -- remains plentiful, operators say. U.S. steel production is at about 75 percent capacity, according to the American Iron and Steel Institute. About 7.2 percent of steel production went to the energy industry in 2011, and that share is expected to grow this year. Capacity is rising as well. Industrial Info is tracking more than $1.7 billion in projects to build mills designed to produce pipe in North America, much of it by foreign companies including China's Tianjin Pipe and India's Welspun Gujarat Stahl Rohren.
CONNACHER SELLS TWO UNITSRELEASES Q2 RESULTS
Connacher Oil and Gas Limited has announced that it has entered into an agreement with Calumet Specialty Products Partners, L.P., a leading refiner and processor of specialty hydrocarbon products in the United States, to sell its heavy oil refinery and related asset in Great Falls, Montana for total proceeds of US$155 to US$170 million, prior to the potential deduction of a tax liability of approximately US$20 million. The total proceeds consist of a purchase price for the Refinery of US$120 million plus working capital, including inventory at market value at the time of closing. Management estimates that the working capital adjustment could result in additional cash proceeds of US$35 to US$50 million, depending primarily on the quantity of asphalt sales prior to closing and the corresponding market prices of refined products. The transaction is subject to customary regulatory approvals and third
unconventional resources -- such as shale and tight oil and gas production -- have led to "significant project activity" in its North American oil and gas, chemical and power markets. The company does not break out valves and pumps for U.S. liquids pipelines. Starck said M&J, whose parent SPX reports earnings on August 1, has bulked up its manufacturing workforce slightly, but so far has mostly worked to optimize existing plant capacity. ClydeUnion Pumps, a leading pumpmaker that SPX bought last year for $1.25 billion, has no plans to expand manufacturing capacity, confident its five factories in North America and Europe can meet demand. "We can see ahead just how our capacity is, and do what we need to do whether it be one shift or two shifts," said Dick McAdam, vice president of sales in the Americas for ClydeUnion. Some competitors to the top firms say builders have begun to complain about long lead times, even at manufacturers with which they regularly work.
party consents. Closing of this transaction is expected in October 2012. This sale transaction represents one of the steps in the strategic review process initiated by the Board of Directors earlier this year. The sale capitalizes on the significant value of the Refinery arising from the disconnect between North American posted prices, heavy oil differentials and crack spreads, which have resulted in strong refining margins. Another step in the strategic review process is the proposed sale of the company's conventional oil and gas assets. In this regard, the company has entered into a letter of intent to sell all of its conventional petroleum and natural gas properties effective July 1, 2012, for cash consideraton of $18.3 million, subject to normal post-closing adjustments. This transaction is expected to close in September 2012. The completion of these transactions will enhance the company's liquidity and allow it to pursue development opportunities to increase production at Great Divide. Connacher's Board of Directors continues to actively pursue its strategic review process. Connacher's upstream operating and financial results in the quarter ("Q2 2012") were lower than the comparable period of 2011 ("Q2 2011") primarily due to slightly lower production volumes and significantly lower commodity prices. The Refinery continued to post strong financial results, contributing $22.8 million in refining netbacks in Q2 and $33.3 million year to date ("YTD"). Net proceeds from the aforementioned dispositions will be used in part to repay the company's revolving credit facility, with the remainder added to working capital pending deployment in 2013 in the following development projects. Connacher continues to advance two significant projects that have the potential to materially enhance the economics of the company's oil sands projects: (SAGD+™" (the injection of solvent into the steam injectors to increase production, reduce steam:oil ratios ("SOR") and potentially increase reserve recovery) and "dilbit by rail" (utilizing railcars as opposed to pipelines to move dilbit to refineries thereby improving pricing and netback for dilbit). A second SAGD+™ phase was initiated during the second quarter on a single well with medium quality pay located at Algar. The objective of the test was to demonstrate repeatability from the previously reported fall 2011 two-well pilot. Additionally, this test is intended to quantify production improvements on lesser pay quality wells and test additional solvent recovery surface equipment and design parameters. The results to date on this well have been very encouraging. Comparing July 2012 to April 2012 bitumen production and steam injection volumes, results in an approximate 25% increase in bitumen production and an approximate 28% decrease in SOR for this well pair. Based on these results and subject to capital allocation, the Algar SAGD+™ project may be expanded to the full Algar field in 2013. As previously announced the company recently entered into a five year agreement with Canexus Corporation for "Transloading Services" at their North American Terminal Operations facility in B ruderhe im, A lbe r ta as we l l as "Transportation Management Services" which includes the use of 300 newly constructed railcars to be delivered over a nine month period. These efforts have resulted in current "dilbit by rail" sales
amounting to approximately 40% of the company's production. It is anticipated that "dilbit by rail" as a percentage of total production will continue to rise as more rail cars become available thereby improving pricing for bitumen. In addition to these significant innovations, Connacher has a number of approved development projects designed to increase production and throughput at its existing plants. In addition to SAGD+™ there are two re-drills at Algar; up to six SAGD well pairs on the new Pad 104 at Pod One; the drilling of a number of infill wells at Pod One and the addition of a
diluent recovery unit ("DRU") at Pod One to reduce overall diluent usage and recycle diluent to the plants rather than selling it as part of the sales stream at a discount. Reducing overall diluent usage required for treating and transportation of bitumen will reduce overall diluent purchase costs and transportation costs and enhances bitumen value to refineries. The commencement of such projects will depend on, among other f a c t o r s , t h e c o m p l e t i o n o f t h e a forement ioned d ispos i t ions , the conclusion of the strategic review process and the company's balance sheet position.
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