Halliburton to Return Equipment, Workers to Gulf

by Paula Dittrick, OGJ Senior Staff Writer, OGJ, Apr 18, 2011
Halliburton Co.’s management plans in the coming months to return some equipment and workers to the Gulf of Mexico, Halliburton Chairman, Chief Executive Officer, and Pres. Dave Lesar said Apr. 18 while he announced escalating first-quarter profits.

Halliburton moved some equipment and workers from the gulf to US onshore while regulators temporarily suspended drilling during investigations into the Apr. 20, 2010, blowout of BP PLC’s deepwater Macondo well in 5,000 ft of water off Louisiana and the subsequent oil spill.

An explosion and fire on Transocean Ltd.'s Deepwater Horizon semisubmersible resulted in the deaths of 11 workers. A resumption of offshore US drilling is coming about gradually as producers and contractors fulfill new federal certification requirements [please see remarks below -- D.R.].

Halliburton reported first-quarter net income of $511 million, compared with $206 million for the same period last year [please see details, here. -- D.R.]. [Full story]

(U.S. regulators began during the first quarter to issue drilling permits for the Gulf of Mexico's deep waters for the first time since halting such activity in response to BP PLC's oil spill a year ago. Halliburton, which provided services to BP on its doomed Macondo well, has won 30% of the drilling service contracts and 40% of well-completion work for projects that have been approved since the resumption of activity, CEO Lesar said. As a result, Lesar said, Halliburton plans in the coming months to bring back to the Gulf some equipment and workers that it had deployed onshore during the deep-water drilling shut down---please see MarketWatch, Apr 18, 2011, here. All deep-water drilling must comply with new safety and environmental mandates imposed since the spill. Companies/Operators also must prove they can swiftly contain a blowout in deep water. Two companies -- Houston-based Helix Energy Solutions Group and the Exxon Mobil-led Marine Well Containment Company -- have developed systems including vessels and other equipment to capture oil from runaway deep-water wells---please see my post here, including remarks. For Halliburton 4Q 2010 earnings, please see my post here, including remarks. In January 2010, the US presidential commission investigating the BP disaster slammed Halliburton, along with BP and rig owner Transocean---please see my post here. For Halliburton's operations in Iraq, please see my post here. -- D.R.)

Half of U.S. Liquid Fuels Net Imports in 2010 Came from the Americas

EIA, Today in Energy, Apr 15, 2011

Notes: Imports from Saudi Arabia amounted to about 12%. Other ME excludes imports from North Africa (Algeria and Libya). -- D.R.

Based on data from the Petroleum Supply Monthly [released: Feb 25, 2011 -- D.R.], half of all U.S. net imports (imports minus exports) of liquid fuels [i.e., net imports of crude oil and petroleum products, etc.] in 2010 came from the Americas (North America, Central America, South America, and the Caribbean). Only about one-fifth of U.S. net imports came from the Middle East. For many years, the top source of U.S. liquid fuels net imports has been Canada, followed by Mexico, Saudi Arabia, Venezuela, and Nigeria. With the exception of Canada, the order of these top five sources has varied from year to year.

Net imports have been a key source of supply for U.S. liquid fuels consumption over the years as the chart above indicates. After reaching a trough in the mid-1980s, net imports of liquid fuels generally rose until 2005. More recently, increases in domestic production and declines in consumption [during the recession -- D.R.] both have led to a drop in net imports of liquid fuels. Net imports of liquid fuels represented about half of U.S. liquid fuels consumption in 2010. [Full story but please see interactive graphics -- D.R.]

(U.S. total consumption of petroleum and non-petroleum liquid fuels increased by some 380,000 barrels per day or 2.0% to 19.148 million b/d in 2010, compared to the previous year. U.S. liquid fuel net imports, including both crude oil and refined products, fell from 9.667 million b/d in 2009 to 9.441 million b/d in 2010, comprising 49% of total consumption in 2010, compared with nearly 52% in 2009---please see chart/interactive above. During the same period, U.S. total liquids production grew from 9.212 million b/d to 9.755 million b/d. In retrospect, liquid fuel net imports fell from 60% of total U.S. consumption in 2005 to 49% in 2010---please see chart above. Currently, the United States still relies heavily on imported oil. In 2010, it imported 9.163 million b/d of crude oil and nearly 2.6 million b/d of refined products, according to data from the EIA---please see my post here. U.S. crude oil production last year increased by 151,000 b/d to 5.512 million b/d---please see Aaron and David Rachovich, "U.S. Crude Oil Production/Table," here. In a speech at Georgetown University in Washington, March 30th, President Obama said, "Last year, American oil production reached its highest level since 2003, and for the first time in more than a decade [last time 1997 - 49% -- D.R.], oil we imported [net imports] accounted for less than half the liquid fuel we consumed [i.e., 49%, see above -- D.R.]."---please see OGJ, Mar 30, 2011, here. Separately, for the U.S. crude oil imports alone from Top 15 countries in 2010, please see our post here. -- D.R.)

Ten Deepwater Oil Wells Approved in First Six Weeks of Post-Macondo Permitting

by Meghan Gordon, Platts blog -- The Barrel, Apr 12, 2011
Now that US regulators have awarded the first 10 deepwater drilling permits since the Deepwater Horizon disaster -- Statoil received number 10 late last week -- don't expect a lot of fanfare from them about each subsequent approval. The Bureau of Ocean Energy Management, [Regulation and Enforcement, i.e., BOEMRE, the former Minerals Management Service -- D.R] said it would stop alerting reporters when it signs off on individual deepwater permits. You can still track them here.

The watch continues for these holders of the first 10 permits to get started:

Drilling permits approved

1. Noble Energy, February 28 -- [...] [drilling] a bypass well in 6,500 feet of water in Mississippi Canyon Block 519, about 70 miles southeast of Venice, Louisiana. [An operator drills a bypass in order to drill around a mechanical problem in the original hole to the original geologic target from the existing wellbore. In this case, Noble Energy will be drilling around the plugs set in the original well when drilling was suspended in order to complete the project---please see BOEMRE, here. -- D.R]. Helix Well Containment Group. [Also, please see my related post, here. -- D.R.]

2. BHP Billiton, March [...] [11] -- resume pre-moratorium operation in 4,234 feet of water in Green Canyon Block 653, about 120 miles south of Houma, Louisiana. Helix Well Containment Group.

3. ATP Oil & Gas, March 18 -- resume [...] [operations/i.e., drill a new well -- D.R.] halted by the moratorium in 4,000 feet of water in Mississippi Canyon Block 941, about 90 miles south of Venice. [Initial drilling on ATP’s Well #4 began August 2008, in 4,000 feet water depth. Drilling was suspended July 2009, and a rig was on-location April 2010 to prepare for installation of a production facility when activities were suspended due to the temporary drilling suspensions imposed following the Deepwater Horizon oil spill---please see BOEMRE, here. -- D.R.] Helix Well Containment Group.

4. ExxonMobil, March 22 -- start drilling a well approved before the spill in 6,941 feet of water in the Keathley Canyon Block 919, about 240 miles south of Lafayette, Louisiana. Marine Well Containment Company.

5. Chevron, March 24 -- resume drilling started before Macondo in 6,750 feet of water in Keathley Canyon Block 736, about 215 miles [sic] south of Lafayette. Marine Well Containment Company.

6. Statoil, March 25 -- start drilling a well that had rig under contract before the spill in 7,134 feet of water in Alaminos Canyon Block 810, about 215 miles south of Texas City, Texas. Helix Well Containment Group.

7. Shell, March 30 -- new well and first permit under an exploration plan reviewed entirely after moratorium. Allows drilling in 2,721 feet of water in Garden Banks Block 427, about 140 miles south of Lafayette. Marine Well Containment Company.

8. Eni, April 1 -- sidetrack well that had rig on location before the moratorium. Allows drilling in 2,823 feet of water in Mississippi Canyon Block 460, about 60 miles southeast of Venice. Helix Well Containment Group.

9. Murphy Exploration & Production, April 7 -- sidetrack well that had rig on location before moratorium. Allows drilling in 3,325 feet of water in Green Canyon Block 338, about 170 miles southwest of New Orleans. Helix Well Containment Group.

10. Statoil, April 8 -- start drilling a well that had rig under contract before the spill in 7,813 feet of water in Walker Ridge Block 969, about 220 miles south of Houma. Marine Well Containment Company.

Exploration plans approved
1. Shell, March 21 -- three wells in 2,950 feet of water in the Auger field, about 130 miles offshore Louisiana. [Full story]

(All deep-water drilling must comply with new safety and environmental mandates imposed since the spill. Companies/Operators also must prove they can swiftly contain a blowout in deep water. Two companies -- Houston-based Helix Energy Solutions Group and the Exxon Mobil-led Marine Well Containment Company -- have developed systems including vessels and other equipment to capture oil from runaway deep-water wells. -- D.R.)

Halliburton Wins Oil Services Contract in Iraq

Bloomberg Businessweek, Apr 11, 2011
Halliburton Co. said Monday that it has been contracted by Exxon Mobil Corp. to use three drilling rigs to provide oil drilling services at a large field under development in southern Iraq.

The contract from ExxonMobil Iraq Ltd. covers services for 15 wells at the 8.6 billion-barrel West Qurna Phase I oil field, one of Iraq's largest. Financial terms of the deal were not disclosed.

Exxon's partners in the Qurna project include two Iraqi state-owned companies and an affiliate of Royal Dutch Shell PLC. ExxonMobil Iraq is the lead contractor on the field, with a 60 percent stake [please see remarks below -- D.R.]. It said last month that initial field production at the Qurna I field increased 17 percent to 285,000 barrels per day, exceeding its 10 percent improvement target. Under an agreement between Iraq and the companies, production from the West Qurna I field should reach 2.825 million barrels a day after 6 to 7 years [please see my post here -- D.R.].

Shares of Houston-based Halliburton rose 8 cents to $48.21 in morning trading. [Full story]

(ExxonMobil subsidiary Exxon Mobil Iraq Limited with 60% interest is the lead contractor working with the South Oil Company of Iraq to redevelop and expand the West Qurna I field along with the Oil Exploration Company of Iraq with 25% interest and Shell West Qurna B.V., a Royal Dutch Shell affiliate -- 15% interest. In August 2010, Halliburton announced it had been awarded a contract by Italian oil company Eni to provide a range of integrated energy services to help redevelop the Zubair field in southern Iraq. Halliburton will perform services such as wire-line logging, perforating, acidizing and well testing on 20 wells. For Iraq's oil production targets, please read my post "Iraq Says to Produce 6.5 mil b/d by 2014; Disputes IMF Figures," here. For Halliburton's profits, please see my post here, including remarks. -- D.R.)

World Watch [Statoil's Growth Strategy: North America]

by Tom Haywood, Houston, EI
Onshore and offshore North American plays are taking on a greater role in Statoil's plan to grow international assets from 25% of its portfolio. Statoil has stakes in some of the major fields in the deepwater Gulf of Mexico, including Shell's new Vito discovery, and offshore Eastern Canada. But its onshore presence is also burgeoning from the Western Canadian oil sands to the Marcellus and Eagle Ford shales in the US. Bill Maloney, Statoil's first executive vice president based in the US, told the Houston Chronicle that North America is becoming a "major growth engine" for the Norwegian major. "The nice thing about working in North America is that every day is an opportunity. You don't have that same commercial setup in other parts of the world." [Please see remarks below -- D.R.] But Statoil is finding more opportunity in Norway, as well. [Recently,] [...] the company announced it had made a major oil discovery in the Barents Sea off Norway's northern coast [please see remarks below -- D.R.].

(Please read an interview with Bill Maloney: The Houston Chronicle, Apr 2, 2011, here. Statoil, along with partners Eni Norway and Petoro, has made a significant oil and gas discovery on the Skrugard prospect in the Barents Sea. The breakthrough discovery is one of the most important finds on the Norwegian continental shelf in the last decade---please see Scandinavian Oil-Gas Magazine, Apr 1, 2011, here. For Statoil's ranking, please see my post, "Problems Slow Statoil's 2010-11 Production," > remarks, here. For exploration and drilling offshore Norway during the first quarter of 2011, please see my post here. -- D.R.)

CERAWeek: Unconventional Gas Lifts US Petrochemicals

by Bob Tippee, OGJ Editor, OGJ, Mar 9, 2011
Rapid growth in gas supply from shales and other unconventional reservoirs inverts expectations for North American petrochemicals and underscores the importance of feedstock flexibility in an integrated business strategy, says the leader a major US petrochemical manufacturer.

The brightened business outlook shows the importance of integrating petrochemicals not only with refining but also with upstream operations, according to Stephen Pryor, president of ExxonMobil Chemical Co. and vice-president of ExxonMobil Corp.

A 20% surge in gas supply from unconventional resources during the past 5 years [please see remarks below -- D.R.] has boosted ethane production by 25% and lowered the cost of an important feedstock, Pryor told an IHS-CERA Week conference session [please see remarks below -- D.R.].

“We see ethane reemerging as an advantage feedstock in North America, reflecting the growing production of unconventional natural gas and the increasing importance of gas in the world energy mix,” he said.

In the US last year, the growing supply of relatively low-cost ethane strengthened margins for ethylene and derivatives, lightened the feed slate, and increased US exports.

“The current strength of the US petrochemical market contrasts with conventional wisdom of just a few years ago when it was believed that US petrochemical production would decline, feed slates would get heavier, and the US by 2010 would flip into a net import position,” Pryor said. “Actually, exports grew by about 28% last year.”

Capacity gains?

The ExxonMobil Chemical chief doubts that the improved outlook for North American petrochemicals will lead to an early surge in grassroots construction of ethane crackers.

At least in the near term, he said, capacity growth will be incremental, resulting from debottlenecking of existing light-feed capacity and limited conversion of heavy-feed crackers.

Capacity investment will depend on the pace and pattern of North American ethane supply growth, which in turn will depend on the location and rate of unconventional gas development, liquids content across geologic plays, and construction of equipment able to strip, transport, and store NGLs.

“Just as in refining, incremental investment in feed flexibility and capacity creep are the most efficient ways to meeting growing demand in a mature market like North America, major investments at full grassroots costs would be subject to significant risks relative to long-term oil and gas prices, export economics, and gas developments around the world that could provide feedstocks for competitors overseas,” Pryor said.

Integration strategy

Feedstock flexibility is central to what Pryor described as the “site-wide optimization” ExxonMobil Chemical applies in its integration strategy.

It involves “having the flexibility to process a wide variety of feedstocks and selecting the feed slate that generates the highest value for the integrated complex,” he said. “It entails adjusting the process conditions and product slates in real time so that you extract maximum value from every molecule processed.”

Integration is “more than simply collocating refineries with petrochemical plants,” Pryor said.

It involves optimization not only of feedstocks but also of products, costs, capital, and people. Pryor said 90% of his company’s petrochemical capacity is integrated with refining or gas processing capacity.

The process is continuous and oriented to long-term outcomes. Managing through the “turbulence” of modern markets requires a “disciplined, long-term approach that does not change with short-term changes in commodity prices and profits,” he said. [Full story]

(According to the U.S. Energy Information Administration/EIA, in the past 10 years, U.S. shale gas production has increased more than 12-fold from 0.39 trillion cubic feet/tcf in 2000 to 4.87 tcf in 2010---please see my post > remarks > EIA data, here. In 2005, U.S. shale gas production stood at just over 0.5 tcf. After methane, ethane is the second-largest component of natural gas. The new natural gas/i.e., shale gas can provide ethane feedstock that can be converted into ethylene, a key plastic feedstock used to make commodity resins polyethylene and PVC and several specialty materials as well. For years, North American makers of plastics and petrochemicals had been looking for a way to remain competitive on the global market. Use of low-priced natural gas as a feedstock has allowed the North American market to use less ethylene based on higher-priced naphtha feedstock, which comes from price-volatile crude oil. Naturally, as the price of crude oil rises, so does the price of plastic. The Barnett shale basin in Texas, with 12,000 natural gas wells as of 2009, “is huge,” Alan Armstrong, CEO of Williams Cos. Inc., said. But the Marcellus shale basin---covering a large portion of Pennsylvania and parts of Ohio, New York and West Virginia, etc.---is expected to be many times larger---please see Plastics News, Apr 5, 2011, here. -- D.R.)

Mixed Drilling Trends off NW Europe, Deloitte Finds

Offshore Magazine, Aberdeen UK, Apr 8, 2011
Exploration and drilling has tailed off slightly on the UK continental shelf, but held steady or has risen elsewhere in northwest Europe according to the latest survey by Deloitte.

During the first quarter of 2011, Deloitte identified nine exploration and appraisal well spuds [more specifically, five exploration + four appraisal wells -- D.R.] on the UKCS, a decrease of 25% compared with the previous quarter. Of the nine wells spud this year, five were in the central North Sea, two in the southern gas basin, one in the northern North Sea, and one on the Faroe-Shetland escarpment.

Despite the dip, Deloitte says the outlook was more positive until the government imposed its surprise tax increase on the sector in March [please see remarks below -- D.R.]. Various companies have since stated their intention to put appraisal and development projects on hold, although it is not clear how much this will impact drilling levels over the coming months.

During 1Q 2011, 10 UKCS exploration and appraisal wells were completed, four by EnCore and its partners in central block 28/9 to find or appraise the Varadero, Catcher North, and Burgman discoveries. Another of the completed wells was Maersk’s Culzean gas/condensate find in the same sector.

UK farm-in activity has risen, Deloitte says, with 13 farm-in deals announced in the first quarter of this year compared with eight in the previous quarter. The rising oil price could be an incentive for companies to increase their equities in reserves, or it could herald a return to corporate strategies that were in place pre-recession.

Offshore Norway, one appraisal and 12 exploration and appraisal wells spudded during the first quarter, the same as during the corresponding quarter in 2010. Eight of the 13 wells were in the North Sea, three in the Norwegian Sea, and two in the Barents Sea.

The outlook for the Norwegian shelf remains positive, Deloitte says. New production licenses were awarded in January under the latest pre-defined areas (APA) round. These, combined with the oil price, should sustain high drilling activity over the remainder of this year.

Of the 11 E&A wells completed on the shelf in the quarter, three were successful. Appraisal well 15/6-11 A intersected an oil column for Statoil on the Dagny/Ermintrude discovery, and well 24/9-10 S and its side track 24/9-10 A encountered oil at Caterpillar.

Off the Netherlands, three E&A wells were spudded during the quarter, compared with one in the corresponding quarter last year.

So far in 2011, four wells have been completed, of which two were drilled by GDF Suez in the K quadrant to target the Darcy prospect. Both resulted in technical failure after heavy mud losses were experienced while drilling though a fractured chalk horizon.

The Minister of Economic Affairs is inviting applications for an exploration license for Dutch North Sea block E/5, with bids due by June 7. One unnamed operator has so far applied. [Full story]

(UK Chancellor of the Exchequer George Osborne announced plans on March 23 to raise GBP2 billion a year from the sector to pay for a fuel duty freeze by adding an extra 12% to taxes on profits made from oil and natural gas in the UK North Sea while crude oil prices remain above $75/b---please see Platts, London, Apr 8, 2011, here. -- D.R.)