OGJ Newsletter

May 27, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Growth easing for MENA oil exporters

Economic growth rates of oil exporters in the Middle East and North Africa (MENA) are moderating as oil production flattens in response to modest global demand, reports the International Monetary Fund.

The IMF expects average growth for a group of exporters to be 3.2% this year, down from 5.7% last year. It projects average growth of 3.7% in 2014 for the group, which includes Algeria, Bahrain, Iran, Iraq, Kuwait, Libya, Oman, Qatar, Saudi Arabia, the United Arab Emirates, and Yemen.

The region's oil importers, IMF says, "face a difficult external environment." The importers' group—Afghanistan, Djibouti, Egypt, Jordan, Lebanon, Mauritania, Morocco, Pakistan, Sudan, and Tunisia—will have average economic growth of 3% this year vs. 2.7% last year. IMF projects the importers' growth next year at 3.6%.

"Economic conditions remain impaired across most MENA oil importers, with continued social unrest, complex political transitions, and an economic environment characterized by modest global growth, persistently high food and fuel prices, and weak domestic confidence," IMF Middle East Department Director Masood Ahmed told a press conference in Dubai.

Higher gas prices unlikely under several scenarios

US natural gas prices are unlikely to rise markedly under a variety of scenarios, including those with increased demand across multiple sectors, a study by the Bipartisan Policy Center's Energy Project staff concluded.

BPC said the report analyzed the combined effect of increased gas demand from multiple sources, including industry, electric power generation, and LNG and pipeline exports.

It said the analysis addresses two key policy questions: what price impacts would be when multiple demand drivers act in concert, and how impacts would vary under high and low gas supply assumptions.

The analysis found that even when demand for gas is high and supplies are low, prices in the scenario analysis would never reach levels seen in the past when prices peaked, BPC said.

It said increased gas consumption in the future will be primarily driven by overall economic growth and increased demand in the electric power and industrial sectors. Natural gas vehicles stand to make significant gains in market share and vehicle miles traveled by 2035, it said.

Bill aims to correct unintended RFS subsidy

US Sens. Bob Corker (R-Tenn.) and Joe Manchin (D-W.Va.) introduced legislation on May 16 aimed at correcting what they said was unintentional subsidization of foreign ethanol imports under the federal Renewable Fuels Standard.

They said the Foreign Fuels Reduction Act is necessary because EPA has revised the RFS's cellulosic biofuels volume requirement down to US commercially produced levels, but has not used its authority to also reduce advanced biofuels and total renewable fuels requirements.

This has created a gap in advanced biofuels production that has provided an incentive to import biofuels, further complicated the "blend wall" issue, and intensified the debate over biofuels land use issues domestically and internationally—all of which are contrary to RFS's original intent, the lawmakers indicated.

They said their bill would end imports of sugar cane ethanol from Brazil, which EPA allows, to meet an increasing portion of the RFS mandates; more properly align ethanol supplies with demand to mitigate blend wall impacts; and soften RFS's harmful effects on land use and commodity prices internationally.

The American Fuel & Petrochemical Manufacturers, which wants Congress to fully repeal the RFS, said the proposed bill highlights one of the policy's many problems: "When the RFS was enacted in 2007, Congress never envisioned that cellulosic biofuels would not exist and that more than 90%, as much as 75 billion gal, of the advanced biofuels quota would have to be fulfilled by imports and biodiesel," AFPM Pres. Charles T. Drevna said.

QPI invests in Total E&P Congo

Qatar Petroleum International (QPI) agreed to acquire a 15% stake in Total E&P Congo, stating this reinforces its commitment to invest in Africa.

Terms of the agreement were not specified. Total E&P Congo operates the Moho-Bilondo license with a 53.5% interest. The oil development offshore Congo (Brazzaville) is expected to begin production in 2015 and reach 140,000 boe/d in 2017 (OGJ Online, Mar. 22, 2013).

Mohammed Bin Saleh Al Sada, Minister of Energy and Industry and QPI chairman, said the agreement reinforced relationships between Qatar and Congo.

Christophe de Margerie, Total chairman and chief executive officer, called the agreement a new step in implementation of a 2010 memorandum between QPI and Total for a strategic cooperation in Africa.

QPI was established in 2006 as a wholly owned subsidiary of Qatar Petroleum, the national oil company of Qatar.

Exploration & DevelopmentQuick Takes

BLM seeks comments on Horseshoe basin project

The US Bureau of Land Management's Rock Springs, Wyo., field office began a 30-day public scoping period on May 6 before it prepares an environmental assessment of Devon Energy Production Co. LP's proposal to develop up to 20 new oil and gas wells within the Horseshoe basin unit. Comments will be accepted until June 4.

The unit covers 24,972 acres of primarily federal land, with a small amount of state and privately owned land, about 55 miles southeast of Rock Springs, BLM said. The Horseshoe basin unit was developed in 2005, and presently has two gas wells, roads, pipelines, and a centralized production facility, BLM noted.

Devon has proposed drilling 2 wells/year horizontally or vertically to 8,500-11,500 ft depending on the geologic formation, according to BLM's scoping notice. It said the project also would include access roads, pipelines, and power lines.

BLM said Devon plans to minimize surface disturbance by co-locating new wells on existing well pads, or by establishing multiwell pads, when possible, with about a 40-acre maximum surface disturbance. The wells would be developed during the next 10 years, with the life of the project anticipated to be 20-30 years, it said.

Max Petroleum logs pay in Kazakh appraisal

Max Petroleum PLC, London, has run production casing in an appraisal well it plans to test in Baichonas West field in Kazakhstan. The company said it logged hydrocarbon potential in several zones in the BCHW-2, drilled to 1,487 m TVD.

Electric logs indicated 7 m of net pay in Jurassic reservoirs and 5 m of net pay in Triassic reservoirs over a 170-m gross interval that also included 93 m of lower quality Triassic reservoirs possibly amenable to hydraulic fracturing.

The indicated Jurassic pay is in two zones: 1,106-16 m and 1,187-1,201 m. The lower interval correlates with pays in the BCHW-1 well. The reservoir in the upper zone hasn't been encountered before. Reservoir quality is excellent with porosities of 15-27%, Max said.

The Triassic section, at 1,210-1,380 m, is mostly tight sandstones, all of which appear charged with hydrocarbons. The section Max considers net pay has porosity of 15% or greater. A 33-m section has porosities of 8-15%, and a further 60 m has porosities below 8%. Max plans to test the whole Triassic section then move the Zhanros ZJ30 rig to drill the SAGW-4 appraisal in Sagiz West field, which is northeast of Baichonas West and also on Block E, east of Atyrau.

Karoon encounters oil at Santos basin discovery

A combine led by Karoon Gas Australia Ltd. has made an oil discovery at the Bilby-1 well in the Santos basin offshore Brazil.

The Bilby-1 well, on Block S-M-1166 went to 3,854 m measured depth and found oil contained in an interbedded sand and shale interval of Late Cretaceous age, confirmed from sampling over a 200-m gross section so far. The discovery has been verified by wireline petrophysical, pressure data, fluid sampling, and mudlog analysis.

The well is positioned 150 m downdip from the trap crest as interpreted on seismic. After wireline testing is complete, the well is to drill ahead to the planned TD of 4,573 m MD.

The well was drilled as part of an agreement dated Sept. 18, 2012, as a minimum work commitment for five offshore blocks, S-M-1101, S-M-1102, S-M-1037, S-M-1165, and S-M-1166. Pacific Rubiales Energy Corp., Toronto, has a 35% interest in the blocks subject to approval by Brazil's ANP.

Two other exploratory wells have been drilled on the blocks as part of the agreement. Kangaroo-1 was previously announced as an Eocene light oil discovery, and Emu-1 was plugged and abandoned after failing to discover hydrocarbons in economic quantities.

Drilling & ProductionQuick Takes

Hercules Offshore agrees to sell its inland fleet

Hercules Offshore Inc. agreed to sell 11 inland barge rigs, which includes 3 active rigs, 8 cold-stacked rigs, and related assets for $45 million. Excluded from that divestiture, Hercules also agreed to sell the Hercules 27 to a third party for $5 million.

Closing will be staggered based on the expiration dates of existing contracts on the three active rigs and is subject to the completion of certain customary closing conditions.

An initial closing is expected to include 10 rigs and is expected in late second quarter, at which time Hercules will $35 million, and closing on the final rig is expected in early third quarter, at which time the company will receive the remaining balance of $10 million.

John T. Rynd, Hercules chief executive officer and president, said, "The sale of our inland rigs is consistent with our ongoing efforts to rationalize noncore assets."

Based in Houston, Hercules operates a fleet of 38 jack up rigs, 13 barge rigs, and 64 lift boats.

Solar EOR system commissioned in Oman

Petroleum Development Oman and GlassPoint Solar have commissioned a solar enhanced oil recovery system at Amal West oil field in southern Oman (OGJ Online, Aug. 4, 2011).

The 7-Mw system produces an average 50 tonnes/day of steam directly into existing thermal operations at the field, lowering the use of natural gas.

GlassPoint says its technology, called Enclosed Trough, can cut gas used for EOR by as much as 80%.

The technology encloses parabolic mirrors inside a glasshouse structure to protect solar collectors from wind, dust, dirt, sand, and humidity. The enclosure allows use of ultralight, low-cost reflective materials and automated washing equipment.

The steam generators are designed to use low-quality boiler water such as that used in once-through steam generators.

Cabot using Marcellus field gas to fracture wells

Cabot Oil & Gas Corp. said it is using natural gas from the Marcellus shale in Susquehanna County, Pa., to fracture wells via dual-fuel technology in a process that can displace as much as 70% of the diesel fuel traditionally used to operate hydraulic fracturing equipment.

The dual-fuel technology involves engines operating on a mixture of natural gas and diesel. The effort was a partnership with FTS International (FTSI) and Caterpillar Global Petroleum, Cabot said. Benefits are said to include:

• Reduced air emissions for a cleaner environment, due to a reduction in diesel usage.

• Reduced truck traffic when field gas at or near the well site is used due to a reduction in the transportation of diesel fuel to site.

• Reduced costs, as natural gas can be a less expensive fuel option than diesel, providing potential cost savings for industry and consumers.

"Cabot is continually searching for ways to utilize cutting-edge, environmentally friendly technology during our operations," said Dan O. Dinges, Cabot chairman, president, and CEO. "We are already converting our vehicle fleet and currently have a drilling rig using natural gas as well, so the next step is to utilize the technology on a hydraulic fracturing site."

In order to operate using natural gas, FTSI's mobile pressure pumping unit at the site was retrofitted with a dynamic gas blending kit from Caterpillar. The system enables substitution of diesel fuel with natural gas during high-pressure pumping operations and is compatible with field gas, CNG, and LNG.

Fletcher Finucane production starts off Australia

Oil production has started ahead of schedule from Fletcher Finucane oil field offshore Western Australia in the Carnarvon basin, project operator Santos Ltd. reported.

The $490 million (Aus.) project was originally due on stream during this year's second half after a final investment decision was reached in January (OGJ Online, Jan. 13, 2013).

The field is producing 15,000 b/d of oil through a three-well subsea tieback to the Mutineer Exeter FPSO vessel. Gross proved and probable reserves are put at 14 million bbl.

The project effectively extends the life of the nearby Mutineer-Exeter fields, which have been on stream for many years.

Santos is also hoping to expand the reserves still further with the drilling of the Vanuatu prospect on the same permit, hopefully later this year.

Santos holds a 44% aggregate interest in the project; partners include Kuwait Foreign Petroleum Exploration Co. (Kufpec) and JX Nippon Oil & Gas Exploration Corp.

PROCESSINGQuick Takes

EPA proposes Tier 3 vehicle emission, sulfur limits

The US Environmental Protection Agency proposed standards to reduce vehicle emissions and sulfur content in gasoline beginning in 2017. Comments on the so-called Tier 3 requirements will be accepted until June 13, EPA said on May 21. The American Petroleum Institute immediately asked for a longer comment period.

"EPA is cramming through unnecessary new regulations for gasoline that could drive up costs without providing significant environmental benefits," API Downstream Group Director Bob Greco said, adding that by limiting public comments, EPA is "trying to skirt public participation and transparency in the rulemaking process."

In its May 21 Federal Register notice, EPA said the proposed gasoline sulfur limit would make both new and existing vehicles' emissions control systems more effective, and enable more stringent vehicle emission standards.

"The proposed vehicle standards would reduce both tailpipe and evaporative emissions from passenger cars, light-duty trucks, medium-duty passenger vehicles, and some heavy-duty vehicles," it said.

"This would result in significant reductions in pollutants such as ozone, particulate matter, and air toxics across the country, and help state and local agencies in their efforts to attain and maintain health-based National Ambient Air Quality Standards," EPA said.

The proposed vehicle emission limits also would bring federal requirements into line with California's low-emission vehicle program, enabling automakers to sell the same vehicles in all 50 states, it added.

API previously asked EPA to follow federal Clean Air Act public review procedures, but the proposal only allows comments for 23 days, Greco said. Current regulations are working, with 90% less sulfur in gasoline today compared to 10 years ago, he indicated.

IOC develops biodiesel coprocessing method

State-held Indian Oil Corp. Ltd. (IOC) has developed and commercialized a technology for coprocessing nonedible vegetable oil in a refinery diesel hydrotreating unit to make biodiesel.

During development of the method it also created a process for demetallization and degumming of vegetable oils.

IOC demonstrated the technology at the 190,000-b/d Chennai Petroleum Corp. Ltd. Refinery at Manali. Chennai Petroleum is part of the IOC group.

The refinery's diesel hydrotreating unit, operating with a specific catalyst developed by IOC's research and development center, used up to 6.5% of jatropha oil with the refinery stream.

The company ran 200 tonnes of jatropha oil supplied by CREDA Biofuels Ltd., a joint venture of IOC and Chhattisgarh Renewable Energy Development Authority.

During the trial, IOC said, the diesel cetane number improved by 2 units, sulfur content diminished, and the inlet temperature of the reactor could be reduced by 100º C.

IOC said its coprocessing technology yields biodiesel with a higher cetane number, better oxidation stability, and lower density than biodiesel produced via conventional transesterification, which requires a separate plant. It said its coprocessing method, which can be deployed in existing refineries with minor modifications, has an operating cost about 50% lower than that of conventional biodiesel facilities.

Kansas refinery to pay air-quality penalty

Coffeyville Resources Refining & Marketing agreed to pay a $300,000 civil penalty to settle alleged violations of air-quality requirements at its 115,000-b/d refinery at Coffeyville, Kan.

Under a consent decree lodged in the US District Court in Wichita, the company also will perform a series of audits and reviews of its procedures for managing risks of accidental release of harmful substances into the air.

The agreement settles allegations by the Environmental Protection Agency of deficiencies in a risk-management program required by the Clean Air Act.

It's the company's third environmental settlement since 2012, according EPA Region 7.

The new settlement is subject to a 30-day public comment period and approval by the federal court.

TRANSPORTATIONQuick Takes

Plains All American to build line extension

Plains All American Pipeline LP is building a 95-mile extension of its existing Oklahoma oil pipeline to service production from the Granite Wash, Hogshooter, and Cleveland Sands producing areas in western Oklahoma and the Texas Panhandle.

The new Western Oklahoma pipeline will ship up to 75,000 b/d from Reydon, Okla. in Roger Mills County, to PAA's Orion station in Major County, Okla. From the Orion station, crude oil will flow on PAA's existing pipeline system to its terminal in Cushing, Okla.

Long-term producer commitments support the new pipeline, which PAA expects to enter service by the end of first-quarter 2014.

Earlier this year PAA announced a 55-mile extension of its Mississippian Lime pipeline, expected to enter service by yearend and also shipping through existing infrastructure to Cushing (OGJ Online, Feb. 8, 2013).

Pipeline okayed for Alberta blended bitumen

Laricina Energy Ltd., Calgary, has received approval from the Energy Resources Conservation Board of Alberta for its Stony Mountain Pipeline (SMP) in the western Athabasca oil sands region.

The project will be able to carry 200,000 b/d of blended bitumen through a 187-km, 24-in. pipeline from Saleski, where Laricina has a thermal pilot project, to Cheecham south of Fort McMurray. Cheecham is becoming a pipeline hub (OGJ Online, Jan. 25, 2013).

The project also will have a 12-in. diluent return line with capacity of 70,000 b/d. A tank farm about 2 km northeast of the Saleski pilot also is planned.

"The SMP is the first regional pipeline in west Athabasca servicing the emerging Grand Rapids and Grosmont plays," said Glen Schmidt, Laricina president and chief executive officer. "Bitumen production volumes from in situ oil sands projects in the area are expected to increase in the near to midterm. A permanent transportation solution beyond trucking and rail will be required to continue to develop the region efficiently and economically."

Laricina expects to start up the blend line in mid-to-late 2015 as Saleski Phase 1 commercial production begins. The company expects to receive diluent by truck until the diluent return line enters service about a year later.

An extension is possible to connect Laricina's Germain thermal project at start-up of a second phase there. Production from the first phase of the Germain project is expected to start later this year.

Laricina is considering what it described as "a range of commercial structures, agreements, and financing sources" for the pipeline, which it estimates requires initial capital of $600-650 million (Can.).

Questar Pipeline starts open season for expansion

Questar Pipeline Co. has started a binding open season to solicit support for an expansion of capacity out of the Uinta basin by extending its Jurisdictional Lateral 138 (JL138) to the Myton Yard.

The proposed expansion will involve 4.3 miles of pipe and ancillary facilities that will enable Questar to offer 30,000 dekatherms/day of incremental transportation capacity from receipt points located on JL138, JL46, and JL47 with possible deliveries available at the following locations:

• Chipeta Processing LLC or other Uinta basin processors.

• White River hub.

• Questar Northern system interconnects including Overthrust, CIG, Questar Gas, and Southern Star.

• Questar Southern system interconnects including Questar Gas and Kern River.

Other receipt and delivery points might be available depending on response to the open season, scheduled to conclude June 14.

Assuming Questar receives customer interest and arranges financing, the company anticipates the expansion could be in service by November 2014.