OGJ Newsletter

Jan. 12, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

COGCC to resume hearing on oil, gas fines, penalties

Colorado's Oil & Gas Conservation Commission was scheduled to resume a hearing at 9 a.m. MST on Jan. 5 on implementing legislation that would increase fines and penalties for companies which violate the state's comprehensive oil and gas regulations.

COGCC recessed the proceedings after 2 days on Dec. 16, 2014, after approving all but two proposed rule changes. It planned to deal with those when the hearing resumed.

The Colorado Oil & Gas Association, meanwhile, disputed some media reports that COGCC delayed its final decision because of "intense oil and gas industry pushback."

COGA Pres. Tisha Schuller said, "The commissioners delayed the decision for no other reason than it was after 5 p.m. and they had several versions of proposed rules they needed to compare and individually review. COGA, and each industry representative who testified, made it clear that we supported the law that passed and COGCC's authority to implement its mandates. The industry was proud to support the increased penalty bill."

Schuller said industry witnesses expressed concerns over the process for issuing notices of alleged violations and the penalty schedule set forth in the COGCC's proposed matrix. Specifically, she said companies were concerned improper application of the penalties would have an impact without reasonable discretion to the alleged violation.

"We're looking for clarity and certainty as to how the new rules would be enforced and applied, not for certainty on what the penalty should be," Schuller said. "Overall, we are all on the same page with the same goal, which is to promulgate rules that provide certainty, clarity, and consistency to all stakeholders, not just industry."

American Energy's Utica, Marcellus units to merge

American Energy-Utica LLC (AEU) and American Energy-Marcellus LLC (AEM), both affiliates of American Energy Partners LP (AELP), will merge in an all-stock transaction.

AEU and AEM will remain wholly owned subsidiaries of AEA and their existing debt and convertible debt securities remain unaffected.

The merger will result in AEA operating more than 300,000 net acres in the Utica and Marcellus shales in eastern Ohio and northern West Virginia. AEU says the deal was made because of the complementary nature of the respective company's acreage.

During the quarter ended Sept. 30, 2014, AEA had estimated proved reserves of 1.5 tcfe, of which 77% was gas, and estimated daily production of 167 MMcfe, of which 79% was gas.

Both companies in August closed on acquisitions in their respective plays totaling $1.75 billion (OGJ Online, Aug. 8, 2014). AEA's equity owners are The Energy & Minerals Group, First Reserve, and other institutional investors and management.

Bradshaw to head Trans Adriatic Pipeline

Ian Bradshaw, senior vice-president for capital projects at BG Group, has been named managing director of Trans Adriatic Pipeline AG, Baar, Switzerland (OGJ Online, Oct. 15, 2014). He succeeds Kjetil Tungland, who had worked with TAP on secondment from Statoil since April 2010 and will return to Norway.

Bradshaw has worked for BG Group since 2005 and before then worked for Shell.

Exploration & DevelopmentQuick Takes

Chevron finds oil in deepwater gulf Anchor prospect

Chevron Corp. reported a discovery of oil pay in multiple Lower Tertiary Wilcox sands in its Anchor prospect's Green Canyon Block 807 Well No. 2, drilled in the deepwater Gulf of Mexico.

The well, which was spudded in August 2014, was drilled about 140 miles offshore Louisiana in 5,183 ft of water. It reached a depth of 33,749 ft. Chevron says appraisal drilling begins in August.

"The Anchor discovery, along with the previously announced Guadalupe discovery (OGJ Online, Oct. 23, 2014), are significant finds for us in the deepwater Gulf of Mexico," said Jay Johnson, Chevron senior vice-president, upstream. He added that these discoveries, combined with more than 30 others worldwide in 2014, will add an estimated 1 billion bbl of resources to the company's holdings.

The Anchor well was drilled by Pacific Drilling's Santa Ana drillship. Chevron says it has five deepwater drillships operating in the gulf, two of which are focused on exploration (OGJ Online, Oct. 17, 2014).

Chevron is Anchor's operator with 55% working interest, Cobalt International Energy Inc. has 20%, Samson Offshore Anchor LLC and Venari Resources LLC each have 12.5%.

The Anchor well was drilled by Pacific Drilling Services Inc.'s Pacific Santa Ana drillship. Photo from Pacific Drilling.

CNOOC makes gas discovery in Qiongdongnan basin

CNOOC Ltd. reported making a natural gas discovery with its Lingshui 25-1-1 exploration well drilled in the northeast part of Ledong Sag in the Qiongdongnan basin of the South China Sea. Average water depth is about 980 m.

The well was drilled and completed at a depth of 4,000 m and encountered an oil and gas pay zone with a total thickness of 73 m, CNOOC said. On test, the well produced at rates of 35.6 MMcfd of gas and 395 b/d of oil.

The discovery follows the Lingshui 17-2 discovery in the same basin in first-quarter 2014 (OGJ Online, Mar. 19, 2014).

Drilling & ProductionQuick Takes

ConocoPhillips starts production from Eldfisk II

ConocoPhillips has started oil production from the Eldfisk II project in the Norwegian North Sea.

The project includes plans to drill 40 new production and water injection wells. One of four predrilled wells is currently online, with the remaining three anticipated to come on stream this month.

The company says production from the field will ramp up over the next 3 years as additional wells are brought online.

The Greater Ekofisk area, 200 miles offshore Stavanger, encompasses the producing Ekofisk, Eldfisk, Embla, and Tor fields. Crude oil from Greater Ekofisk's fields is exported via pipeline to Teesside, England, and natural gas flows via pipeline to Emden, Germany.

"Eldfisk II joins Ekofisk South as the second major project startup in Norway since late 2013 (OGJ Online, Oct. 28, 2013)," said Matt Fox, ConocoPhillips executive vice-president, exploration and production.

"These projects will increase ultimate resource recovery and extend the field life of this premier legacy asset for years to come," said Fox. Eldfisk II, along with Ekofisk South and other projects offshore Norway, will add 60,000 boe/d to the company's production volumes by 2017.

Statoil starts gas, condensate production from Valemon

Statoil ASA reported start of natural gas and condensate production from Valemon field in the Norwegian North Sea on Jan. 3 (OGJ Online, Oct. 9, 2014).

The company estimates recoverable reserves of 192 million boe in the high-pressure, high-temperature field.

The Valemon platform will be remotely controlled from shore and will evolve into a normally unmanned platform when drilling is completed in 2017. The platform will have 10 production wells.

Use of existing facilities in the Kvitebjorn and Heimdal fields reduced Valemon development costs, said Arne Sigve Nylund, executive vice-president. Condensate will be piped to Kvitebjorn for processing while gas will be sent to Heimdal.

Eni starts production from Nene Marine field

Eni SPA has started production from Nene Marine field, 17 km offshore Congo (Brazzaville) in 28 m of water on the Marine XII block. The milestone comes 8 months after the company received the production permit and 16 months following the discovery (OGJ Online, Aug. 1, 2013).

Nene Marine is near existing plants and produces from the Djeno presalt formation 2.5 km below the ground. Development of the field will occur in several stages, which include the installation of production platforms and the drilling of more than 30 wells, Eni says.

The first phase of production totals 7,500 boe/d, which is sent for treatment on the Eni-operated Zatchi production platform via a subsea pipeline over 17 km. Production is expected to plateau at 140,000 boe/d. On test, the Nene Marine 3 well flowed more than 5,000 b/d of 36° gravity oil.

Last month, the Minsala Marine 1 well, also part of Marine XII, flowed 5,000 b/d of 41° gravity oil and 14 MMscfd of gas (OGJ Online, Dec. 15, 2014). The company in recent years has discovered 3.5 billion boe in the Congolese Marine XII block, of which 1.5 billion Eni attributes to Nene Marine field.

PROCESSINGQuick Takes

Petrotrin takes hit from US shale, margins

Trinidad and Tobago's state-owned oil company Petrotrin is blaming the shale oil revolution in the US and poor refining margins overall for a $60 million loss during its 2013-14 fiscal year. Petrotrin noted that even though it has sold its crude at high prices during the first half of 2014, its refining business has been particularly hard hit because it imports 125,000 bo/d for its 175,000 bo/d refinery. It said its 50,000 bo/d production is not enough for its refinery and it has had to deal with low margins because US refineries are benefitting from "discounted" crude prices.

Petrotrin said it plans to increase crude and gas output from its Trinmar operations in Jubilee field and the continuing South West Soldado project as well as from other lease operatorship, farmout, and joint venture programs.

Trinidad and Tobago's Energy Minister Kevin said poor margins have led to the closure of 60 refineries globally in the last 5 years, with a further 11 closures currently being contemplated. Ramnarine said, "In the Caribbean, two refineries have closed in recent years. In Europe, 13 refineries have closed in the last 5 years."

Salaries and wages account for 54.5% of Petrotrin's recurrent budget compared with the benchmark of 35-40% for national oil companies around the world. In addition, it has a debt of $2.3 billion following several refinery upgrades in the last 5 years.

Pemex advances clean energy plans at Salina Cruz

Mexico's Petroleos Mexicanos (Pemex) is in the process of converting its Antonio Dovali Jaime refinery in Salina Cruz, Oaxaca, to operate on cleaner, more affordable fuels as part of the country's recently inaugurated energy reform legislation (OGJ Online, Aug. 18, 2014).

Pemex currently is working to revamp processing activities at the Salina Cruz refinery that will allow them to operate on cleaner natural gas supplies arriving to the region via a newly commissioned 12-in. gas pipeline that extends 247 km from the Gulf of Mexico at Jaltipan, Veracruz, to Oaxaca, along Mexico's Pacific Coast, according to separate releases from Pemex and Mexican President Enrique Pena Nieto.

Gas deliveries to Oaxaca along the Jaltipan-Salina Cruz pipeline, which started up Jan. 2, will allow the Salina Cruz refinery to eliminate the use of 4.38 million bbl/year of heavy fuel oil to power boilers and burners at the plant, Pemex said.

The displacement of fuel oil with gas also will lead to sharp reductions in emissions of carbon dioxide and sulfide oxides from the refinery, the company said.

Part of Pemex's Transoceanic Corridor Project, the first $200 million phase of the Jaltipan-Salina Cruz pipeline has a capacity to deliver 90 MMcfd of dry gas to the Salina Cruz refinery.

Pemex previously let a contract to Foster Wheeler AG for the Salina Cruz refinery for work related to an ultralow-sulfur diesel (ULSD) project that forms part of the diesel phase of a $2.8 billion investment into increasing ULSD production at five of Mexico's refineries (OGJ Online, Oct. 14, 2014; Aug. 21, 2014).

Under the contract, Foster Wheeler, in joint venture with Mexican construction company Arendal, Monterrey, will provide a major revamp of the refinery's four diesel hydrodesulfurization units; the installation of units for hydrogen production, sulfur recovery, and sour water stripping; and extensive upgrades to the utilities and offsite installations.

The Salina Cruz revamp project is scheduled to be completed in 2018.

Tall Oak expanding Oklahoma natural gas midstream

Tall Oak Midstream, LLC began natural gas gathering operations on its 150-mile STACK System, serving producers in Oklahoma's STACK play (Sooner Trend, Anadarko basin and Oklahoma's Canadian and Kingfisher counties). Long-term gathering and processing agreements with Felix Energy LLC and PayRock Energy LLC anchor STACK. Together, Felix and PayRock control more than 100,000 net acres in the STACK play. Tall Oak is also in discussions with other area producers to bring gas onto the STACK System.

Northwest of Oklahoma City, STACK targets liquids-rich Woodford and Mississippian-age shales, including the Upper and Lower Mississippian Meramec, Osage, Woodford shale and Hunton formations. The system will also be able to serve production from the Springer shale play and other portions of the South Central Oklahoma Oil Province (SCOOP).

Tall Oak expects to commission the system's first processing plant, the 100-MMcfd Chisholm Plant in Kingfisher county, in this year's third quarter. Residue gas can be shipped to market via Southern Star Central Gas Pipeline and Enable Gas Transmission (OGJ, Nov. 3, 2014, p. 38). The Chisholm site can accommodate expansion up to 400 MMcfd.

The company is also building a natural gas gathering and processing system to serve producers in Oklahoma's Central Northern Oklahoma Woodford (CNOW) play. Tall Oak's CNOW System consists of 250 miles of gas gathering pipeline and the 75-MMcfd Battle Ridge Plant in Payne County, Okla. Tall Oak expects to bring the cryogenic plant with nitrogen rejection capabilities into service at the end of this month.

BP lets contract for Belgian petchem complex revamp

BP Chembel NV, a wholly owned subsidiary of BP PLC, has let a contract to Jacobs Engineering Group Inc., Pasadena, Calif., to provide basic and detailed engineering services for a revamp of units at its 2 million-tonne/year petrochemicals complex in Geel, Belgium.

Jacobs Engineering will install equipment and perform upgrades in purified terephthalic acid (PTA) units at the complex, the service provider said.

The upgrading project is intended to optimize Geel's overall operational performance, Jacobs Engineering said.

Neither a value of the contract nor details regarding the specific nature of the upgrades were disclosed.

In addition to three PTA units with a combined production capacity of 1.3 million tpy, the Geel complex also produces 700,000 tpy of paraxylene (PX), which is used exclusively for in-house production of PTA, according to BP's web site.

Using BP technology, the complex's PX unit-one of the world's largest-also produces benzene and fuel additives from xylenes feedstock supplied by multiple refineries.

Amoco Chemical Belgium Co. NV, Geel's previous owner, let contract to Foster Wheeler Energy Ltd., Reading, UK, for the complex's PX unit, which had an initial production capacity of 420,000 b/d and was scheduled to be commissioned in 2000 (OGJ Online, Nov. 24, 1997).

TRANSPORTATIONQuick Takes

Cheniere given FERC okay for Corpus Christi project

The US Federal Energy Regulatory Commission has authorized Cheniere's Corpus Christi Liquefaction LLC and Cheniere Corpus Christi Pipeline LP to construct and operate their proposed 15-million ton/year (tpy) liquefaction plant, 400-MMcfd regasification terminal, and associated pipeline. FERC concluded that any adverse environmental impacts from the projects would be reduced to less than significant levels via implementation of the 104 conditions included in the approval.

Corpus Christi Liquefaction plans to build three 5-million tpy liquefaction trains and three 160,000 cu m LNG storage tanks. The liquefaction project will also include two trains of ambient air vaporizers, each with an average vaporization capacity of 200 MMcfd.

The project will also include a marine terminal with two berths on the north end of the La Quinta Channel, capable of receiving 200 to 300 LNG carriers annually. Each berth will consist of a maneuvering area and a protected marine berth area. Four tugs will be available to maneuver the LNG carriers. Two parallel LNG transfer lines will deliver LNG between the LNG carriers and the LNG storage tanks at a rate not to exceed 12,000 cu m/hour.

In conjunction with the liquefaction project, Cheniere Pipeline, formerly Corpus Christi Pipeline Co., will build and operate a 23-mile, 48-in OD, bidirectional pipeline in San Patricio County from Corpus Christi Liquefaction to a point near Sinton, Tex. The 2.25 bcfd pipeline will move both domestic natural gas to the plant for export and regasified imports from the LNG terminal to interconnections with the existing pipeline systems of Texas Eastern Transmission Corp., Kinder Morgan Tejas Pipeline LLC, Natural Gas Pipeline Co. of America, Transcontinental Gas Pipe Line Corp., and Tennessee Gas Pipeline Co. The pipeline will operate at a 1,440-psig maximum allowable operating pressure.

Cheniere Pipeline also will build and operate the Taft Compressor Station at milepost 7.5 and the Sinton Compressor Station at MP 21.5. The Taft Compressor Station will consist of two Solar Centaur 50 6,387-hp units and the Sinton Compressor Station will consist of two Solar Titan 130 20,387-hp units.

Cheniere expects Corpus Christi Liquefaction to begin operations in 2018-19.

BG's Queensland Curtis LNG second train on track

BG Group's Queensland Curtis LNG (QCLNG) project is on schedule to bring its second train on stream during third-quarter 2015.

The announcement follows on the heels of the first shipment of LNG from Train 1 loaded onto the Methane Rita Andrew carrier on Dec. 28 (OGJ Online, Dec. 29, 2014). The second cargo will be loaded onto the Methane Mickie Harper carrier during the first week of January 2015.

QCLNG is the world's first LNG project to be fed by coal seam gas, and first shipments have come after 4 years of development work in the fields in the Surat-Bowen basins and construction at the LNG plant site on Curtis Island near Gladstone.

QCLNG expect plateau production from the two trains to occur in 2016 with an output of 8 million tonnes/year of LNG. The gas supply will come from more than 2,000 wells spread across 4,500 sq km and flowing through 540 km of gathering and trunk pipelines to the Curtis Island facility.

Water produced from the wells will be processed at two treatment plants providing supplies for use by local landholders, industry and communities in the interior Queensland region. Overall, Curtis Island is host to three LNG projects with a total of six LNG trains to produce a total of 25 million tpy of LNG when all are completed in 2016.

Golar to convert second LNG carrier to FLNGV

Golar LNG Ltd. will convert the 125,000-cu m LNG carrier Golar Gimi to a floating liquefaction vessel (FLNGV). Singapore's Keppel Shipyard Ltd. will perform the conversion, with Black & Veatch subcontracted to provide its licensed Prico technology, perform detailed engineering and process design, specify and procure topside equipment, and provide commissioning support for the FLNGV topsides and liquefaction process. Golar in July 2014 completed similar agreements for conversion of the Golar Hilli.

Long-lead orders for primary equipment including gas turbines and cold boxes also were released. Golar expects to deliver Gimi to Keppel as early as next quarter and conversion to be completed and delivered in roughly 33 months. Golar can opt out of the conversion contract before November.

Golar described the Gimi FLNGV conversion along with the Hilli conversion agreement and a December heads of agreement to station that vessel as a component of a floating LNG (FLNG) export project in Cameroon as part of its plans to become the leading integrated midstream LNG services provider.

The Cameroon HOA with Societe Nationale de Hydrocarbures and Perenco Cameroon covers development of an FLNG project 20 km off the coast premised on allocating 500 bcf of natural gas reserves from the fields offshore Kribi, Cameroon, exported via Hilli FLNGV. Golar will provide the liquefaction equipment and services under a tolling agreement to SNH and Perenco as owners of the upstream joint venture, also intended to produce LPG for the local market.

Perenco delivers current gas production in the area to an onshore processing plant at Kribi for shipment by SNH to a 216-Mw power plant. Golar expects the reserves to produce at 1.2 million tonnes/year of LNG for about 8 years and that definitive commercial deals will be reached in the first half to hit a first-production target of first-half 2017.