January 2018
News & Resources

World of Oil & Gas

Alongside its partners, Petoro (30%) and Spirit Energy (20%), Wintershall (50%) announced the start of production at Maria field.
Emily Querubin / World Oil


Wintershall reports early start-up at Maria field, offshore Norway

Alongside its partners, Petoro (30%) and Spirit Energy (20%), Wintershall (50%) announced the start of production at Maria field. According to the company, the project’s start-up was not anticipated until fourth-quarter 2018. In addition to being ahead of schedule, the project reportedly was more than NOK 3 billion under budget. Consequently, “The experience gained in the Maria project will serve as a blueprint for our Nova development, previously known as Skarfjell, and worldwide,” said Martin Bachmann, executive board member for E&P in Europe and the Middle East at Wintershall. The subsea field, which is situated in the Norwegian North Sea’s Haltenbanken area, is tied back to Statoil’s Kristin, Heidrun and Åsgard B production platforms. With this infrastructure, Maria is expected to produce for about 25 years. Its recoverable reserves are estimated at approximately 180 MMboe. 

Pipeline shutdown impedes output for North Sea producers

An unplanned shutdown of the Forties Pipeline System last month threw oil and gas markets into a tailspin. What was described as a “hairline crack” was discovered in the pipeline, which serves as a vital conduit for European crude. It reportedly transports oil from more than 80 fields, which make up approximately 30% of the UK’s oil supply. “A shutdown of the Forties Pipeline System, even temporarily, will have wide-reaching implications for the UK oil and gas industry,” Fiona Legate, senior analyst for North Sea upstream, told Bloomberg. Ineos confirmed by the end of the month, however, that restrictions had been lifted, and the pipeline system was fully operational. Beyond the unexpected closure, Brent crude continued to climb in London, reaching a two-year high for the new year.

Reggane Nord consortium announces first gas in southwestern Algeria 

The Reggane Nord project—situated in the Reggane basin, a very prospective region of the Algerian Sahara desert—produced first gas last month. DEA, which holds a 19.5% stake in the Groupement Reggane Nord (GRN) consortium, reported that production from four of the six gas fields had begun on Dec. 13. A total of ten wells reportedly was brought onstream in the days following.The project’s six dry gas fields include Reggane, Azrafil Sud-Est, Kahlouche, Kahlouche Sud, Tiouliline and Sali. According to the company, the boost in output is expected to achieve a flowrate of more than 280 MMcfd, and production is anticipated to span a total of about 25 years. Thomas Rappuhn, CEO of DEA Deutsche Erdoel AG, said, “Reggane Nord is the first gas project that has been brought into production from this prospective region in the southwest of Algeria. The oil and gas sector is the backbone of the Algerian economy and the gas from Reggane will contribute significantly to the development of the country’s energy sector.” DEA’s project partners include Sonatrach (40%), Repsol (operator, 29.25%) and Edison (11.25%).

Giant Zohr field begins producing in the Mediterranean Sea

Eni announced the start of production from Zohr field in mid-December. The field is situated more than 118 mi north of Port Said, Egypt, in the Shorouk Block. It is said to hold resources of about 30 Tcf of gas-in-place (5.5 Bboe). The field was brought onstream just two-and-a-half years after its discovery. This is record time for a field of this size, according to Eni, which holds a 60% stake in the Shorouk Block. The company’s partners include Rosneft (30%) and BP (10%). Production from Zohr reportedly could help Egypt reach its goal of becoming a net exporter by 2019. Additionally, it is expected to ease the country’s budget problem and reduce imports. To learn more, please see this month’s Eastern Mediterranean Regional Report, pg. 50. 


Industry applauds repeal of BLM rule regulating fracing on federal lands

Last month, the Department of the Interior said it would repeal a federal rule on hydraulic fracturing that had been implemented by the Obama administration. The 2015 Bureau of Land Management (BLM) rule applied costly regulations to fracing activities on federal lands—regulations that API says stunted economic growth and job opportunity. IPAA President and CEO Barry Russell said, “[We’ve] fought for independent oil and natural gas producers against an Obama-era federal rule that was overly restrictive and did not make hydraulic fracturing any safer than current state laws. The rescinding of this burdensome rule, which was never enacted, due to IPAA and Western Energy Alliance’s ongoing legal challenge, will save our member companies and those operating on federal lands hundreds of millions of dollars in compliance costs...” API Upstream and Industry Operations Group Director Erik Milito also commented, “[This] means that the BLM can work with the states and tribal governments—not against them—to encourage responsible investment on federal lands, create jobs, and promote America’s energy security.” He continued, “If the rule were allowed to continue, development in several states, such as New Mexico, Colorado, and Wyoming, could have been especially hard hit with slowed permitting and limited access to public lands, stunting economic growth and pushing away jobs.”

Trump administration proposes greater offshore activity, reduces regulatory burden

Just one week after amending several offshore drilling rules set forth by the Obama administration, President Trump proposed that nearly all U.S. coastal regions be opened for drilling. BSEE says that the proposed regulatory amendments could reduce industry compliance costs by an estimated $228 million over the next 10 years, and the proposal to open parts of the U.S. outer continental shelf would help expand domestic energy development beyond the Gulf of Mexico. Accordingly, the U.S. will be able to better position itself to meet rising demand, domestically, as well as globally. A recent study cited by API revealed that the U.S. oil and gas industry supported 10.3 million jobs in 2015, and added $1.3 trillion to the country’s economy. “This new offshore leasing plan is an important step towards harnessing our nation’s energy potential for the benefit of American energy consumers,” said API Upstream Director Erik Milito. “The ability to safely and responsibly access and explore our resources in the Arctic, Atlantic, Pacific and the Eastern Gulf of Mexico is a critical part of advancing the long-term energy security of the U.S. It will also encourage economic growth, spur manufacturing and investment, create thousands of additional U.S. jobs, and strengthen our national security.” 


Aker BP submits PDOs for three projects in the North Sea

Aker BP has submitted Plans for Development and Operation (PDO) for three North Sea projects—Skogul, Ærfugl and the western flank of Valhall. Skogul, which previously was known as Storklakken, reportedly will be developed with a two-branch well. According to Aker BP, it will be connected to the pipeline from Vilje to Alvheim field. The company has reported an investment estimate of NOK 1.5 billion for the development of Skogul, which is one of the smallest fields on the Norwegian shelf with about 9.4 MMbbl. Ærfugl, found west of Skarv field, contains an estimated  35 Bscm of gas reserves. Its plan for development is made up of two phases. Phase one, which is expected to begin in 2020, will involve the southern part of the Snadd deposit. Phase two, which is expected to begin in 2023, will involve the northern part, as well as Snadd Outer. According to Aker BP, both phases will be developed with three independent satellite wells. It is anticipated that they will be tied-in to the Skarv FPSO. Total investment is estimated at about NOK 8.5 billion. Development of the Valhall western flank will incorporate an unmanned wellhead platform that the company says will be controlled from the field center at Valhall field (pictured), situated more than 186 mi. from Stavanger. Twelve well slots are planned for the new facility. With an anticipated six new wells to be drilled, the remaining slots will be used for future wells. Its development is expected to increase reserves by up to 60 MMbbl. Aker BP has estimated upwards of NOK 5.5 billion of investment for the project. 

SDX Energy strikes gas in Morocco’s Hoot formation

SDX Energy said that its KSR-16 development well, situated on the Sebou permit in Morocco, has encountered gas pay. After drilling to a TD of approximately 6,220 ft, the well reportedly encountered 46.5 ft of net conventional natural gas pay in the Hoot formation. Once it is connected to existing infrastructure, the company says flow testing will begin shortly thereafter. The drilling rig was subsequently moved to the ELQ-1 prospect, situated on the Gharb Centre permit. Drilled to a TD of nearly 4,869 ft, the well reportedly encountered about 74 ft of reservoir interval and about 6.5 ft of net conventional gas pay. Because it was deemed commercially insufficient, the well will be plugged and abandoned. The company says the drilling rig will then move on to the ONZ-7 development well. The wells being drilled are part of a nine-well drilling program on the Sebou, Gharb Centre and Lalla Mimouna permits. SDX President and CEO Paul Welch said, “We are now very confident in delivering upon our planned natural gas sales rates of 10-11 MMscfd in 2018.”

Faroe Petroleum submits PDO for Fenja field, in the Norwegian Sea

Faroe Petroleum announced that a PDO has been submitted for Fenja field, previously known as Pil. The field, situated about 20 mi southwest of Statoil’s Njord field, contains an estimated 100 MMboe of gross recoverable resources. Its development reportedly will consist of three horizontal production wells—two water injectors and one gas injector. They will be tied back to the Njord A (pictured) floating production facility for processing and export. According to Faroe, investment for the project is estimated at NOK 10.2 billion. Start-up is planned for 2021, with an expected field life of about 16 years. Faroe Petroleum CEO Graham Stewart commented, “I am very pleased to announce that the development plan for the Fenja field has now been submitted. When Fenja comes onstream, it will provide significant additional volumes across the Njord host facility (Faroe 7.5%, and currently undergoing refurbishment), and contribute considerable cash flow to Faroe. Fenja is another outstanding example of the exploration success and subsequent monetization Faroe has delivered in Norway.” 


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Emily Querubin
World Oil
Emily Querubin Emily.Querubin@worldoil.com
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