OGJ Newsletter

April 30, 2018
International news for oil and gas professionals


Halliburton writes off Venezuelan investment

In another sign of deterioration of Venezuela’s oil and natural gas industry, Halliburton Co. is writing down its remaining investment in the economically distressed member of the Organization of Petroleum Exporting Countries.

The country’s production, according to the US Energy Information Administration’s April Short Term Energy Outlook, averaged 1.5 million b/d in March, 24% down from a year earlier. EIA cited “economic and political instability.”

The March output level is nearly 500,000 b/d below Venezuela’s implied quota under OPEC’s supply-management agreement in effect since the beginning of last year.

Halliburton said it based its decision to take a charge against first-quarter earnings of $312 million net of tax on “recent changes in the foreign currency exchange system in Venezuela and continued devaluation of the local currency, combined with US sanctions and ongoing political and economic challenges.” The charge included $151 million of receivables, $53 million of fixed assets, $48 million of inventory, $13 million of other assets, and $47 million of accrued taxes.

Halliburton said it is “maintaining its presence in Venezuela and is carefully managing its go-forward exposure.”

Service companies have been trimming their operations in Venezuela for several years because of payment problems (OGJ Online, Apr. 13, 2016).

US petroleum demand for March highest since 2007

US petroleum demand reached 20.6 million b/d in March—the highest level since 2007, according to the latest monthly statistics of the American Petroleum Institute. To satisfy demand, US refineries utilized 91.5% of their capacity—a record for the month of March—and processed 17 million b/d of oil and natural gas liquids. The US also produced a record 10.4 million b/d of crude oil plus another 3.9 million b/d of NGLs.

“As the US’s leading position in oil and natural gas markets advanced in March, consumers continue to enjoy affordable prices at the pump,” said API Chief Economist Dean Foreman. “Economic strength at home and abroad has spurred a virtuous cycle of US oil demand, production, and exports that in turn have helped to reinforce prices and motivate even greater infrastructure investment and US drilling activity. The proverbial April surprise was that the US drilling rig count eclipsed 1,000 for the first time since April 2015 and positioned the US for further supply growth.”

The US petroleum trade balance narrowed in March as the global thirst for US crude oil and major refined product exports rose to 6.8 million b/d, which also was a record for the month and an increase of 1 million b/d from March 2017. With strong demand and exports, US inventories fell in March by 4.9% year-over-year but rose compared with February. Within the total, inventories of crude oil and “other oils” increased between February and March, which is partly why domestic oil prices traded at a greater discount to international ones and NGL prices have fallen.

In addition, US exported 6.8 million b/d of oil and refined product, increased 8% from February and 16.2% compared with March 2017. Crude oil exports of 1.6 million b/d in March continued to rise and more than double those of March 2017.

Vermilion Energy to acquire Spartan Energy

Vermilion Energy Inc. has agreed to acquire Spartan Energy Corp., which produces oil and natural gas in southeastern Saskatchewan, in a stock deal worth $1.4 billion (Can.). Both companies are based in Calgary.

Vermilion will acquire all Spartan shares through an exchange of its shares worth $1.23 billion and assumption of $175 million in debt.

Spartan produces about 23,000 boe/d of light oil and gas, 91% oil. Its production is from 480,000 net acres, with average working interest of 80%, including 400,000 net acres with multizone potential.

Spartan also holds 80,000 net acres in other areas of Saskatchewan, Alberta, and Manitoba. Reserves are 73 million boe (92% crude oil and natural gas liquids) proved and 113.5 million boe (92% crude and NGL) proved plus probable.

Vermilion said it has identified more than 1,000 development locations amenable to open-hole completions not requiring hydraulic fracturing. It also has identified locations in the Mississippian Midale play, which requires hydraulic fracturing as well as waterflood opportunities in Midale and Mississippian Ratcliffe zones.

Moitra named ONGC director (onshore)

Sanjay Kumar Moitra has been named director (onshore) of state-owned Oil & Natural Gas Corp. of India.

He has been head of ONGC’s Bassein and satellite operations off western India since 1983. A mechanical engineer, he joined ONGC in 1982.

Exploration & DevelopmentQuick Takes

Frontera confirms oil, gas for Georgia’s Block 12

Frontera Resources Corp. has confirmed the presence of 78.8 m of combined pay interval in three target zones with the Dino-2 well, the second of a three-well campaign, at the company’s Taribani complex on the Block 12 license in Georgia.

The Dino-2 well has been sidetracked from an existing wellbore and drilled to a vertical depth of 2,700 m into the Late Sarmatian Eldari formation. The pay intervals were in Zones 9, 14, and 15. Cement bond logging indicated a consistent bond across all zones of interest, allowing for effective containment and fracture stimulation. Current bottom hole pressures at Dino-2 are between 6,800-7,200 psi, Frontera said.

The company also confirmed several oil and gas shows during drilling operations. Formation gas flowed with a mud weight reduction drilling through 2,445-2,460 m in Zone 12, which also showed oil at surface. Zone 13 flowed gas while drilling through 2,520-2,540 m, and the company recorded increased connection and formation gas drilling through Zone 14 from 2,570 m to 2,600 m.

The rig will be moved to the T-39 well location for sidetracking operations once released from the Dino-2 location. Frontera Resources first opened its Kura basin operations in Block 12 more than a decade ago (OGJ Online, Nov. 26, 2007).

BLM to prepare EIS for ANWR oil, gas leasing

The US Bureau of Land Management reported it will begin a 60-day public scoping period to assist in preparing an environmental impact statement for oil and gas leasing on the Arctic National Wildlife Refuge’s coastal plain.

“Developing our resources there is an important facet for meeting our nation’s energy demands and achieving energy dominance,” Assistant Interior Sec. for Land and Minerals Management Joe Balash said.

Members of Alaska’s congressional delegation—Senate Energy and Natural Resources Committee Chair Lisa Murkowski, Sen. Dan Sullivan, and Rep. Don Young—issued a joint statement supporting the action. All are Republicans.

BLM said the public scoping process is designed to help identify relevant issues that will influence the EIS’s scope and guide its development. Public comments on scoping issues for the proposed EIS will be accepted through June 19, BLM said.

BP, RIL sanction KG D6 gas development

BP PLC and Reliance Industries Ltd. have sanctioned the second of three integrated deepwater gas developments on Block KG D6 off eastern India.

Called the Satellite Cluster, the project will develop four dry-gas discoveries with five wells completed subsea in 1,700 m of water. The discoveries are as far as 15 km east and southeast of the producing D1D3 fields on the block.

The companies have begun work on the first development, called R Cluster, involving six subsea wells tied back to the KG D6 control and riser platform (OGJ Online, Nov. 1, 2017).

Production from all three development projects is to reach 1 bcfd of gas during 2020-22. RIL operates the block with 60% interest. BP holds 30%, and Niko Resources Ltd. holds 10%.

Contango updates southern Delaware basin work

Contango Oil & Gas Co. expects to complete two wells in June from a common pad in its Delaware basin acreage in Pecos County, Tex. The Sidewinder No. 1H well, spud in March, was drilled to a total measured depth of 20,550 ft into the Wolfcamp A horizon just south of the operator’s Rude Ram No. 1H, which has produced 155,000 boe in 9 months.

The second well—Gunner No. 3H—was spud on Apr. 4 and is at 4,700 ft, Contango said.

This Wolfcamp B test will be completed with a 10,000-ft lateral in the same unit as the Gunner No. 2H, which Contango said is the company’s best producing well to date totaling 130,000 boe in 6 months.

Drilling & ProductionQuick Takes

Shell makes FID on Vito development in gulf

Shell Offshore Inc. will construct and fabricate a simplified host design and subsea infrastructure for Vito, a deepwater development covering four blocks in the Mississippi Canyon area of the Gulf of Mexico. The development will consist of eight subsea wells with deep (18,000 ft) in-well gas lift and is expected to begin production in 2021.

The company said the final investment decision was made with a forward-looking, break-even price estimated to be less than $35/bbl.

Vito, which lies in more than 4,000 ft of water about 150 miles southeast of New Orleans, is expected to reach peak production of 100,000 boe/d. The development currently has an estimated recoverable resource of 300 million boe, the company said.

In 2015, Shell began to redesign the Vito project, reducing cost estimates by more than 70% by simplifying the design and working with vendors in well design and completions, subsea, contracting, and topsides design (OGJ Online, Nov. 30, 2016).

Shell owns and operates the Vito development with a 63.11% interest. Statoil USA E&P Inc. holds 36.89%.

Grieve field starts EOR flood

Elk Petroleum Ltd. said enhanced oil recovery flooding has started at Grieve field’s carbon dioxide EOR project near Casper, Wyo. Initially water is being produced, which will be followed by oil production that is anticipated to ramp up to about 2,100 b/d by Dec. 31.

Third-party engineers suggest gross oil production could peak at more than 3,400 b/d within 13 months, Elk said.

Based in Sydney, Elk said its joint venture partner, Denbury Resources of Plano, Tex., constructed the EOR infrastructure. Elk has a 49% non-operated working interest in Grieve while Denbury holds 51% operated interest.

Grieve begun producing oil in the 1950s but its production had dropped, making it an EOR candidate. Grieve has not produced oil since July 2012, Wyoming Oil & Gas Conservation Commission statistics showed.

Mobil Producing Nigeria lets pipeline contract

Mobil Producing Nigeria Unlimited let a contract to Subsea 7 for production uplift pipeline projects in shallow water offshore Nigeria. The contract includes engineering, construction, transportation, installation, and precommissioning of 24-in. corrosion resistant alloy (CRA) pipeline between the Idoho platform and an onshore terminal.

The contract also includes 2 km of 24-in. CRA pipeline between the Edop and Idoho platforms along with topside modifications and tie-ins.

The offshore work is expected to start during the third quarter through early 2019 using Subsea 7’s Seven Antares vessel.

Norway’s liquids production declined in March

Norway’s preliminary production for March averaged 1.9 million b/d of oil, natural gas liquids, and condensate, marking a decrease of 46,000 b/d compared with February. Norwegian officials blamed the lower March production on technical problems on some fields.

Average liquids production in March was a rounded 1.52 million b/d of oil, 352,000 b/d of NGL, and 29,000 b/d of condensate, the Norwegian Petroleum Directorate (NPD) said.

March oil production was 5% lower than NPD’s forecast. Production for the year is about 3% below NPD’s forecast so far.

NPD provided few other specifics on the technical problems. Previously, NPD has said Norway’s production is expected to decline until 2020 when Johan Sverdrup oil field is scheduled to come on stream. It is anticipated to produce as much as 660,000 b/d by 2022 (OGJ, Mar. 5, 2018, p. 48).


Inter Pipeline lets contract for Canadian PDH-PP unit

Inter Pipeline Ltd., Calgary, has let a contract to W.R. Grace & Co. to provide polypropylene (PP) technology and associated polyolefin catalyst supply for a PP unit to be built at its proposed $3.5-billion (Can.) Heartland Petrochemical Complex in in Strathcona County, Alta. (OGJ Online, Dec. 20, 2017).

Grace will deliver its proprietary Unipol PP process technology and nonphthalate CONSISTA catalyst for the new plant, which will process propylene feedstock into PP beginning in late 2021, the service provider said.

Approved for construction in December 2017, the HPC will be built near Inter Pipeline’s Redwater Olefinic Fractionator (ROF)—which has a capacity to fractionate about 40,000 b/d of ethane-plus mixture—and will include an integrated propane dehydrogenation (PDH) and PP plant designed to convert 22,000 b/d of propane feedstock from ROF and several other third-party fractionators in the region into 525,000 tonnes/year of polymer-grade PP.

Shymkent refinery slated for modernization

PetroKazakhstan Oil Products LLP (PKOP), a joint venture of state-owned KazMunaiGas and China National Petroleum Corp., has undertaken a scheduled shutdown of its 5.25 million-tonne/year Shymkent refinery in Kazakhstan to execute works related to the ongoing modernization of the manufacturing site (OGJ Online, Jan. 31, 2014).

Initiated on Apr. 10, the turnaround will include preventative maintenance projects to ensure continued reliability of existing equipment as well as works aimed at implementation of new installations at the refinery’s new residual fluid catalytic cracking (RFCC) complex, PKOP said.

Upgrades and installations to be implemented during the turnaround come as part of the second phase of PKOP’s modernization program at Shymkent, which alongside construction of the RFCC complex, aims to increase the refinery’s crude processing capacity to 6 million tpy (OGJ Online, Sept. 27, 2012).

PKOP wrapped Phase 1 of Shymkent’s modernization in 2017 with commissioning of a new 600,000-tpy naphtha isomerization unit to enable production of Euro 4 and Euro 5-quality fuels and reduce environmental impacts by enhancing the high-octane gasoline production process to meet the latest requirements set by Kazakhstan law (OGJ Online, July 3, 2017).

Phase 1 projects also included reconstruction of the refinery’s existing diesel hydrotreater as well as construction of a sulfur treatment plant.

Phase 2 of the refinery modernization is scheduled to be completed during third-quarter 2018, PKOP said.

Initiated in 2014, the refinery modernization comes as part of Kazakstan’s plan to increase production of light, high-quality fuels to meet increased domestic demand and help reduce the country’s dependence on foreign fuel imports.

Operators start up Kandym gas processing complex

Russia’s privately held PJSC Lukoil and Uzbekistan’s National Holding Co. Uzbekneftegaz have commissioned their jointly owned Kandym gas processing complex in southwestern Uzbekistan’s province of Bukhara, about 520 km southwest of Tashkent (OGJ Online, Apr. 19, 2016).

Designed to convert sour natural gas from the Kandym development’s six gas condensate Kandym, Kuvachi-Alat, Akkum, Parsanal, Khoji, and West Khoji fields to marketable gas, stable gas condensate, and marketable sulfur, the newly commissioned 8.1 million-cu m/year was completed exactly 2 years from start of construction and 8 months ahead of schedule, Lukoil and Uzbekneftegaz said in separate releases on Apr. 19.

Alongside the two-trained gas processing plant, the complex includes a gas gathering system and commodity export terminals. The project also includes about 500 km of process and in-field pipelines, more than 280 km of roads, 272 km of overhead electric lines, 50 km of access railroad, and water pipelines.

With 77 wells currently drilled, the complex eventually will process gas feedstock from 114 producing wells combined from two collecting points within the six-field Kandym cluster, Lukoil and Uzbekneftegaz said (OGJ Online, Feb. 24, 2017).

Total investment in the Kandym project exceeded $6 billion, Uzbekneftegaz said.

In a separate release on Apr. 19, Lukoil said it raised a 10-year, $660-million loan from ING Bank, UniCredit Bank, and Deutsche Bank to finance part of incurred construction costs for the Kandym gas plant.

Lukoil holds 90% interest in the Kandym project and Uzbekneftegaz holds 10% interest.


West Texas-Gulf Coast crude line proceeds

Phillips 66 Partners will build the Gray Oak Pipeline to carry crude oil from the Permian basin to the Texas Gulf Coast and hold a second open season to gauge interest in a system expansion (OGJ Online, Dec. 13, 2017).

The pipeline will be owned by Gray Oak Pipeline LLC, a joint venture of Phillips 66 Partners, 75%, and Andeavor, 25%. Third parties, including Enbridge Inc., have an option to acquire up to 32.75% of the joint venture from the Phillips 66 Partners interest.

The first phase is due in service by the end of 2019 with a capacity of 385,000 b/d.

The ultimate capacity and scope of the system will depend on results of the second open season enabling additional shippers to enter agreements for long-term service.

Phillips 66 Partners said the new open season might lead to capacity expansion to 700,000 b/d. If that capacity is fully subscribed, it said, capacity ultimately might reach 1 million b/d.

Origination stations will be in Reeves, Loving, Winkler, and Crane counties in West Texas. The system also will receive crude oil from the Eagle Ford play in South Texas.

It will deliver oil to Corpus Christi, Freeport, and Houston.

At Corpus Christi, the pipeline will connect to a new terminal under construction by Buckeye Partners LP. Terminal ownership will be Buckeye, 50%, and Phillips 66 Partners and Andeavor, 25% each.

Scheduled to begin operations by the end of 2019, the terminal will have initial storage capacity of 3.4 million bbl.

AOPL-API: Pipeline incidents down in last 5 years

Liquid pipeline incidents affecting the public or the environment have fallen 19% in the last 5 years, the Association of Oil Pipelines and American Petroleum Institute jointly said in their 2018 Pipeline Safety Excellence Report.

“Pipeline operators are working hard to improve their pipeline safety performance, and this data shows that,” AOPL Pres. Andrew J. Black said in Washington on Apr. 24 as the latest report was released.

“Today’s report furthers the pipeline industry’s top priority of safety—especially in operator commitment to implementing pipeline safety management systems,” API Pipeline Manager David Murk said in St. Louis. “As the demand for liquid energy grows, our industry will continue its efforts to promote safety in all its operations to further protect our employees, communities and the environment.”

The report, which is based on publicly available data collected by the US Pipeline & Hazardous Materials Safety Administration as part of its federal regulation of pipeline operators, also said:

• Incidents caused by corrosion, cracking, or weld failures declined 35% from 2013 to 2017.

• Incident caused by operations or maintenance failures fell 24% during the same period.

The report also lists four goals to improve US pipeline safety:

• Promote operational excellence.

• Improve safety through technology and innovation.

• Enhance emergency response preparedness.

• Increase stakeholder awareness and involvement.

FERC begins inquiry into gas line review process

The US Federal Energy Regulatory Commission began the first examination of its process for reviewing and authorizing interstate natural gas pipelines under Section 7 of the Natural Gas Act since it was adopted in September 1999.

It made the move in response to changes in the gas industry and increased stakeholder interest in how it reviews gas pipeline proposals since FERC adopted its current pipeline certification policy, the commission said.

The notice of inquiry poses a range of questions that reflect concerns that were raised in numerous public comments, court proceedings, and other forums, FERC said. “The commission also is seeking feedback on the transparency, timing, and predictability of its certification process,” it said. “FERC is encouraging commenters to specifically identify any perceived issues with the current analytical and procedural approaches, and to provide detailed recommendations to address these issues.”

Comments will be accepted for 60 days following the notice’s publication in the Federal Register in the next few days, FERC said.

Responding to FERC’s announcement, Interstate Natural Gas Association of America Pres. Donald F. Santa said, “It is understandable that FERC wishes to take a fresh look at its 1999 certificate policy statement. Natural gas now plays a more prominent role in our energy economy and the public policy landscape surrounding energy and the environment has evolved considerably over the intervening years.”